Docket No. UE 263
Exhibit P AC/11 07
Witness: C. Craig Paice
BEFORE THE PUBLIC UTILITY COMMISSION
OF OREGON
PACIFICORP
Exhibit Accompanying Direct Testimony of C. Craig Paice
Oregon Marginal Cost Study
March 2013
PacifiCorp
Oregon Marginal Cost Study
December 2014
Table of Contents
Tab 1
Tab 2
Tab 3
Tab4
Tab 5
Tab 6
Tab 7
Tab 8
Tab 9
Tab 10
Tab 11
Tab 12
Tab 13
Tab 14
Tab 15
Tab 16
Tab 17
Marginal Cost Study I Circuit Model Procedures
Summaries
Generation Capacity
Generation Energy, Avoided Costs
Transmission Summary (Investment, MW, O&M)
Distribution Substation
Distribution Poles& Conductors
Distribution Transformers
Distribution O&M
Customer Service Drop
Customer Meters and O&M
Streetlight
Customer Accounting, Service and Information
A&G Expense Loading Factor
Annual Charges
Losses
Customer Data
Exhibit PAC/1107
PacifiCorp
Marginal Cost Study & Circuit Model Procedures
INTRODUCTION
Customer class marginal costs are developed to illustrate the resources required to
produce one additional unit of electricity or add one additional customer to the system.
One, five, ten and twenty years marginal costs are calculated because the Company
believes the Commission should have information about the Company's marginal costs
over different time periods. Twenty-year (or long run) marginal costs, however, are the
primary time frame used in setting retail tariff prices.
The one-year marginal costs include only changes in operating costs, while ten- and
twenty-year marginal costs also include the cost of expanding facilities. The cost of
added facilities results in long-run costs, which are higher than short-run costs. Short-run
costs include only one year of generation energy costs and some billing costs. There are
no short-run demand-related generation, transmission or distribution costs. Long-run
costs include ten or twenty years of generation costs, transmission and distribution costs.
One, ten and twenty-year marginal costs are summarized by customer class and load size
group and shown in mills/kilowatt-hour (kWh). Marginal commitment costs and billing
expenses, which are sometimes referred to as customer costs, are shown in dollars per
customer per year. Costs are shown for both the one-year and the long-run time periods.
Unit costs are adjusted to 2014 values and are shown by generation, transmission, and
distribution functional categories and by demand, energy, and commitment and billing
costing classifications. Also included are energy usage, peak demand, and number of
customers by customer class for the 12 month period ending December 2014.
One, ten and twenty-year marginal costs in mills/kilowatt-hour (kWh) are shown on
"Summary of Marginal Costs Demand & Energy in Mills/kWh" (Sheet 'Table 1').
Marginal commitment costs and billing expenses are shown on "Summary of Marginal
Costs Commitment and Billing in$ I Customer I Month" (Sheet 'Table 2'). Unit costs
and billing information are shown on "20 Year Costing Inputs and Customer Data
Marginal Unit Costs" (Sheet 'Table 3 ') and total marginal costs are shown on "20 Year
Marginal Cost By Load Class" (Sheet 'Table 4').
MARGINAL GENERATION COSTS
The development of marginal generation costs for this study is consistent with the
analysis done to prepare the Company's avoided costs filings. Marginal generation costs
are based on the Company's most recent avoided cost calculations. The analysis
recognizes that baseload generation produces the dual products of capacity and energy.
The new resource costs are based on the fixed and variable cost of a Combined Cycle
Combustion Turbine (CCCT), which operates as a base load unit. The cost of the CCCT
is split into capacity and energy components. The fixed cost of a simple cycle
combustion turbine (SCCT) defines the fixed costs of the CCCT that are assigned to
capacity. CCCT fixed costs which are in excess of SCCT fixed costs are assigned to
energy. They are added to the variable production cost of the CCCT and renewable wind
Tab 1
Page 1 of 12
resource costs. Renewable resource costs are included in the marginal cost of service
study for the first time in the current case. These costs are based on a Wyoming wind
facility (35% capacity factor) as shown in Table 6.3 ofthe Company's 2011 integrated
resource plan ("IRP") and are weighted according to the Oregon RPS requirements for
each year during the long-run marginal cost period. Weightings oftl.ve percent for 2014,
fifteen percent for 2015-2019, twenty percent for 2020-2024, and twenty-five percent for
2025-2032 are applied to renewables resource costs. Non-renewable marginal energy
costs are reduced by the renewable weighting percentage, added to the weighted
renewable costs. Total energy and capacity costs are present valued, summed and an
annual charge applied to the total. The marginal generation cost calculation is shown in
the cost of service study on sheet "Summary of Marginal Generation Costs In Nominal
Dollars" (Sheet 'Table 5').
