20190926PAC to Staff Attach 14.pdf

PACIFICORP

Idaho

2009 Analysis of System Losses

November 2011

Prepared by:

Management Applications Consulting, Inc.
1103 Rocky Drive – Suite 201
Reading, PA 19609
Phone: [phone] / Fax: [phone]
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MANAGEMENT APPLICATIONS CONSULTING, INC.

1103 Rocky Drive • Suite 201 • Reading, PA 19609-1157 • 610/670-9199 • fax [phone] •www.manapp.com

November 15, 2011

Mr. Kenneth Houston, PE
Vice President, Transmission Services
PacifiCorp
825 NE Multnomah, Suite 1600
Portland, OR 97232

RE: 2009 LOSS ANALYSES – Idaho

Dear Mr. Houston:

Transmitted herewith are the results of the 2009 Analysis of System Losses for the Idaho
operations. These results consist of an Annual analysis which develops cumulative expansion
factors (loss factors) for both demand (peak-kW) and energy (average-kWh) losses by discrete
voltage levels applicable to metered sales data. The loss calculations were made using a
preliminary system wide transmission loss factor which was then incorporated into the Idaho loss
model to derive the final results prescribed herein. Our analyses considered only technical losses
in arriving at our final recommendations.

On behalf of MAC, we appreciate the opportunity to assist you in performing the loss analysis
contained herein. The level of detail, multiple databases, and state jurisdictions coupled with
power flow studies and updates are consistent with prior loss studies and reflect reasonable and
representative power losses on the PacifiCorp system. Our review of these data and calculated
loss results support the proposed loss factors as presented herein for your use in various cost of
service, rate studies, and demand analyses.

Should you require any additional information, please let us know at your earliest convenience.

Sincerely,
Paul M. Normand
Principal
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PACIFICORP - IDAHO

2009 ANALYSIS OF SYSTEM LOSSES

TABLE OF CONTENTS

1.0 EXECUTIVE SUMMARY ................................................................................................ 1 
2.0 INTRODUCTION .............................................................................................................. 6 
2.1 Conduct of Study ............................................................................................................ 6 
2.2 Description of Model ...................................................................................................... 7 
2.2 Description of Model ...................................................................................................... 8 
3.0 METHODOLOGY ............................................................................................................. 9 
3.1 Background ..................................................................................................................... 9 
3.2 Analysis and Calculations ............................................................................................. 11 
3.2.1 Bulk, Transmission and Subtransmission Lines ....................................................... 11 
3.2.2 Transformers ............................................................................................................. 11 
3.2.3 Distribution System .................................................................................................. 11 
4.0 DISCUSSION OF RESULTS........................................................................................... 13 

Appendix A – PacifiCorp System Wide Transmission Loss Factor (Preliminary)

Appendix B – Results of PacifiCorp Idaho 2009 Loss Analysis

Appendix C – Discussion of Hoebel Coefficient

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Idaho 2009 Analysis of System Losses

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1.0 EXECUTIVE SUMMARY

This report presents PacifiCorp’s 2009 Analysis of System Losses for Idaho’s power systems as
performed by Management Applications Consulting, Inc. (MAC). Our analyses considered only
technical losses and did not attempt to quantify non-technical factors such as theft and meter
accuracy. The study developed separate demand (kW) and energy (kWh) loss factors for each
voltage level of service in the power system. The cumulative loss factor results by voltage level,
as presented herein, can be used to adjust metered sales data in Idaho for losses in performing
cost of service studies, determining voltage discounts, and other analyses which may require a
loss adjustment.

The procedures used in the overall loss study were consistent with prior studies and emphasized
the use of "in house" resources where possible. To this end, extensive use was made of the
Company's peak hour power flow studies and transformer plant investments in the model. Using
estimated load data provided a means of calculating reasonable estimates of losses by using a
"top-down" and "bottom-up" procedure. In the "top-down" approach, losses from the high
voltage system, through and including distribution substations, were calculated along with power
flow data, conductor and transformer loss estimates, and metered sales.

At this point in the analysis, system loads and losses at the input into the distribution substation
system are known with reasonable accuracy. However, it is the remaining loads and losses on
the distribution substations, primary system, secondary circuits, and services which are generally
difficult to estimate. Estimated load data provided the starting point for performing a "bottom-
up" approach for calculating the remaining distribution losses. Basically, this "bottom-up"
approach develops line loadings by first determining loads and losses at each level beginning at a
customer's meter service entrance and then going through secondary lines, line transformers,
primary lines and finally distribution substation. These distribution system loads and associated
losses are then compared to the initial calculated input into Distribution Substation loadings for
reasonableness prior to finalizing the loss factors. An overview of the loss study is shown on
Figure 1 on page 4.

Appendix A identifies the PacifiCorp system-wide Transmission 2009 loss factors for the
integrated PacifiCorp System for 500 kV through 46 kV. These preliminary loss factors will be
finalized and approved as the Company’s FERC OATT rate in 2012.

Appendix B incorporates Appendix A’s loss factor and presents a total PacifiCorp Idaho only
loss calculation and derives specific loss factors by voltage applicable to metered sales. Table 1,
below, provides the final results from Appendix A and B for the calendar year. The distribution
system losses are calculated in Appendix B for all voltage levels except transmission which was
obtained from Appendix A. These loss expansion factors are applicable only to metered sales at
the point of receipt for adjustment to the power system’s input level.
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Idaho 2009 Analysis of System Losses

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TABLE 1
Loss Factors at Sales Level
Idaho

Voltage Level
of Service

2009
Delivery System
(Excludes Transmission)

Demand (kW)

Transmission1 1.04259 1.00000
Primary 1.08559 1.04124
Secondary 1.11867 1.07298
Energy (kWh)
Transmission1 1.04527 1.00000
Primary 1.07448 1.02794
Secondary 1.11466 1.06638

Losses – Net System Input2 7.83% MWh
8.62% MW
Losses – Net System Output3 8.50% MWh
9.44% MW

The loss factors presented in the Delivery Only column of Table 1 are the Total PacifiCorp loss
factors divided by the transmission loss factor in order to remove the transmission losses from
each service level loss factor. For example, the secondary distribution demand loss factor of
1.07298 includes the recovery of all non-transmission losses from distribution substation,
primary lines, line transformers, secondary conductors and services. The additional
transformation loss multipliers are appropriate as an adjustment for either additional
transformation or additional primary loss recovery.

The net system input shown in Table 1 presents percent MWh losses of 7.83% for the total
PacifiCorp load using calculated losses divided by the associated input energy to the system.
The 8.62% represents the MW losses also using system input as a reference. The net system
output reference shown in Table 1 represents MWh losses of 8.50% and MW losses of 9.44%.
These results use the appropriate total losses for each but are divided by system output or sales.
These calculations are all based on the results from Exhibits 1, 7, and 9 of Appendix B.

1 Reflects preliminary loss factors from Appendix A for 500 kV through 46 kV. 2 Net system input equals firm sales plus losses, Company use less non-requirement sales and related losses. See Appendix B,
Exhibit 1, for their calculations. 3 Net system output uses losses divided by output or sales data as a reference.
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Idaho 2009 Analysis of System Losses

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Due to the very nature of losses being primarily a function of equipment loadings, the loss factor
derivations for any voltage level must consider both the load at that level plus the loads from
lower voltages and their associated losses. As a result, cumulative losses on losses equates to
additional load at higher levels along with future changes (+ or –) in loads throughout the power
system. It is therefore important to recognize that losses are multiplicative in nature (future) and
not additive (test year only) for all future years to ensure total recovery based on prospective
fixed loss factors for each service voltage.

The derivation of the cumulative loss factors shown in Table 1 have been detailed for all
electrical facilities in Exhibit 9, page 1 for demand and page 2 for energy. Beginning on line 1
of page 1 (demand) under the secondary column, metered sales are adjusted for service losses on
lines 3 and 4. This new total load (with losses) becomes the load amount for the next higher
facilities of secondary conductors and their loss calculations. This process is repeated for all the
installed facilities until the secondary sales are at the input level (line 45). The final loss factor
for all delivery voltages using this same process is shown on line 46 and Table 1 for demand.
This procedure is repeated in Exhibit 9, page 2, for the energy loss factors.

The loss factor derivation for major voltage categories is simply the input required (line 45)
divided by the metered sales (line 2).

An overview of the loss study is shown on Figure 1 on the next page. Figure 2 simply illustrates
the major components that must be considered in a loss analysis.
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Figure 2
Generic Energy Loss Components
Lo
a
d

D
a
t
a

Metered and/or
Estimated Load Data

Unbilled
Company Use
Lo
s
s
e
s
Transmission
System Wide
Load Losses
Distribution
Delivery
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Idaho 2009 Analysis of System Losses

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2.0 INTRODUCTION

This report of the 2009 Analysis of System Losses for Idaho provides a summary of results,
conceptual background or methodology, description of the analyses, and input information
related to the study.