MARGINAL TRANSMISSION COSTS
The calculation of transmission costs are based on a five-year (20 14-20 18) analysis of
forecasted expenditures to meet increased load on the transmission system. All of these
growth-related transmission investments, except bulk power lines, are classified entirely
to demand.
Unlike growth-related system support and local transmission investments, the Company's
investment in bulk power lines is classified both to demand and energy in the same
proportions as twenty-year marginal costs of generation resources. Bulk transmission
costs are classified this way because they are thought to be an integral part of the
generation system. The Company's investments in high voltage bulk transmission lines
are being made to move both energy and capacity. It is usually not possible to site a
thermal plant close to the customers the plant is intended to serve. Instead, bulk power
lines are constructed to transmit the energy being generated, along with the
accompanying capacity.
Each year's growth-related transmission investments are adjusted to 2014 dollars and the
five years are totaled. The total transmission investment is divided by the forecasted
growth in system demand over the 5-year period to determine the marginal investment
per kilowatt (kW). An annual charge for including an A&G expense loading factor and a
transmission O&M loading factor are added to the per kW investment to arrive at longrun transmission marginal cost.
The marginal transmission calculation including the split between demand and energy
can be seen in the marginal cost study on page "Marginal Transmission Investment and
O&M Expenses" (Sheet 'Transml '). A summarized version of this page is "Marginal
Cost of Transmission Investment and Associated Expenses" (Sheet 'Table 6').
MARGINAL DISTRIBUTION COSTS
Distribution costs are classified into three components: Demand-related, shown in dollars
per kW/year, commitment-related, shown in dollars per customer/year, and billingrelated, shown in dollars per customer/year. Commitment costs consist of the costs of
transformers, poles, and conductor that are not determined by the level of demand
customers place on the system. Demand-related costs are the additional costs of larger
Tab 1
Page 2 of 12
transformers, substations, poles, and conductors with sufficient capacity to serve the level
of demand a customer class places on the system. Billing costs are the costs of meters,
service drops, and customer accounting functions.
A summary of distribution marginal costs showing these three components are on page
"Marginal Distribution & Billing Costs By Load Size 2014 Dollars" (Sheet 'Table 7').
Marginal line transformer costs are calculated using a least squares regression analysis of
the current installed cost versus size ofthe Company's commonly installed transformers.
Commitment and demand costs are separated by the nature of the statistical technique.
The regression provides an intercept term, which represents the commitment costs, and a
slope, which represents the demand cost per kW. The regression also identifies the
additional costs of a three-phase transformer over a single-phase transformer.
Line transformer regression results are shown on page "Calculation of Escalation Factors
for Transformers (Regression weighted by number of transformer banks)" (Sheet
'XFMR3 '). Transformer demand costs are shown on page "Transformer Demand Costs"
(Sheet 'XFMR2') and commitment costs are shown on page "Transformer Commitment
Costs by Customer Load Class" (Sheet 'XFMR1 ').
Marginal costs of distribution poles and wires are calculated using the Company's
Distribution Circuit Model (Sheets 'PC3' through 'PC14'). The circuit model focuses on
several key characteristics that influence distribution cost of service. Among these are
customer density, customer size and usage characteristics, and customer location on the
circuit. The hypothetical circuit is constructed with seven branches of equal length using
the composite line statistics for the state of Oregon. The model determines the cost of the
circuit by using current cost estimates to construct one mile of distribution facilities using
each of the Company's single and three phase wire sizes. The results are segregated into
commitment related and demand related costs for each customer class. A more detailed
description of the circuit model is included as an appendix to this narrative.
Marginal poles and wire costs are shown on page "Hypothetical Circuit Study Results
Annual Demand and Commitment Costs" (Sheet 'PC1 ').
Marginal substation costs are determined using the per k W cost of budgeted and
forecasted substation additions for the five year period 2012 - 2016. As part of the
capital budgeting process the company determines which substations are approaching
their maximum design loading. When load can no longer be shifted to adjacent
substations, an upgrade, either greater capacity at the substation or a new substation, is
required. The capital investment in common year dollars is totaled across all projects and
across the budget-planning horizon to produce total substation investment. The
substation investment is divided by the associated incremental substation capacity to get
dollars I kW. The dollars per kW is adjusted to an annual value by applying a real
levelized carrying charge. Substation marginal costs are classified entirely to demand,
and are allocated to customer classes based on the distribution peak load for each class.
Tab 1
Page 3 of 12
Page "Substation Investment" (Sheet 'Dist Sub 2') shows the detail of the substation
calculation. "Distribution Substation Costs I kW 2014 Dollars" (Sheet 'Dist Sub 1')
shows the annualized cost in $/kW.
The marginal cost of services includes the costs of new service drop investment plus
associated O&M expense. Average service drop investments are determined for each
customer load size by analyzing service requirements, such as single or three-phase
service and voltage level. Incremental service drop O&M is based on the average of ten
years of historical expenditures.
The metering category includes the marginal cost of metering equipment with associated
O&M expense. Average meter investments are determined for each customer load size
by analyzing service requirements, such as single or three-phase service and voltage
level. Meter O&M expense is based on historical expenditures.
The billing customer service/other category includes the costs of billing, payment
processing, debt recovery, meter reading expenses and all remaining customer accounting
and customer service activities. Customer accounting and customer service expense are
based on the most recent five years of expenditures and are assigned to each customer
class based on the various resources required to perform billing, collections, and
customer service activities for different types of customers.
Weighted average installed service drop cost calculations are located on Sheets 'Services
1' through 'Services 3' and the weighted average installed meter cost calculations are
included on Sheets 'Meters 1' through 'Meters 5 '. The customer accounting and
informational expense calculation is on page "Summary of Customer Accounting
Expense by Schedule" (Sheet 'Cust Exp Sum'). These calculations are brought together
on "Marginal Distribution & Billing Costs By Load Size" (Sheet 'Table 7') to calculate
metering reading, billing, collections and customer service related costs ($/Customer/Yr).
Tab 1
Page 4 of 12
PacifiCorp
Distribution Circuit Model
PacifiCorp Distribution Circuit Model
General Overview
The PacifiCorp Distribution Circuit Model is included in Exhibit PAC/1107, Sheets PC 3
through PC 14 and calculates the cost of building a hypothetical circuit (Figure 1, below)
with seven branches of equal length using the composite line statistics for a chosen state
or service area. A hypothetical circuit is used rather than a sampling of actual existing
circuits. This is because the diverse characteristics ofPacifiCorp's six state service area,
consisting of over 2,000 distribution circuits, makes the selection of any single, or small
number of typical circuits impractical. The fundamental concept of the hypothetical
circuit is to create a model that reduces the elements of distribution cost assignment to a
workable form.
Figure 1 - Circuit Model Diagram
I Branch 1
JBranch 4
~
/
/
/
/
/
Substation
1-1 Branch 7 ~ -( ~~ Branch 6
''
'
''
~--(~-------I Branch 2
''
l
Branch 5
''
'
l
Branch 3
The circuit model focuses on several key characteristics that influence distribution cost of
service. Among these are customer density, customer size and usage characteristics, and
perhaps most importantly, customer location on the circuit. Each customer is assigned
cost responsibility for all distribution facilities between the customer's location and the
substation (upstream facilities), but no facilities beyond the customer's service location
(downstream facilities). The model performs three basic functions. First, it estimates the
total cost to build the composite circuit using current construction costs and state specific
characteristics. Second, it divides the cost of each branch of the circuit between demand
and commitment related costs. Third, it assigns the various types of costs to customer
classes.