2.1 Conduct of Study

Typically, between five to ten percent of the total kWh requirements of an electric utility
is lost or unaccounted for in the delivery of power to customers. Investments must be
made in facilities which support the total load which includes losses or unaccounted for
load. Revenue requirements associated with load losses are an important concern to
utilities and regulators in that customers must equitably share in all of these cost
responsibilities. Loss expansion factors are the mechanism by which customers' metered
demand and energy data are mathematically adjusted to the generation or input level
(point of reference) when performing cost and revenue calculations.

An acceptable accounting of losses can be determined for any given time period using
available engineering, system, and customer data along with empirical relationships.
This loss analysis for the delivery of demand and energy utilizes such an approach. A
microcomputer loss model4 is utilized as the vehicle to organize the available data,
develop the relationships, calculate the losses, and provide an efficient and timely avenue
for future updates and sensitivity analyses. Our procedures and calculations are
consistent with prior loss studies and rely on numerous databases that include customer
statistics and power system modeling results.

Company personnel performed most of the data gathering and data processing efforts.
MAC analyzed the Company’s various databases and performed calculations to check the
reasonableness of results. A review of the preliminary results provided for additions to
the database and modifications to certain initial assumptions based on available data.
Efforts in determining the data required to perform the loss analysis centered on
information which was available from existing studies or reports within the Company.
4Copyright by Management Applications Consulting, Inc.

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From an overall perspective, our efforts concentrated on five major areas:

1. System information by state jurisdiction concerning peak demand and metered
annual sales data by voltage level,
2. High voltage power system power flow data and associated loss calculations
(utilized preliminary system wide Transmission Loss Factors),
3. Distribution system primary and secondary loss calculations,
4. Derivation of fixed and variable losses by voltage level, and
5. Development of final cumulative expansion factors at each voltage level for peak
demand (kW) and annual energy (kWh) requirements reconciled to system input.

2.2 Electric Power Losses

Losses in power systems consist of primarily technical losses with a much smaller level
of non-technical losses.

Technical Losses

Electrical losses result from the transmission of energy over various electrical
equipment. The largest component of these losses is power dissipation as a result
of varying loading conditions and are oftentimes called load losses which are
proportional to the square of the current (I2R). These losses can be as high as
75% of all technical losses. The remaining losses are called no-load and represent
essentially fixed (constant) energy losses throughout the year. These no-load
losses represent energy required by a power system to energize various electrical
equipment regardless of their loading levels. The major portion of no-load losses
consists of core or magnetizing energy related to installed transformers
throughout the power system.

Non-Technical Losses

These are unaccounted for energy losses that are related to energy theft, metering,
non-payment by customers, and accounting errors. Losses related to these areas
are generally very small and can be extremely difficult and subjective to quantify.
Our efforts generally do not develop any meaningful level as appropriate because
we assume that improving technology and utility practices have minimized these
amounts.

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2.3 Description of Model

The Loss Model is a customized applications model, constructed using the Excel
software program. Documentation consists primarily of the model equations at each cell
location. A significant advantage of such a model is that the actual formulas and their
corresponding computed values at each cell of the model are immediately available to the
analyst.

A brief description of the two appendices and their major categories of effort for the
preparation of each loss model is as follows:

• Appendix A identifies the preliminary system wide transmission loss factors and
supporting calculations. These transmission loss factors formed the basis and
starting point with which to derive the final delivery loss factors for each
remaining voltage level as presented in Appendix B and summarized on Table 1
of the Executive Summary.

• Appendix B which contains calculations for distribution-related conductors,
transformers, and all primary and secondary losses as summarized in the output
reports.

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3.0 METHODOLOGY

3.1 Background

The objective of a Loss Study is to provide a reasonable set of energy (average) and
demand (peak) loss expansion factors which account for system losses associated with
the transmission and delivery of power to each voltage level over a designated period of
time. The focus of this study is to identify the difference between total energy inputs and
the associated sales with the difference being equitably allocated to all delivery levels.
Several key elements are important in establishing the methodology for calculating and
reporting the Company's losses. These elements are:

• Selection of voltage level of services,

• Recognition of losses associated with conductors, transformations, and
other electrical equipment/components within voltage levels,

• Identification of customers and loads at various voltage levels of service,

• Review of generation or net power supply input at each level for the test
period studied, and

• Analysis of kW and kWh sales by voltage levels within the test period.

The three major areas of data gathering and calculations in the loss analysis were as
follows:

1. System Information (monthly and annual)
• MWH generation and MWH sales.

• Coincident peak estimates and net power supply input from all sources
and voltage levels.

• Customer load data estimates from available load research information,
adjusted MWH sales, and number of customers in the customer groupings
and voltage levels identified in the model.

• System default values, such as power factor, loading factors, and load
factors by voltage level.

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2. High Voltage System (Appendix A)
• Presents the detailed calculations and derivation of the preliminary system
wide transmission loss factors used in the calculations developed in
Appendix B.

3. Distribution System (Appendix B)
 Distribution Substations – data was developed for modeling each
substation as to its size and loading. Loss calculations were performed
from this data to determine load and no load losses separately for each
transformer.

• Primary lines – Line loading and loss characteristics were obtained from
distribution feeder analyses. These loss results developed kW loss per
MW of load by Primary Voltage level. An average was calculated to
derive the primary loss estimate after weighting the proper rural versus
urban customer mix.

• Line transformers – Losses in line transformers were based on each
customer service group's size, as well as the number of customers per
transformer. Accounting and load data provided the foundation with
which to model the transformer loadings and calculate load and no load
losses.

• Secondary network – Typical secondary networks were estimated for
conductor sizes, lengths, loadings, and customer penetration for residential
and small general service customers.

• Services – Typical services were estimated for each secondary service
class of customers identified in the study with respect to type, length, and
loading.

The loss analysis was thus performed by constructing the model in segments and
subsequently calculating the composite until the constraints of peak demand and energy
were met:

• Information as to the physical characteristics and loading of each
transformer and conductor segment was modeled.

• Conductors, transformers, and distribution were grouped by voltage level,
and unadjusted losses were calculated.

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• The loss factors calculated at each voltage level were determined by
"compounding" the per-unit losses. Equivalent sales at the supply point
were obtained by dividing sales at a specific level by the compounded loss
factor to determine losses by voltage level.

• The resulting demand and energy loss expansion factors were then used to
adjust all sales to the generation or input level in order to estimate the
difference.

• Reconciliation of kW and kWh sales by voltage level using the reported
system kW and kWh was accomplished by adjusting the initial loss factor
estimates until the mismatch or difference was eliminated.

3.2 Calculations and Analysis

This section provides a discussion of the input data, assumptions, and calculations
performed in the loss analysis. Specific appendices have been included in order to
provide documentation of the input data utilized in the model.

3.2.1 Bulk, Transmission and Subtransmission Lines

Appendix A provides the summary results of the hourly calculations of segments
of the PacifiCorp power system on an hourly basis.

3.2.2 Transformers

Appendix A provides the summary results of the hourly calculations of segments
of the PacifiCorp power system on an hourly basis.

3.2.3 Distribution System

The load data at the substation and customer level, coupled with primary and
secondary network information, was sufficient to model the distribution system in
adequate detail to calculate losses.

Primary Lines

Estimates were made by the Company of primary line losses by the different
levels of distribution voltage and whether they were urban or rural. These
estimates consider substations, feeders per substation, voltage levels, loadings,
total circuit miles, wire size, and single- to three-phase investment estimates. Our
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recommended loss factors were determined by calculating all other factors, and
the remaining unaccounted for MW and MWH were assigned to primary losses.

Line Transformers

Losses in line transformers were determined based on typical transformer sizes
for each secondary customer service group and an estimated or calculated number
of customers per transformer. Accounting records and estimates of load data
provided the necessary database with which to model the loadings. These
calculations also made it possible to determine separate copper and iron losses
based on a table of representative losses for various transformer sizes.

Secondary Line Circuits

Calculations of secondary line circuit losses were performed for loads served
through these secondary line investments. Estimates of typical conductor sizes,
lengths, loadings and customer class penetrations were made to obtain total circuit
miles and losses for the secondary network. Customer loads which do not have
secondary line requirements were also identified so that a reasonable estimate of
losses and circuit miles of the investments could be made.

Service Drops and Meters

Service drops were estimated for each secondary customer reflecting conductor
size, length and loadings to obtain demand losses. A separate calculation was
also performed using customer maximum demands to obtain kWh losses. Meter
loss estimates were also made for each customer and incorporated into the
calculations of kW and kWh losses included in the Summary Results.
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4.0 DISCUSSION OF RESULTS

A brief description of each Exhibit provided in Appendix B as follows:

Exhibit 1 - Summary of Company Data

This exhibit reflects system information used to determine percent losses and a detailed summary
of kW and kWh losses by voltage level. The loss factors developed in Exhibit 7 are also
summarized by voltage level.

Exhibit 2 - Summary of Conductor Information

A summary of MW and MWH load and no load losses for conductors by voltage levels is
presented. The sum of all calculated losses by voltage level is based on input data information
provided in Appendix A. Percent losses are based on equipment loadings.