Required Engineering & Statistical Data
Listed below are the basic statistics that we use to calculate the composite circuit for a
given state:
1. Current One Mile Line Construction Cost Estimates for Each Conductor Size
2. Economic Conductor Loading for Each Conductor Size
Tab 1
Page 5 of 12
3.
4.
5.
6.
7.
8.
Overhead and Underground Line Miles
Number of Poles
Number of Circuits-- distribution line points of origin radiating from a substation.
Actual Customer Distances from Distribution Substations
Number of Customers and Loads by Class
Percentages of Three-Phase and Single-Phase Customers by Class
One Mile Line Estimate
The model determines the cost of the circuit by using cost estimates to construct one mile
of distribution facilities using each of the Company's single and three-phase wire sizes.
These cost estimates are based on typical topography and equipment configuration for an
average mile of line construction. Since the number of poles per mile varies between
states, we use a factor to adjust the line cost estimate from the system wide average of
26.13 poles per mile to the state average poles per mile. For example, Oregon has an
average of 25.86 poles per mile. Figure 2 shows the circuit cost per mile calculation for
Oregon.
Figure 2 -Adjusted Oregon Line Costs per Mile
Account 364 Pole Cost per Mile
Pole Cost
Adjustment Adjusted
per Mile
Factor
Pole Cost
I
Wire Sizes
1
2
3
4
1 Phase -1/0 ACSR
3 Phase- 1/0 ACSR
3 Phase- 447 AAC & 4\0 AAC
3 Phase -795 AAC & 477 AAC
$
$
$
$
I
27,300
47,186
53,129
56,254
0.990
0 990
0.990
0.990
12,430,368
22,947,921
75,818,501
60,059,546
18,879,273
38,426,986
228,562,595
2,354
4,346
14,360
11,375
3,576
7,278
43,288
$
$
$
$
27,027
46,714
52,598
55,691
Account365 Total Line
Conductor Construction
Cost per Mile
Cost
$
$
$
$
13,053
28,680
47,812
105,804
$ 40,080
$ 75,394
$ 100,410
$ 161,495
State
California
Idaho
Oregon
Utah
Washington
Wyoming
Total
55,887
99,188
371,373
350,610
98,696
155,389
1,131,143
23.74
22.82
25.86
30.82
27.60
21.35
26.13
0.908
0.873
0.990
1.180
1.056
0.817
1.000
Customer Placement
One of the most significant cost drivers of marginal distribution costs is the distance
between the customer and the substation. Costs increase as the distance from the
substation increases.
The circuit model takes distance into account by assigning customers to the different
branches ofthe circuit based upon actual customer locations. The actual customer
distances are derived from PacifiCorp's outage management system (CADOPS). The
system is able to accurately trace the flow of electricity from substation to customer as
well as ascertain the exact distance it must travel.
Figure 3 shows the Customer Distribution on the Hypothetical Circuit Branch for
Oregon.
Tab 1
Page 6 of 12
Figure 3 Customer Distribution
I
(A)
I
(B)
Class
I
(C)
I
(D)
I
(E)
I
(F)
(H)
(G)
Hypothetical Circuit Branch
I
1
I
2
I
3
I
4
Branch
I
5
I
6
7
Total
1
Residential
0.90%
0.90%
0.90%
3.62%
3.62%
3.62%
86.45%
100.00%
2
GS
kVV (sec) (23)
1.30%
1. 30°/o
1.30%
3.92%
3.92'%
3. 92°/o
84.34%
100.0u%
3
GS >15 kW (sec) (23)
1.30%
1.30%
1.30%
3.92%
3.92%
3.92%
84.34%
100.00%
4
GS (pri) (23)
1.30%
1.30%
1.30%
3.92%
3.92%
3.92%
84.34%
100.00%
5
GS < 50 kW (sec) (28)
0.76%
0.76%
0.76%
2.08%
2.08%
2.08%
91.45%
100.00%
6
GS 51-100 kW (sec) (28)
0.76%
0.76%
0.76%
2.08%
2.08%
2.08%
91.45%
100.00%
7
GS > 100 kW (sec) (28)
0.76%
0.76%
0.76%
2.08%
2.08%
2.08%
91.45°/o
100.00%
8
GS (pri) (28)
0.76%
0.76%
0.76%
2.08%
2.08%
2.08%
91.45%
100.00%
0.52%
0.52%
1.26%
1.26%
1.26%
94.65%
100.00%
0.52%
0.52%
0.52%
0.52%
1.26%
1.26%
1.26%
94.65%
100.00%
0.52%
2.56%
0.52%
2.56%
0.52%
1.26%
1.26%
1.26%
94.65%
100.00%
2.56%
12.34%
12.34%
12.34%
55.31%
100.00%
1.65%
1.65%
1.65%
95.05%
100.00%
1.65%
1.65%
1.65%
95.05%
100.00%
0~15
GS 0-300 kW (sec) (30)
9
10 GS >300 kW (sec) (30)
11
GS (pri) (30)
12
13
Irrigation
Large GS 1 - 4 MW (sec)
-
14
Large GS 1 - 4 MW (pri)
-
15
Large GS + 4 MW (sec)
-
-
Large customer are on dedicated circuits and are not included here.
Large customer are on dedicated circuits and are not included here.
16 Large GS + 4 MW (pri)
Customer Density
The next significant driver of distribution costs is customer density. The model uses state
specific line and customer statistics to calculate the average number of customers by
circuit branch. Total state distribution line miles and state customers, by class, are
divided by the number of distribution circuits in the state to determine the average length
of the composite circuit (line miles I number of circuits) and the number of customers on
the circuit (customers I circuits). Figure 4 shows the average number of customers
located on each of the seven circuit branches for Oregon.
Figure 4- Oregon Average Customers by Hypothetical Circuit Branch
Class
Average Customers
1 Residential
8.07
8 07
8.07
32.66
32.66
32 66
779.38
901.58
2 GS 0-15 kW (sec) (23)
1.64
1.64
164
4 93
4 93
4 93
106.10
125 80
3 GS >15 kVV (sec) (23)
0.26
0.26
0.26
0.79
0 79
0.79
17.00
2016
4 GS (pri) (23)
0.00
0 00
0.00
0.00
0.00
0.00
0.07
0 08
5 GS <50 kW (sec) (28)
0.07
0.07
0.07
0.18
0.18
0.18
7.80
8.53
6 GS 51-100 kW (sec) (28)
0.05
0.05
0.05
0.14
0 14
0.14
6.00
6.57
7 GS > 100 kW (sec) (28)
0.03
0.03
0.03
0.08
0.08
0.08
3.35
3.66
8 GS (pri) (28)
0.00
0.00
0.00
0.00
0.00
0.00
0.10
0.11
0.41
0.00
0.00
0.00
0.01
0.01
0.01
0.39
10 GS >300 kW (sec) (30)
0.01
0.01
0.01
0.01
0.01
0.01
0.99
1.05
11
GS (pri) (30)
0.00
0.00
0.00
0.00
0.00
0.00
0.09
0.10
12
Irrigation
0.35
0.35
0.35
13
Large GS 1 - 4 MW (sec)
14
Large GS 1 - 4 MW (pri)
15
Large GS + 4 MW (sec)
9 GS 0-300 kW (sec) (30)
-
1.69
1.69
1.69
7.58
13.71
0.00
0.00
0.00
0.19
0.20
0.00
0.00
0.00
012
0.12
40 49
40.49
40.49
929 17
1,082.07
16 Large GS + 4 MW (pri)
17 Total
10 48
10.48
10.48
Load Accumulation
The kW load that a customer or class places on the system influences the size of the
conductor necessary to serve the load. At each point on the circuit, the conductor must be
sized to carry the entire downstream load. At the far ends of the outer branches, loads are
Tab 1
Page 7 of 12
minimal. As you move upstream closer to the substation, the load on the circuit becomes
greater requiring larger conductor sizes. In the model, load can accumulate two ways.
The first occurs as customers accumulate on a branch of the circuit. When enough
customers, or load, accumulate it is necessary to increment up to the next wire size.