Exhibit 3 - Summary of Transformer Information

This exhibit summarizes transformer losses by various types and voltage levels throughout the
system. Load losses reflect the copper portion of transformer losses while iron losses reflect the
no load or constant losses. MWH losses are estimated using a calculated loss factor for copper
and the test year hours times no load losses.

Exhibit 4 - Summary of Losses Diagram (2 Pages)

This loss diagram represents the inputs and output of power at system peak conditions. Page 1
details information from all points of the power system and what is provided to the distribution
system for primary loads. This portion of the summary can be viewed as a "top down" summary
into the distributor system.

Page 2 represents a summary of the development of primary line loads and distribution substa-
tions based on a "bottom up" approach. Basically, loadings are developed from the customer
meter through the Company’s physical investments based on load research and other metered
information by voltage level to arrive at MW and MVA requirements during peak load
conditions by voltage levels.

Exhibit 5 - Summary of Sales and Calculated Losses

Summary of Calculated Losses represents a tabular summary of MW and MWH load and no
load losses by discrete areas of delivery within each voltage level. Losses have been identified
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and are derived based on summaries obtained from Exhibits 2 and 3 and losses associated with
meters, capacitors and regulators.

Exhibit 6 - Development of Loss Factors, Unadjusted

This exhibit calculates demand and energy losses and loss factors by specific voltage levels
based on sales level requirements. The actual results reflect loads by level and summary totals of
losses at that level, or up to that level, based on the results as shown in Exhibit 5. Finally, the es-
timated values at generation are developed and compared to actual generation to obtain any
difference or mismatch.

Exhibit 7 - Development of Loss Factors, Adjusted

The adjusted loss factors are the results of adjusting Exhibit 6 for any difference. All differences
between estimated and actual are prorated to each level based on the ratio of each level's total
load plus losses to the system total as shown on Exhibit 8. These new loss factors reflect an
adjustment in losses due only to kW and kWh mismatch.

Exhibit 8 – Adjusted Losses and Loss Factors by Facility

These calculations present an expanded summary detail of Exhibit 7 for each segment of the
power system with respect to the flow of power and associated losses from the receipt of energy
at the meter to the generation for the Company’s power system.

Exhibit 9 – Appendix B Only – Summary of Losses by Delivery Voltage

These calculations present a reformatted summary of the losses presented in Exhibits 7 and 8 by
power system delivery segment as calculated by voltage level of service based on sales.
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Idaho 2009 Analysis of System Losses