Upstream from that point, customer segments increase in cost due to the increase in wire
size. The second method of load accumulation is when several branches converge at a
central point on the trunk of the circuit. The trunk branches must be of adequate size to
carry the load of the customers on that branch plus all downstream branches.
Figure 5 shows the circuit kW loading on each of the circuit branches for Oregon. Loads
are for customers located on that branch. Accumulated loads for branch 6 would be the
combined loads of branches 1, 2, 3 and 6. Accumulated loads for branch 7 would be the
combined loads of all branches.
Figure 5- Oregon Circuit kW Load by Branch
Class
Circuit kW Loads
1
2
3
4
5
6
7
16.6
2.2
1.8
0.0
16.6
2.2
1.8
0.0
GS <50 kW (sec) (28)
11
GS 51-100 kW (sec) (28)
16
11
1.6
GS > 100 kW (sec) (28)
20
00
03
20
0.0
03
16
0.1
13
Residential
GS 0-15 kW (sec) (23)
GS >15 kW (sec) (23)
GS (pn) (23)
8 GS (pri) (28)
9 GS 0-300 kW (sec) (30)
10 GS >300 kW (sec) (30)
11 GS (pn) (30)
12
13
14
15
16
17
Irrigation
-
16 6
2.2
1.8
0.0
11
16
67 2
66
5.4
0.0
3.1
43
16
01
20
00
0.3
16
01
13
13
55
01
07
40
04
62
26
2.2
LargeGS 1 4 MW (sec)
Large GS 1 4 MW (pn)
67.2
6.6
5.4
0.0
3.1
4.3
5.5
O.i
07
4.0
04
62
2.6
22
67.2
6.6
5.4
0.0
3.1
43
55
01
07
40
0.4
62
26
22
Total
1,854.6
142.5d
115.7
137 2
0.3
0.3
134.8
147 4
189.4
207 1
242.7
265.3
5.8
63
53.6
56 6
296.3
313 0
26.9
28.4
28 0
50 6
151 9
159 9
124.0
130 5
-
Large GS + 4 MW (sec)
Large GS + 4 MW (pri)
1,603.21
28.8
28.8
28 8
108 3
108.3
108 3
3,115 0
3,526.2
Circuit Model Cost Assignment
Line statistics for the PacifiCorp service area shovv that the distribution system is
predominately overhead. To calculate the cost of branch construction, miles per branch
is calculated by taking the distance per circuit (total line miles I total number of circuits)
and dividing it by the number of branches per circuit (7 branches, see figure 1). Next,
using an assumption from distribution engineers that the typical outer branches are 35%
single phase, the circuit branch length is split between single and three-phase. The total
branch construction cost can then be calculated by taking the single and three-phase
distances per branch and multiplying them by the one mile construction costs for poles
and conductors, as shown in figure 6. Costs are split between demand and commitment
by assuming that the cost of constructing the branch with the smallest single-phase
conductor and smallest pole is the commitment related portion and all costs above this
amount are demand related. Trunk branches 6 and 7 are shown as 100% three-phase.
Figure 6 shows the circuit costs per mile, costs for each branch and miles per branch
broken out by single and three-phase for Oregon.
Tab 1
Page 8 of 12
Figure 6 - Adjusted Oregon Line Costs per Mile
I
Costs for Branches 1,2,3,4,5
Wire Size
1 Phase -1/0 ACSR
Poles
$
$
$
Conductors
Total
Wire Size
I Poles
Conductors
Total
~hase- 1/0 ACSR
1
Total
160,467
98,518
258 985
7
I
210,458
122,662
333,120
$
$
$
Cost for Branch 7
3 Phase -795 AAC & 477 AAC
294,315
$
559,147
$
$
853.462
Costs for Branch 6
3 Phase- 447 AAC & 410 AAC
277,965
$
252,674
$
530,640
$
Miles per Branch
Single Phase Miles Per Branch
Three Phase Miles Per Branch
5.28
1.85
3.44
Customer Circuit Costs
After calculating the cost per mile for single and three-phase construction for all of the
branches, we compile the data and create a hypothetical circuit model branch cost sheet,
as shown in figure 7. Figure 7 includes the total cost per circuit branch in columns (A)
and (B), and the allocation of total cost between commitment and demand in columns (C)
through (F) for Oregon.