Appendix A

PacifiCorp
System Wide Transmission
Loss Factors (Preliminary)
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Appendix A
Transmission Loss Model
Page 1 of 6PacifiCorp
2009 State Jurisdictional Transmission Loss Analysis With GSU
Pages 1
Schedule 1,
Page 2
Schedule 2,
Page 3
Schedule 3,
Page 4
Schedule 4,
Page 5
Schedule 5,
Page 6
Index
Presents the summary loss results of the calculated hourly losses for the
Company's PACE and PACW control areas at the annual peak hour and for
the annual average losses for all hours of the year.
Calculated loss factors are applicable to the metered (output) sales level.
All data is from Schedule 2.
Summary of the summer and winter peak hour MW and annual MWH losses
for PACE and PACW and the total system.
Results are detailed by segment and season: Summer (June, July, August,
and September), Winter (all months excluding Summer months).
Loss data is from Schedule 3.
Summary of MW and MWH loss results for each control area by season and
voltage level.
Summary of seasonal peak hour MW and average MWH loss results for PACE
by voltage level from Appendices A (winter) and B (summer) hourly loss
calculations.
Summary of seasonal peak hour MW and average MWH loss results for
PACW by voltage level from Appendices C (winter) and D (summer) hourly
loss calculations.
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Appendix A
Transmission Loss Model
Page 2 of 6
PACIFICORP 2009 TRANSMISSION LOSS ANALYSI
PERCENT OF
LOSSES TOTAL INPUT OUTPUT LOSS FACTO
TRANSMISSION (Input/Output)
TRANSMISSION
A. DEMAN Peak (MW) Summe
1 East 325.0 73.4% 7,443 7,118 1.04566
2 West 117.9 26.6% 3,647 3,529 1.03340
3 Total Demand 442.8 100.0% 11,090 10,647 1.04159
4 Unmetered Station Use Adjustment 0.00100
5 Demand Loss Factor 1.04259
B. ENERG nnual MWH
6 East 2,002,285 70.8% 45,369,000 43,366,715 1.04617
7 West 826,451 29.2% 21,361,106 20,534,655 1.04025
8 Total Energy 2,828,736 100.0% 66,730,106 63,901,370 1.04427
9 Unmetered Station Use Adjustment 0.00100
10 Energy Loss Factor 1.04527
NOTES:
(1) Results include Bridger losses from Schedule 4,
(2) Results include Corona loss estimates from Schedule 3.
(3) Loss calculations include adjusted (reduced) for Company ownership.
(4) Loss calculations include GSU and Wind Plant.
(5) Loss calculations excludes third party facilities.
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Appendix A
Transmission Loss Model
Page 3 of 6
PACIFICORP POWER FLOW RESULTS - SUMMARY OF LOSSES
PEAK (SUMMER) PEAK (WINTER)NNUA
Total % of Total % of Total Total % of Total % of Total Total Annua % of Total % of Total
(MW)re System (MW)re System (MWH)re System
EAST
1 Load (Peak MW, Annual MWH)7,443 6,946 45,369,000
Transmission
2 Transformers 25.0 7.7% 5.6%23.9 7.7% 5.4% 145,704 7.3% 5.2%
3 Transmission Lines 300.0 92.3% 67.8%286.7 92.3% 65.0% 1,856,581 92.7% 65.6%
4 Total Transmission 325.0 100.0% 73.4%310.6 100.0% 70.4% 2,002,285 100.0% 70.8%
5 Subtotal - EAST 325.0 100.0% 73.4%310.6 100.0% 70.4% 2,002,285 100.0% 70.8%
6 Losses % of Input (Line 6/Line 1)4.4%4.5%4.4%
7 Losses % of Output (Line 6/(Line 1/Line 6))4.6%4.7%4.6%
WEST
8 Load (Peak MW, Annual MWH)3,647 4,009 21,361,106
Transmission
9 Transformers 11.9 10.1% 2.7%12.5 9.5% 2.8% 98,188 11.9% 3.5%
10 Transmission Lines 106.0 89.9% 23.9%118.3 90.5% 26.8% 728,263 88.1% 25.7%
11 Total Transmission 117.9 100.0% 26.6%130.7 100.0% 29.6% 826,451 100.0% 29.2%
12 Subtotal - WEST 117.9 100.0% 26.6%130.7 100.0% 29.6% 826,451 100.0% 29.2%
14 Losses % of Input (Line 14/Line 9)3.2%3.3%3.9%
15 Losses % of Output (Line 14/(Line 9/Line 14)) 3.3%3.4%4.0%
TOTAL PACIFICORP
16 Load (Peak MW, Annual MWH)11,090 10,955 66,730,106
Transmission
17 Transformers 36.9 8.3%36.3 8.2% 243,893 8.6%
18 Transmission Lines 406.0 91.7%405.0 91.8% 2,584,843 91.4%
19 Total Transmission 442.8 100.0%441.3 100.0% 2,828,736 100.0%
20 Total System 442.8 100.0%441.3 100.0% 2,828,736 100.0%
22 Losses % of Input (Line 22/Line 17)4.0%4.0%4.2%
23 Losses % of Output (Line 22/(Line 17/Line 22)) 4.2%4.2%4.4%
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Appendix A
Transmission Loss Model
Page 4 of 6
PACIFICORP POWER FLOW RESULTS - TOTAL TRANSMISSION
TRANSFORMER LOSSES MW TRANSMISSION LINE LOSSES MW
TIME
MW
INPUT
345 kV to
500 kV (1)
161 kV to
345 kV Includes
Bridger
115 kV to
161 kV
46 kV to
115 kV GSU SVC
Subtotal
Transformers
345 kV to
500 kV (2)
161 kV to
345 kV Includes
Bridger
115 kV to
161 kV
Corona 500 kV to
138 kV
46 kV to
115 kV
Below 46
kV
Subtotal
Transm Lines
Total Transmission
Losses
WINTER - EAST
1 PEAK - MW 6,946 7.160 3.450 0.182 12.569 0.504 23.864 177.157 51.324 9.313 45.029 3.889 286.712 310.5762 LOSS % TO INPUT 0.103% 0.050% 0.003% 0.181% 0.007% 0.344% 2.550% 0.739% 0.134% 0.648% 0.056% 4.128%3 LOSS % TO TOTAL LOSSES 7.684%92.316% 100.000%4
5 WINTER MWH 29,694,446 33,163 9,480 812 53,402 2,612 99,470 753,679 206,587 70,607 136,393 18,450 1,185,716 1,285,186
6 LOSS % TO INPUT 0.112% 0.032% 0.003% 0.180% 0.009% 0.335% 2.538% 0.696% 0.238% 0.459% 0.062% 3.993%
7 LOSS % TO TOTAL LOSSES 7.740%92.260% 100.000%
SUMMER - EAST8 PEAK - MW 7,443 7.211 4.461 0.190 12.566 0.534 24.962 175.235 67.436 9.313 45.430 2.607 300.021 324.982
9 LOSS % TO INPUT 0.097% 0.060% 0.003% 0.169% 0.007% 0.335% 2.354% 0.906% 0.125% 0.610% 0.035% 4.031%
10 LOSS % TO TOTAL LOSSES 7.681%92.319% 100.000%
11
12 SUMMER MWH 15,674,554 16,316 6,444 415 22,316 744 46,234 410,374 146,442 35,449 72,178 6,422 670,864 717,099
13 LOSS % TO INPUT 0.104% 0.041% 0.003% 0.142% 0.005% 0.295% 2.618% 0.934% 0.226% 0.460% 0.041% 4.280%14 LOSS % TO TOTAL LOSSES 6.447%93.553% 100.000%
TOTAL ANNUAL - EAST
15 PEAK - MW 7,443 7.211 4.461 0.190 12.566 0.534 24.962 175.235 67.436 9.313 45.430 2.607 300.021 324.982
16 ANNUAL MWH 45,369,000 49,479 15,924 1,228 75,718 3,356 145,704 1,164,053 353,028 106,055 208,572 24,872 1,856,581 2,002,285
17 LOSS % TO INPUT 0.109% 0.035% 0.003% 0.167% 0.007% 0.321% 2.566% 0.778% 0.234% 0.460% 0.055% 4.092%18 LOSS % TO TOTAL ANNUAL INPUT 7.277%92.723% 100.000%
19 LOSS % TO TOTAL ANNUAL OUTPUT 43,366,71520 (Input - Losses)4.617%
LOSS FACTORS - EAST
21 Demand 1.0456622 Energy 1.04617
WINTER - WEST
23 PEAK - MW 4,009 0.465 6.843 2.042 3.109 12.459 11.433 30.143 4.691 70.768 1.237 118.271 130.730
24 LOSS % TO INPUT 0.012% 0.171% 0.051% 0.078% 0.311% 0.285% 0.752% 0.117% 1.765% 0.031% 2.950%25 LOSS % TO TOTAL 9.530%90.470% 100.000%2627 WINTER MWH 14,464,624 1,165 36,257 11,417 17,590 66,430 64,387 114,122 35,565 279,221 1,616 494,911 561,34128 LOSS % TO INPUT 0.008% 0.251% 0.079% 0.122% 0.459% 0.445% 0.789% 0.246% 1.930% 0.011% 3.422%
29 LOSS % TO TOTAL LOSSES 11.834%88.166% 100.000%
SUMMER - WEST
30 PEAK - MW 3,647 0.390 6.604 1.834 3.065 11.892 10.025 27.421 4.691 62.660 1.161 105.958 117.85131 LOSS % TO INPUT 0.011% 0.181% 0.050% 0.084% 0.326% 0.275% 0.752% 0.129% 1.718% 0.032% 2.906%32 LOSS % TO TOTAL 10.091%89.909% 100.000%
33
34 SUMMER MWH 6,896,481 536 19,636 4,442 7,144 31,759 30,516 51,775 17,856 132,623 581 233,351 265,110
35 LOSS % TO INPUT 0.008% 0.285% 0.064% 0.104% 0.461% 0.442% 0.751% 0.259% 1.923% 0.008% 3.384%
36 LOSS % TO TOTAL LOSSES 11.979%88.021% 100.000%
TOTAL ANNUAL - WEST
37 PEAK - MW 3,647 0.390 6.604 1.834 3.065 11.892 10.025 27.421 4.691 62.660 1.161 105.958 117.851
38 ANNUAL MWH 21,361,106 1,702 55,893 15,859 24,735 98,188 94,903 165,897 53,421 411,844 2,197 728,263 826,451
39 LOSS % TO INPUT 0.008% 0.262% 0.074% 0.116% 0.460% 0.444% 0.777% 0.250% 1.928% 0.010% 3.409%
40 LOSS % TO TOTAL ANNUAL INPUT 11.881%88.119% 100.000%
39 LOSS % TO TOTAL ANNUAL OUTPUT 20,534,65540 (Input - Losses)4.025%
LOSS FACTORS - WEST
41 Demand 1.03340
42 Energy 1.04025
TOTAL ANNUAL - PACIFICORP
43PEAK SUMMER - M 11,090 0.390 13.814 4.461 2.023 15.632 0.534 36.854 10.025 202.657 67.436 14.004 108.091 3.767 405.979 442.833
44 ANNUAL MWH 66,730,106 1,702 105,372 15,924 17,087 100,453 3,356 243,893 94,903 1,329,951 353,028 159,476 620,416 27,069 2,584,843 2,828,736
45 PEAK WINTER MW 10,955 0.465 14.003 3.450 2.224 15.678 0.504 36.323 11.433 207.299 51.324 14.004 115.797 5.125 404.983 441.306
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Appendix A
Transmission Loss Model
Page 5 of 6
PACIFICORP POWER FLOW RESULTS - EAST
TRANSFORMER LOSSES MW TRANSMISSION LINE LOSSES MW
TIME
MW-EAST
INPUT
161 kV to
345 kV
Bridger
345 kV
115 kV to
161 kV
46 kV to
115 kV GSU SVC
Subtotal
Transformers
161 kV to
345 kV
Bridger
345 kV
115 kV to
161 kV
Corona
500 kV to
138 kV
46 kV to
115 kV
Below 46
kV
Subtotal
Transm Lines
Total
Transmission
Losses
WINTER - EAST
1 PEAK - MW 6,946 4.226 2.934 3.450 0.182 12.569 0.504 23.864 118.027 59.130 51.324 9.313 45.029 3.889 286.712 310.576
2 LOSS % TO INPUT 0.061% 0.042% 0.050% 0.003% 0.181% 0.007% 0.344% 1.699% 0.851% 0.739% 0.134% 0.648% 0.056% 4.128%
3 LOSS % TO TOTAL LOSSES 7.684%92.316% 100.000%
4
5 WINTER MWH 29,694,446 15,751 17,413 9,480 812 53,402 2,612 99,470 440,073 313,606 206,587 70,607 136,393 18,450 1,185,716 1,285,186
6 LOSS % TO INPUT 0.053% 0.059% 0.032% 0.003% 0.180% 0.009% 0.335% 1.482% 1.056% 0.696% 0.238% 0.459% 0.062% 3.993%
7 LOSS % TO TOTAL LOSSES 7.740%92.260% 100.000%
SUMMER - EAST
8 PEAK - MW 7,443 4.278 2.933 4.461 0.190 12.566 0.534 24.962 118.015 57.220 67.436 9.313 45.430 2.607 300.021 324.982
9 LOSS % TO INPUT 0.057% 0.039% 0.060% 0.003% 0.169% 0.007% 0.335% 1.586% 0.769% 0.906% 0.125% 0.610% 0.035% 4.031%
10 LOSS % TO TOTAL LOSSES 7.681%92.319% 100.000%
11
12 SUMMER MWH 15,674,554 7,729 8,587 6,444 415 22,316 744 46,234 243,369 167,005 146,442 35,449 72,178 6,422 670,864 717,099
13 LOSS % TO INPUT 0.049% 0.055% 0.041% 0.003% 0.142% 0.005% 0.295% 1.553% 1.065% 0.934% 0.226% 0.460% 0.041% 4.280%
14 LOSS % TO TOTAL LOSSES 6.447%93.553% 100.000%
TOTAL ANNUAL - EAST
15 PEAK - MW 7,443 4.278 2.933 4.461 0.190 12.566 0.534 24.962 118.015 57.220 67.436 9.313 45.430 2.607 300.021 324.982
16 ANNUAL MWH 45,369,000 23,480 26,000 15,924 1,228 75,718 3,356 145,704 683,442 480,611 353,028 106,055 208,572 24,872 1,856,581 2,002,285
17 LOSS % TO INPUT 0.052% 0.057% 0.035% 0.003% 0.167% 0.007% 0.321% 1.506% 1.059% 0.778% 0.234% 0.460% 0.055% 4.092%
18 LOSS % TO TOTAL ANNUAL INPUT 7.277%92.723% 100.000%
19 LOSS % TO TOTAL ANNUAL OUTPUT 43,366,71520 (Input - Losses)4.617%
LOSS FACTORS - EAST
21 Demand 1.0456622 Energy 1.04617
Winter
Hours
Summer
Hours
Total
Hours
Percent of
Total
Hours
PERCENT RANGE - EAST
22 91-100 169 109 278 3.17%
23 76-90 970 905 1,875 21.40%
24 51-75 4,596 1,875 6,471 73.87%
25 1-50 97 39 136 1.55%
26 Total Hours 5,832 2,928 8,760 100.00%
NOTES:
(1) Bridger losses shown at 66.7% - reference Work paper 1.
(2) Summer Period includes June, July, August, and September.
(3) Winter Period includes all non Summer months.
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Appendix A
Transmission Loss Model
Page 6 of 6
PACIFICORP POWER FLOW RESULTS - WES
TRANSFORMER LOSSES M TRANSMISSION LINE LOSSES MW
TIME
MW-WEST
INPUT
345 kV to
500 kV (1)
161 kV to
345 kV
46 kV to
115 kV GSU
Subtotal
Transformers
345 kV to
500 kV (2)
161 kV to
345 kV
Corona
500 kV to
138 kV
46 kV to
115 kV
Below 46
kV
Subtotal
Transm Lines
Total
Transmission
Losses
WINTER - WEST
1 PEAK - MW 4,009 0.465 6.843 2.042 3.109 12.459 11.433 30.143 4.691 70.768 1.237 118.271 130.730
2 LOSS % TO INPUT 0.012% 0.171% 0.051% 0.078% 0.311% 0.285% 0.752% 0.117% 1.765% 0.031% 2.950%
3 LOSS % TO TOTAL LOSSES 9.530%90.470% 100.000%
4
5 WINTER MWH 14,464,624 1,165 36,257 11,417 17,590 66,430 64,387 114,122 35,565 279,221 1,616 494,911 561,341
6 LOSS % TO INPUT 0.008% 0.251% 0.079% 0.122% 0.459% 0.445% 0.789% 0.246% 1.930% 0.011% 3.422%
7 LOSS % TO TOTAL LOSSES 11.834%88.166% 100.000%
SUMMER - WEST
8 PEAK - MW 3,647 0.390 6.604 1.834 3.065 11.892 10.025 27.421 4.691 62.660 1.161 105.958 117.851
9 LOSS % TO INPUT 0.011% 0.181% 0.050% 0.084% 0.326% 0.275% 0.752% 0.129% 1.718% 0.032% 2.906%
10 LOSS % TO TOTAL LOSSES 10.091%89.909% 100.000%
11
12 SUMMER MWH 6,896,481 536 19,636 4,442 7,144 31,759 30,516 51,775 17,856 132,623 581 233,351 265,110
13 LOSS % TO INPUT 0.008% 0.285% 0.064% 0.104% 0.461% 0.442% 0.751% 0.259% 1.923% 0.008% 3.384%
14 LOSS % TO TOTAL LOSSES 11.979%88.021% 100.000%
TOTAL ANNUAL - WES
PEAK - MW 3,647 0.390 6.604 1.834 3.065 11.892 10.025 27.421 4.691 62.660 1.161 105.958 117.851
15 ANNUAL MWH 21,361,106 1,702 55,893 15,859 24,735 98,188 94,903 165,897 53,421 411,844 2,197 728,263 826,451
16 LOSS % TO INPUT 0.008% 0.262% 0.074% 0.116% 0.460% 0.444% 0.777% 0.250% 1.928% 0.010% 3.409%
17 LOSS % TO TOTAL ANNUAL INPUT 11.881%88.119% 100.000%
18 LOSS % TO TOTAL ANNUAL OUTPUT 20,534,655
19 (Input - Losses)4.025%
LOSS FACTORS - WES
20 Demand 1.03340
21 Energy 1.04025
Winter
Hours
Summer
Hours
Total
Hours
Percent of
Total
Hours
PERCENT RANGE - WES
22 91-100 49 287 336 3.84%
23 76-90 2,039 512 2,551 29.12%
24 51-75 3,663 1,981 5,644 64.43%
25 1-50 81 148 229 2.61%
26 Total Hours 5,832 2,928 8,760 100.00%
NOTES:
(1) Summer Period includes June, July, August, and September.
(2) Winter Period includes all non Summer months.
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Idaho 2009 Analysis of System Losses