Figure 7 - Oregon Hypothetical Circuit Model Branch Costs
Conductors Type
Branch 1
49,991
49,991
$
24,144
NA
NA
.'L'L\3.38.
i_~§L§;I'J:
_$~- 53,680
$
68 982
$
67,627
$
53,680
$
$
$
24,144
44 838
68,982
~
$
NA
67,627
67,627
~
$
NA
53 680
53,680
$
24,144
1 Phase -1/0 ACSR
3 Phase 1/0ACSR
Total Segments
49,991
$
1_160 461
$ 210.458
~2._1§
L_
$
122,662
$
49,991
92 84Q
142,831
1 Phase -1/0 ACSR
3 Phase- 1/0 ACSR
Total Segments
$
49,991
l__j£()367
$ 210,458
$
$
$
24,144
98 518
122,662
$
49,991
L~JllJHQ
L __1_4,.§.38.
$
142,831
$
68,982
$
$
~
$
24,144
98,518
122 662
$
~
$
49,991
92,840
142 831
$
24,144
~---44,838
$
$
49,991
92,840
142 831
$
210 458
1~~~~~..\L?.l~
$ 122 662
$
L.
$
$_ _ _t99~4E
$
24,144
1 Phase -1/0 ACSR
3 Phase 1/0ACSR
Total seoment
L~J'I:S~'LQ
$ 142 831
Branch 2
$
24,144
$
Branch 3
NA
NA
L__!IT~
~$~--§..3J?.~
$
$
67,627
53 680
Branch 4
1 Phase -1/0 ACSR
3 Phase -1/0 ACSR
Total Segments
•.
49,991
LlliA§l
$
210 458
1 Phase -1/0 ACSR
3 Phase -1/0 ACSR
Total Segments
$
$
$
49,991
160,467
210 458
$
$
24,144
98 518
122 662
3 Phase· 447 AAC & 4\0 AAC
Total Seoments
$
$
277,965
$
$
252,674
252 674
$
$
3 Phase -795 AAC & 477 AAC
Total seoment
$
$
294,315
294,315
$
559,147
559 147
~
$
NA
NA
L ___§J_&_~l L ___g_680
$
68 982
$
67 627
$
53 680
$
~
$
24,144
44,838
68 982
~
~
$
NA
67,627
67 627
$
NA
53,680
53 680
142,831
142 831
$
$
68,982
68 982
$
135,135
135135
~
$
183,692
183 692
142,831
142,831
_$- 68,982
68,982
$
Branch 5
~
~
Branch 6
277 965
~
Branch 7
$
Tab 1
Page 9 of 12
LliM.!H l.,,__'U1_Q.165
$
151 484
$
490 165
Cost Sharing Calculation
As mentioned before, one of the critical factors of cost-responsibility is the location of a
customer or class on the circuit branches. Customer classes that locate on all branches
share cost responsibility for all branches of the circuit including the trunk. Large
industrial customers, who locate on the trunk of the circuit, share cost responsibility for
only the trunk. Cost responsibility is determined by calculating the percentage of
demand, or percentage of customers, by class that share a particular branch of the circuit.
The total branch costs are then multiplied by the share percentage, and the branch costs
are totaled by class. To calculate the total branch cost, the applicable cost of branches 6
and 7 are assigned to customers on branches 1, 2, 3, 4 and 5. Demand costs calculated in
an earlier step are allocated between customer classes at this point. Figure 8 shows this
calculation along with the allocation of branch costs to the individual customer classes
for Oregon. Demand costs are totaled for each customer class and divided by circuit kW
to get demand cost in dollars per kW.