Appendix B

Results of PacifiCorp Idaho
2009 Loss Analysis
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
PACIFICORP IDAHO
EXHIBIT 1
SUMMARY OF COMPANY DATA
ANNUAL PEAK 517 MW
GENERATION & PURCHASES-INPUT 3,214,920 MWH
ANNUAL SALES -OUTPUT 2,963,061 MWH
SYSTEM LOSSES INPUT 251,859 or 7.83%
OUTPUT or 8.50%
SYSTEM LOAD FACTOR 70.9%
SUMMARY OF LOSSES - OUTPUT RESULTS
SERVICE KV MW % TOTAL MWH % TOTAL
TRANS 500,345,161 21.1 47.36% 139,236 55.28%
115,69,46 4.09%4.33%
PRIMARY 34,12,1 13.8 30.99% 49,967 19.84%
2.67%1.55%
SECONDARY < 1 9.7 21.64% 62,655 24.88%
1.87%1.95%
TOTAL 44.6 100.00% 251,859 100.00%
8.62%7.83%
SUMMARY OF LOSS FACTORS
CUMMULATIVE SALES EXPANSION FACTORS
SERVICE KV DEMAND ENERGY
d 1/d e 1/e
TRANS 500,345,161 1.04259 0.95915 1.04527 0.95669
115,69,46
PRIM SUBS 0.00000 0.00000 0.00000 0.00000
PRIMARY 0,0,0 1.08559 0.92116 1.07448 0.93068
SECONDARY < 1 1.11867 0.89392 1.11466 0.89714
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
SUMMARY OF CONDUCTOR INFORMATION EXHIBIT 2
DESCRIPTION CIRCUIT LOADING ----- MW LOSSES ----- ---- MWH LOSSES ----
MILES % RATING LOAD NO LOAD TOTAL LOAD NO LOAD TOTAL
--- BULK ----------- 345 KV OR GREATER --------------------- -------------------- -------------------- -------------------- -------------------- -------------------- ------------------
TIE LINES 0.0 0.00% 0.000 0.000 0.000 0 0 0
BULK TRANS 0.0 0.00%0.000 0.000 0.000 0 0 0
SUBTOT 0.0 0.000 0.000 0.000 0 0 0
--- TRANS ---------115 KV TO 345.00 KV -------------------- -------------------- ---------------------------------------- -------------------- ------------------
TIE LINES 0 0.00% 0.000 0.000 0.000 0 0 0
TRANS1 161 KV 0.0 0.00% 0.000 0.000 0.000 0 0 0
TRANS2 115 KV 0.0 0.00%0.000 0.001 0.001 0 7 7
SUBTOT 0.0 0.000 0.001 0.001 0 7 7
--- SUBTRANS ------35 KV TO 115 KV -------------------- -------------------- ---------------------------------------- -------------------- ------------------
TIE LINES 0 0.00% 0.000 0.000 0.000 0 0 0
SUBTRANS1 69 KV 0.0 0.00% 0.000 0.000 0.000 0 0 0
SUBTRANS2 46 KV 0.0 0.00% 0.000 0.000 0.000 0 0 0
SUBTRANS3 35 KV 0.0 0.00%0.000 0.000 0.000 0 0 0
SUBTOT 0.0 0.000 0.000 0.000 0 0 0
PRIMARY LINES 6,010 9.522 0.501 10.024 30,096 4,399 34,496
SECONDARY LINES 280 0.106 0.000 0.106 615 0 615
SERVICES 1,549 1.212 0.214 1.426 5,958 1,876 7,835
TOTAL 7,839 10.840 0.716 11.556 36,669 6,283 42,952
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
SUMMARY OF TRANSFORMER INFORMATION EXHIBIT 3
DESCRIPTION KV CAPACITY NUMBER AVERAGE LOADING MVA --------- MW LOSSES -------- ------- MWH LOSSES ------
VOLTAGE MVA TRANSFMR SIZE % LOAD LOAD NO LOAD TOTAL LOAD NO LOAD TOTAL
BULK STEP-UP 345 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
BULK - BULK 0.0 0 0.0 0.00% 0 0 0.000 0.000 0 0 0
BULK - TRANS1 161 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
BULK - TRANS2 115 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0

TRANS1 STEP-UP 161 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS1 - TRANS2 115 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS1-SUBTRANS1 69 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS1-SUBTRANS2 46 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS1-SUBTRANS3 35 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS2 STEP-UP 115 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS2-SUBTRANS1 69 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS2-SUBTRANS2 46 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS2-SUBTRANS3 35 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN1 STEP-UP 69 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN2 STEP-UP 46 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN3 STEP-UP 35 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN1-SUBTRAN2 46 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN1-SUBTRAN3 35 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN2-SUBTRAN3 35 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
DISTRIBUTION SUBSTATIONS
TRANS1 - 161 34 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS1 - 161 12 30.0 1 30.0 44.25% 13 0.021 0.041 0.062 67 360 428
TRANS1 - 161 1 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 302 302
TRANS2 - 115 34 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS2 - 115 12 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
TRANS2 - 115 1 22.4 1 22.4 44.25% 10 0.017 0.032 0.049 55 279 334
SUBTRAN1- 69 34 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN1- 69 12 618.8 47 13.2 44.25% 274 0.538 0.949 1.486 1,742 8,311 10,054
SUBTRAN1- 69 1 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN2- 46 34 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN2- 46 12 129.6 20 6.5 44.25% 57 0.140 0.229 0.369 453 2,009 2,463
SUBTRAN2- 46 1 20.6 4 5.2 44.25% 9 0.025 0.041 0.066 81 358 439
SUBTRAN3- 35 34 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN3- 35 12 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
SUBTRAN3- 35 1 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
PRIMARY - PRIMARY 0.0 0 0.0 0.00% 0 0.000 0.000 0.000 0 0 0
LINE TRANSFRMR 1,847.3 46,212 40.0 19.13% 353 1.141 5.747 6.888 2,027 50,346 52,373
=========== =========== =========== =========== =========== =========== =========== =========== ========== ===========
TOTAL 2,669 46,285 1.881 7.039 8.920 4,426 61,965 66,392
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
SUMMARY OF LOSSES DIAGRAM - DEMAND MODEL - SYSTEM PEAK 517.3891735 MW EXHIBIT 4 PAGE 1 of 2
BULK TIE LINES BULK LINES BULK STEP UP BULK-BULK
LOAD 0.00% MW LOADING 0.00% LOADING 0.00% LOADING 0.00%
LOAD LOSS 0.000 MW LOAD LOSS 0.000 MW NO LOAD 0.000 MW NO LOAD 0 MW
NOLD LOSS 0.000 MW NOLD LOSS 0.000 MW LOAD 0.000 MW LOAD 0 MW
AVG SIZE 0 MVA AVG SIZE 0 MVA
NUMBER 0 NUMBER 0
TRANS TIE LINES BULK-TRANS1 STEP DOWN TRAN1-TRAN2 STEP DOWN BULK-TRANS2 STEP DOWN
LOAD 0.00% MW LOADING 0.00% LOADING 0.00% LOADING 0.00%
LOAD LOSS 0.000 MW NO LOAD 0.000 MW NO LOAD 0.000 MW NO LOAD 0.000 MW
NOLD LOSS 0.000 MW LOAD 0.000 MW LOAD 0.000 MW LOAD 0.000 MW
AVG SIZE 0 MVA AVG SIZE 0 MVA AVG SIZE 0 MVA
NUMBER 0 NUMBER 0 NUMBER 0
TRANS 1&2 STEP UPS TRANS1 161.0 KV TRANS2 115.0 KV TRANS CUST
LDNG TR1SU 0.00% LOADING 0.00% LOADING 0.00% SUBS 0.000 MW
NOLOAD1&2 0.000 MW LOAD LOSS 0.000 MW LOAD LOSS 0.000 MW 0.000 MVA
LOAD 1&2 0.000 MW NOLD LOSS 0.000 MW NOLD LOSS 0.001 MW LINES MW
AVSIZ TR1SU 0.0 MVA MVA
NUMBER 0
SUBTRANS TIE LINES TRANS1&2-SUBTRANS1 SUBTR1&2-SUBTRANS2&3 TRANS1&2- SUBTRANS2 TRANS1&2-SUBTRANS3
LOAD 0.00% MW LDNG TR2-S 0.00%LOADING 0.00%LDNG TR2-S 0.00%LDNG TR2-ST 0.00%
LOAD LOSS 0.000 MW NO LOAD 0.000 MW NO LOAD 0.000 MW NO LOAD 0.000 MW NO LOAD 0.00
NOLD LOSS 0.000 MW LOAD 0.000 MW LOAD 0.000 MW LOAD 0.000 MW LOAD 0.00
AVSIZ TR2 0 MVA AVG SIZE 0 MVA VSIZ TR2-S 0.00 MVA VSIZ TR2-ST 0.00
NUMBER 0 NUMBER 0 NUMBER 0 NUMBER 0
SUBTRANS1,2,&3 STEP UPS SUBTRANS1 69 KV SUBTRANS2 46 KV SUBTRANS2 35 KV SUBTRANS CUST
LDNG ST1SU 0.00% LOADING 0.00% LOADING 0.00% LOADING 0.00% SUBS - MW 0.000
NO LOAD 0.000 MW LOAD LOSS 0.000 MW LOAD LOSS 0.000 MW LOAD LOSS 0.000 MW MVA 0.000
LOAD 0.000 MW NOLD LOSS 0.000 MW NOLD LOSS 0.000 MW NOLD LOSS 0.000 MW LINES- MW
AVSIZ ST2 0.0 MVA MVA
NUMBER 0
TO DISTRIBUTION SYSTEM
363.4 MVA 356.2 MW
TRANS1 13.3 MVA TRANS2 9.9 MVA SUBTRANS1 273.8 MVA SUBTRANS2 66.4 MVA SUBTRANS3 0.0 MVA
3.65% 2.73% 75.34% 18.28% 0.00%
161 KV 115 KV 69 KV 46 KV 35 KV
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
FROM HIGH VOLTAGE SYSTEM EXHIBIT 4 PAGE 2 of 2
TOTAL 363 MVA 356 MW
TRANS1 13.3 MVA TRANS2 9.9 MVA SUBTRANS1 273.8 MVA SUBTRANS2 66.4 MVA SUBTRANS3 0.0 MVA
3.65% 2.73% 75.34% 18.28% 0.00%
161 KV 115 KV 69 KV 46 KV 35 KV
DISTRIBUTION SYSTEM LOAD
| | | | | | | | | | | | | | |
PRIM1 PRIM2 PRIM3 PRIM1 PRIM2 PRIM3 PRIM1 PRIM2 PRIM3 PRIM1 PRIM2 PRIM3 PRIM1 PRIM2 PRIM3
VOLTAGE 34 12 1 34 12 1 34 12 1 34 12 1 34 12 1
LOAD MVA 0 13 0 0 0 10 0 274 0 0 57 9 0 0 0
% SYS TOT 0.00% 3.65% 0.00% 0.00% 0.00% 2.73% 0.00% 75.34% 0.00% 0.00% 15.77% 2.51% 0.00% 0.00% 0.00%
NOLD LOSS 0.000 0.041 0.000 0.000 0.000 0.032 0.000 0.949 0.000 0.000 0.229 0.041 0.000 0.000 0.000
LOAD LOSS 0.000 0.021 0.000 0.000 0.000 0.017 0.000 0.538 0.000 0.000 0.140 0.025 0.000 0.000 0.000
AVG SIZE 0.0 30.0 0.0 0.0 0.0 22.4 0.0 13.2 0.0 0.0 6.5 5.2 0.0 0.0 0.0
NUMBER 0 1 0 0 0 1 0 47 0 0 20 4 0 0 0
DIVERSITY 0.000 1.000 0.000 0.000 0.000 1.000 0.000 1.000 0.000 0.000 1.000 1.000 0.000 0.000 0.000
RATIO | | | | | | | | | | | | | | |
PRIMARY LINES PRIM/PRIM TRANSF PRIM CUST LOADS
LOADING 344.146 MW LOADING 0.000 MW NO LINES 0.000 MW
@ SYS PF 351.169 MVA NOLD LOSS 0.000 MW CUST SUB 0.000 MVA
LOAD LOSS 9.522 MW LOAD LOSS 0.000 MW NO LINES 0.000 MW
NOLD LOSS 0.501 MW AVG SIZE 0.00 CO. SUB 0.000 MVA
TOT LOSS 10.024 MW NUMBER 0 PRIM WITH 8.808 MW
LINES 9.272 MVA
LINE TRANSFORMERS
LOADING 325.314 MW MVA 360.310
NOLD LOSS 5.747 MW
LOAD LOSS 1.141 MW
AVG SIZE 40.0 KVA
NUMBER 46212
SECONDARY LINES NO SECONDARY LINES
LOAD 28.578 MW
LOAD LOSS 0.106 MW LOAD 289.848 MW
NOLD LOSS 0.000 MW
TOT LOSS 0.106 MW
SERVICES
LOAD 318.320 MW
LOAD LOSS 1.212 MW
NOLD LOSS 0.214 MW
TOT LOSS 1.426 MW
CUSTOMER SECONDARY LOAD
316.895 MW
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
SUMMARY of SALES and CALCULATED LOSSES EXHIBIT 5
LOSS # AND LEVEL MW LOAD NO LOAD + LOAD = TOT LOSS EXP CUM MWH LOAD NO LOAD + LOAD = TOT LOSS EXP CUM
FACTOR EXP FAC FACTOR EXP FAC
1 BULK XFMMR 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0 0
2 BULK LINES 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
3 TRANS1 XFMR 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
4 TRANS1 LINES 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
5 TRANS2TR1 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
6 TRANS2BLK SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
7 TRANS2 LINES 0.0 0.00 0.00 0.00 0.000000 0.000000 0 7 0 7 0.0000000 0.0000000
TOTAL TRAN 0.0 0.00 0.00 0.00 0.000000 0.000000 0 7 0 7 0.0000000 0.0000000
8 STR1BLK SD
9 STR1T1 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
10 SRT1T2 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
11 SUBTRANS1 LINES 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
12 STR2T1 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
13 STR2T2 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
14 STR2S1 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
15 SUBTRANS2 LINES 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
16 STR3T1 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
17 STR3T2 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
18 STR3S1 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
19 STR3S2 SD 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
20 SUBTRANS3 LINES 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
21 SUBTRANS TOTAL 0.0 0.00 0.00 0.00 0.000000 0 0 0 0 0.0000000
22 TRANSMSN LOSS FAC 517.4 2.11 19.02 21.14 1.042590 1.042590 3,214,920 41,771 97,465 139,236 1.0452700 1.0452700
DISTRIBUTION SUBST
TRANS1 13.0 0.04 0.02 0.06 1.004781 0.000000 67,010 663 67 730 1.0110118 0.0000000
TRANS2 0.0 0.03 0.02 0.05 0.000000 0.000000 50,034 279 55 334 1.0067113 0.0000000
SUBTR1 268.3 0.95 0.54 1.49 1.005570 0.000000 1,382,145 8,311 1,742 10,054 1.0073273 0.0000000
SUBTR2 65.1 0.27 0.17 0.44 1.006728 0.000000 335,418 2,367 535 2,902 1.0087265 0.0000000
SUBTR3 0.0 0.00 0.00 0.00 0.000000 0.000000 0 0 0 0 0.0000000 0.0000000
WEIGHTED AVERAGE 346.5 1.3 0.7 2.03 1.005900 1.048742 1,834,608 11,620 2,399 14,019 1.0077002 1.0533188
PRIMARY INTRCHNGE 0.0 0.000000 0 0.0000000
PRIMARY LINES 344.1 0.50 9.52 10.02 1.030000 1.080204 1,820,851 4,390 30,096 34,487 1.0193055 1.0736536
LINE TRANSF 325.3 5.75 1.14 6.89 1.021631 1.103570 1,736,416 50,346 2,027 52,373 1.0310995 1.1070437
SECONDARY 318.4 0.00 0.11 0.11 1.000332 1.103936 1,684,043 0 615 615 1.0003650 1.1074478
SERVICES 318.3 0.21 1.21 1.43 1.004499 1.108903 1,683,429 1,876 5,958 7,835 1.0046757 1.1126259
========== ========== ========== ========== ========== ==========
TOTAL SYSTEM 9.87 31.74 41.61 110,018 138,561 248,578
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
DEVELOPMENT of LOSS FACTORS EXHIBIT 6
UNADJUSTED
DEMAND
LOSS FACTOR CUSTOMER CALC LOSS SALES MW CUM EXPANSION
LEVEL SALES MW TO LEVEL @ GEN FACTORS
a b c d 1/d
BULK LINES 0.0 0.0 0.0 0.00000 0.00000
TRANS SUBS 0.0 0.0 0.0 0.00000 0.00000
TRANS LINES 147.1 6.3 153.3 1.04259 0.95915
SUBTRANS SUBS 0.0 0.0 0.0 0.00000 0.00000
SUBTRANS LINES 0.0 0.0 0.0 0.00000 0.00000
PRIM SUBS 0.0 0.0 0.0 0.00000 0.00000
PRIM LINES 8.8 0.7 9.5 1.08020 0.92575
SECONDARY 316.9 34.5 351.4 1.10890 0.90179
TOTALS 472.8 41.5 514.2
DEVELOPMENT of LOSS FACTORS
UNADJUSTED
ENERGY
LOSS FACTOR CUSTOMER CALC LOSS SALES MWH CUM EXPANSION
LEVEL SALES MWH TO LEVEL @ GEN FACTORS
a b c d 1/d
BULK LINES 0 0 0 0.00000 0.00000
TRANS SUBS 0 0 0 0.00000 0.00000
TRANS LINES 1,237,519 56,022 1,293,541 1.04527 0.95669
SUBTRANS SUBS 0 0 0 0.00000 0.00000
SUBTRANS LINES 0 0 0 0.00000 0.00000
PRIM SUBS 0 0 0 0.00000 0.00000
PRIM LINES 49,948 3,679 53,627 1.07365 0.93140
SECONDARY 1,675,594 188,715 1,864,309 1.11263 0.89877
TOTALS 2,963,061 248,417 3,211,478
ESTIMATED VALUES AT GENERATION
LOSS FACTOR AT
VOLTAGE LEVEL MW MWH
BULK LINES 0.00 0
TRANS SUBS 0.00 0
TRANS LINES 153.33 1,293,541
SUBTRANS SUBS 0.00 0
SUBTRANS LINES 0.00 0
PRIM SUBS 0.00 0
PRIM LINES 9.51 53,627
SECONDARY 351.41 1,864,309
SUBTOTAL 514.25 3,211,478
ACTUAL ENERGY LESS THI 517.39 3,214,920
MISMATCH (3.14) (3,442)
% MISMATCH -0.61% -0.11%
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
DEVELOPMENT of LOSS FACTORS EXHIBIT 7
ADJUSTED
DEMAND
LOSS FACTOR CUSTOMER SALES CALC LOSS SALES MW CUM EXPANSION
LEVEL SALES MW ADJUST TO LEVEL @ GEN FACTORS
a b c d e f=1/e
BULK LINES 0.0 0.0 0.0 0.0 0.00000 0.00000
TRANS SUBS 0.0 0.0 0.0 0.0 0.00000 0.00000
TRANS LINES 147.1 0.0 6.3 153.3 1.04259 0.95915
SUBTRANS SUBS 0.0 0.0 0.0 0.0 0.00000 0.00000
SUBTRANS LINES 0.0 0.0 0.0 0.0 0.00000 0.00000
PRIM SUBS 0.0 0.0 0.0 0.0 0.00000 0.00000
PRIM LINES 8.8 0.0 0.8 9.6 1.08559 0.92116
SECONDARY 316.9 0.0 37.6 354.5 1.11867 0.89392
TOTALS 472.8 0.0 44.6 517.4
DEVELOPMENT of LOSS FACTORS
ADJUSTED
ENERGY
LOSS FACTOR CUSTOMER SALES CALC LOSS SALES MWH CUM EXPANSION
LEVEL SALES MWH ADJUST TO LEVEL @ GEN FACTORS
a b c d e f=1/e
BULK LINES 0 0 0 0 0.00000 0.00000
TRANS SUBS 0 0 0 0 0.00000 0.00000
TRANS LINES 1,237,519 0 56,022 1,293,541 1.04527 0.95669
SUBTRANS SUBS 0 0 0 0 0.00000 0.00000
SUBTRANS LINES 0 0 0 0 0.00000 0.00000
PRIM SUBS 0 0 0 0 0.00000 0.00000
PRIM LINES 49,948 0 3,720 53,668 1.07448 0.93068
SECONDARY 1,675,594 0 192,116 1,867,710 1.11466 0.89714
TOTALS 2,963,061 0 251,859 3,214,920
ESTIMATED VALUES AT GENERATION
LOSS FACTOR AT
VOLTAGE LEVEL MW MWH
BULK LINES 0.00 0
TRANS SUBS 0.00 0
TRANS LINES 153.33 1,293,541
SUBTRANS SUBS 0.00 0
SUBTRANS LINES 0.00 0
PRIM SUBS 0.00 0
PRIM LINES 9.56 53,668
SECONDARY 354.50 1,867,710
517.39 3,214,920
ACTUAL ENERGY LESS THI 517.39 3,214,920
MISMATCH 0.00 0
% MISMATCH 0.00%0.00%
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PACIFICORP IDAHO 2009 LOSS ANALYSIS
Adjusted Losses and Loss Factors by Facitliy EXHIBIT 8
MW MWH
Service Drop Losses 1.42 7,824
Secondary Losses 0.10 614
Line Transformer Losses 6.84 52,302
Primary Line Losses 9.96 34,440
Distribution Substation Losses 2.02 14,000
Transmission System Losses 21.14 139,236
Total 41.48 248,417
MW MWH
Service Drop Losses -0.22 (247)
Secondary Losses -0.02 (19)
Line Transformer Losses -1.06 (1,649)
Primary Line Losses -1.54 (1,086)
Distribution Substation Losses -0.31 (441)
Transmission System Losses 0.00 0
Total -3.14 (3,442)
MW MWH
Service Drop Losses 1.63566 8,071
Secondary Losses 0.12109 633
Line Transformer Losses 7.90180 53,951
Primary Line Losses 11.49915 35,526
Distribution Substation Losses 2.33137 14,441
Transmission System Losses 21.13545 139,236
Total 44.62451 251,859
Retail Sales from Service Drops 316.89 1,675,594
Adjusted Service Drop Losses 1.64 8,071
Input to Service Drops 318.53 1,683,665
Service Drop Loss Factor 1.00516 1.00482
Output from Secondary 318.53 1,683,665
Adjusted Secondary Losses 0.12 633
Input to Secondary 318.65 1,684,298
Secondary Loss Factor 1.00038 1.00038
Output from Line Transformers 318.65 1,684,298
Adjusted Line Transformer Losses 7.90 53,951
Input to Line Transformers 326.55 1,738,249
Line Transformer Loss Factor 1.02480 1.03203
Retail Sales from Primary 8.81 49,948
Req. Whls Sales from Primary 0.00 0
Input to Line Transformers 326.55 1,738,249
Output from Primary Lines 335.36 1,788,197
Adjusted Primary Line Losses 11.50 35,526
Input to Primary Lines 346.86 1,823,723
Primary Line Loss Factor 1.03429 1.01987
Output from Distribution Substations 346.86 1,823,723
Adjusted Distribution Substation Losses 2.33137 14,441
Input to Distribution Substations 349.19 1,838,164
Distribution Substation Loss Factor 1.00672 1.00792
Retail Sales at from Transmission 147.062 1,237,519
Req. Whls Sales from Transmission 0.00 0
Non-Req. Whls Sales from Transmission 0.000 0
Third Party Wheeling Losses 0.000 0
Input to Distribution Substations 349.19 1,838,164
Output from Transmission 496.254 3,075,683
Adjusted Transmission System Losses 21.13545 139,236
Input to Transmission 517.389 3,214,920
Transmission System Loss Factor 1.04259 1.04527
Loss Factors by Segment
Unadjusted Losses by Segment
Mismatch Allocation by Segment
Adjusted Losses by Segment
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DEMAND MW SUMMARY OF LOSSES AND LOSS FACTORS BY DELIVERY VOLTAGE EXHIBIT 9
PAGE 1 of 2
SERVICE SALES LOSSES SECONDARY PRIMARY SUBSTATION SUBTRANS TRANSMISSION
LEVEL MW
1 SERVICES
2 SALES 316.9 316.9
3 LOSSES 1.6 1.6
4 INPUT 318.5
5 EXPANSION FACTOR 1.00516
6 SECONDARY
7 SALES
8 LOSSES 0.1 0.1
9 INPUT 318.7
10 EXPANSION FACTOR 1.00038
11 LINE TRANSFORMER
12 SALES
13 LOSSES 7.9 7.9
14 INPUT 326.6
15 EXPANSION FACTOR 1.02480
16 PRIMARY
17 SECONDARY 326.6
18 SALES 8.8 8.8
19 LOSSES 11.5 11.2 0.3
20 INPUT
21 EXPANSION FACTOR 1.03429
22 SUBSTATION
23 PRIMARY 337.8 9.1
24 SALES 0.0 0.0
25 LOSSES 2.3 2.3 0.1 0.0
26 INPUT 340.0 9.2 0.0
27 EXPANSION FACTOR 1.00672
28 SUB-TRANSMISSION
29 DISTRIBUTION SUBS
30 SALES
31 LOSSES
32 INPUT
33 EXPANSION FACTOR
34 TRANSMISSION
35 SUBTRANSMISSION
36 DISTRIBUTION SUBS 340.0 9.2 0.0
37 SALES 147.1 147.1
38 LOSSES 21.1 14.5 0.4 0.0 6.3
39 INPUT 354.5 9.6 0.0 153.3
40 EXPANSION FACTOR 1.04259
41 TOTALS LOSSES 44.6 37.6 0.8 0.0 6.3
42 % OF TOTAL 100% 84.27% 1.69% 0.00%14.04%
43 SALES 472.8 316.9 8.8 0.0 147.1
44 % OF TOTAL 100.00%67.03% 1.86% 0.00%31.11%
45 INPUT 517.4 354.5 9.6 0.0 153.3
46 CUMMULATIVE EXPANSION LOSS FACTORS 1.11867 1.08559 NA 1.04259
(from meter to system input)
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ENERGY MWH SUMMARY OF LOSSES AND LOSS FACTORS BY DELIVERY VOLTAGE EXHIBIT 9
PAGE 2 of 2
SERVICE SALES LOSSES SECONDARY PRIMARY SUBSTATION SUBTRANS TRANSMISSION
LEVEL
1 SERVICES
2 SALES 1,675,594 1,675,594
3 LOSSES 8,071 8,071
4 INPUT 1,683,665
5 EXPANSION FACTOR 1.00482
6 SECONDARY
7 SALES
8 LOSSES 633 633
9 INPUT 1,684,298
10 EXPANSION FACTOR 1.00038
11 LINE TRANSFORMER
12 SALES
13 LOSSES 53,951 53,951
14 INPUT 1,738,249
15 EXPANSION FACTOR 1.03203
16 PRIMARY
17 SECONDARY 1,738,249
18 SALES 49,948.000 49,948
19 LOSSES 35,526 34,534 992
20 INPUT
21 EXPANSION FACTOR 1.01987
22 SUBSTATION
23 PRIMARY 1,772,783 50,940
24 SALES 0 0
25 LOSSES 14,441 14,038 403 0
26 INPUT 1,786,821 51,344 0
27 EXPANSION FACTOR 1.00792
28 SUB-TRANSMISSION
29 DISTRIBUTION SUBS
30 SALES
31 LOSSES
32 INPUT
33 EXPANSION FACTOR
34 TRANSMISSION
35 SUBTRANSMISSION
36 DISTRIBUTION SUBS 1,786,821 51,344 0
37 SALES 1,237,519 1,237,519
38 LOSSES 139,236 80,889 2,324 0 56,022
39 INPUT 1,867,710 53,668 0 1,293,541
40 EXPANSION FACTOR 1.04527
41 TOTALS LOSSES 251,859 192,116 3,720 0 56,022
42 % OF TOTAL 100% 76.28% 1.48% 0.00%22.24%
43 SALES 2,963,061 1,675,594 49,948 0 1,237,519
44 % OF TOTAL 100.00%56.55% 1.69% 0.00%41.76%
45 INPUT 3,214,920 1,867,710 53,668 0 1,293,541
46 CUMMULATIVE EXPANSION LOSS FACTORS 1.11466 1.07448 NA 1.04527
(from meter to system input)
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Idaho 2009 Analysis of System Losses

Appendix C

Discussion of Hoebel Coefficient

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1
COMMENTS ON HOEBEL COEFFICIENTS

The Hoebel constant represents an established industry standard relationship between peak losses
and average losses and is used in a loss study to estimate energy losses from peak demand losses.
H. F. Hoebel described this relationship in his article, "Cost of Electric Distribution Losses,"
Electric Light and Power, March 15, 1959. A copy of this article is attached.

Within any loss evaluation study, peak demand losses can readily be calculated given equipment
resistance and approximate loading. Energy losses, however, are much more difficult to
determine given their time-varying nature. This difficulty can be reduced by the use of an
equation which relates peak load losses (demand) to average losses (energy). Once the
relationship between peak and average losses is known, average losses can be estimated from the
known peak load losses.

Within the electric utility industry, the relationship between peak and average losses is known as
the loss factor. For definitional purposes, loss factor is the ratio of the average power loss to the
peak load power loss, during a specified period of time. This relationship is expressed
mathematically as follows:

where: FLS = Loss Factor
ALS = Average Losses
PLS = Peak Losses

The loss factor provides an estimate of the degree to which the load loss is maintained
throughout the period in which the loss is being considered. In other words, loss factor is the
ratio of the actual kWh losses incurred to the kWh losses which would have occurred if full load
had continued throughout the period under study.

Examining the loss factor expression in light of a similar expression for load factor indicates a
high degree of similarity. The mathematical expression for load factor is as follows:

where: FLD = Load Factor
ALD = Average Load
PLD = Peak Load

This load factor result provides an estimate of the degree to which the load loss is maintained
throughout the period in which the load is being considered. Because of the similarities in
definition, the loss factor is sometimes called the "load factor of losses." While the definitions
are similar, a strict equating of the two factors cannot be made. There does exist, however, a
relationship between these two factors which is dependent upon the shape of the load duration
curve. Since resistive losses vary as the square of the load, it can be shown mathematically that
the loss factor can vary between the extreme limits of load factor and load factor squared. The
(1) FLS  ALS  PLS
(2) FLD  ALD  PLD
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2
relationship between load factor and loss factor has become an industry standard and is as
follows:

where: FLS = Loss Factor
FLD = Load Factor
H = Hoebel Coefficient

As noted in the attached article, the suggested value for H (the Hoebel coefficient) is 0.7. The
exact value of H will vary as a function of the shape of the utility's load duration curve. In recent
years, values of H have been computed directly for a number of utilities based on EEI load data.
It appears on this basis, the suggested value of 0.7 should be considered a lower bound and that
values approaching unity may be considered a reasonable upper bound. Based on experience,
values of H have ranged from approximately 0.85 to 0.95. The standard default value of 0.9 is
generally used.

Inserting the Hoebel coefficient estimate gives the following loss factor relationship using
Equation (3):

Once the Hoebel constant has been estimated and the load factor and peak losses associated with
a piece of equipment have been estimated, one can calculate the average, or energy losses as
follows:

where: ALS = Average Losses
PLS = Peak Losses
H = Hoebel Coefficient
FLD = Load Factor

Loss studies use this equation to calculate energy losses at each major voltage level in the
analysis.

(3) FLS  H*FLD2 + (1-H)*FLD
(4) FLS  0.90*FLD2 + 0.10*FLD
(5) ALS  PLS * [H*FLD2 + (1-H)*FLD]
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