Figure 8 - Oregon Poles Demand Calculations, Cost Assignment
----
-----------~-------
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
Branch
%Demand
Branch 6 Cost
%Demand
Branch 7 Cost
Branch Demand Cost
Total
Class Cost per Branch(4)
Residential
GS 0-15 kW (sec) (23)
GS >15 kW (sec) (23)
GS (pri) (23)
GS <50 kW (sec) (28)
GS 51-100 kW (sec) (28)
GS > 100 kW (sec) (28)
GS (pri) (28)
GS 0-300 kW (sec) (30)
GS >300 kW (sec) (30)
GS (pri) (30)
Irrigation
Large GS 1 - 4 MW (sec)
Large GS 1 - 4 MW (pri)
Large GS + 4 MW (sec)
Larqe GS + 4 MW (Pril
Check Total
$
$
$
$
1
14.78%
19,973
0.82%
1,235
67,627
88 835
1
51,297
6,792
5,516
14
3,482
4,893
6,269
149
913
5,050
458
4,004
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 88,835
$
$
$
$
2
14.78%
19,973
0.82%
1,235
67,627
88 835
2
51,297
6,792
5,516
14
3,482
4,893
6,269
149
913
5,050
458
4,004
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 88,835
$
$
$
$
4
5
3
6
7
14.78%
NA
NA
55.66%
NA
19,973
NA
$ 75,215
NA
NA
$
0.82%
3.07%
3.07%
88.34%
3.07%
1,235 $ 4,652 $ 4,652 $ 4,652 $ 133,822 $
67,627 $ 67,627 $ 67,627
NA
NA
88,835 $ 72,279 $ 72,279 $ 79,868 $ 133,822 $
3
51,297
6,792
5,516
14
3,482
4,893
6,269
149
913
5,050
458
4,004
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 88,835
4
44,845
4,418
3,588
9
2,049
2,880
3,690
88
477
2,637
239
4,166
1,759
1,435
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 72,279
5
44,845
4,418
3,588
9
2,049
2,880
3,690
88
477
2,637
239
4,166
1,759
1,435
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 72,279
6
49,553
4,882
3,965
10
2,264
3,182
4,077
97
527
2,914
264
4,604
1,943
1,586
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 79,868
100.00%
135,135
100.00%
151,484
$/kW
Average
624,754
$ 177.18
Total
Demand Cost
7
68,876 $
362,008
6,122 $
40,217
4,972 $
32,659
12 $
80
5,790 $
22,597
8,136 $
31,756
10,425 $
40,688
247 $
966
2,301 $
6,520
12,728 $
36,065
3,273
1,155 $
1,202 $
26,151
6,528 $
11,988
5,328 $
9,785
Total
PerkW
$ 195.19
$ 238.03
$ 238.03
$ 23803
$ 153.35
$ 153.35
$ 153.35
$ 153.35
$ 115.21
$ 115.21
$ 115.21
$ 516.84
$ 75.00
$ 75.00
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 133,822
$
$
$
-
$
$
-
624,754
Commitment costs are calculated using a similar method. Commitment costs calculated
in an earlier step are allocated to classes using percent of customers on a given branch.
Commitment dollars are totaled by customer class then divided by the number of
customers in the class to get commitment costs in dollars per customer. Figure 9 shows
these calculations for Oregon.
Figure 9-0regon Poles Commitment Calculations, Cost Assignment
Tab 1
Page 10 of 12
Conductors
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
Branch
%Demand
Branch 6 Cost
%Demand
Branch 7 Cost
Branch Demand Cost
Total
Class Cost per Branch(4)
Residential
GS 0-15 kW (sec) (23)
GS >15 kW (sec) (23)
GS (pri) (23)
GS < 50 kW (sec) (28)
GS 51-100 kW (sec) (28)
GS > 100 kW (sec) (28)
GS (pri) (28)
GS 0-300 kW (sec) (30)
GS >300 kW (sec) (30)
GS (Pri) (30)
Irrigation
Large GS 1 4MW(sec)
Large GS 1 - 4 MW (pri)
Large GS + 4 MW (sec)
Large GS + 4 MW (pri)
Check Total
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(A)
(B)
(C)
1
14.78%
27,150
0.82%
3,997
53,680
84,827
2
14.78%
27,150
0.82%
3,997
53,680
84,827
3
4
5
6
7
14.78%
NA
55.66%
NA
NA
27,150
NA
NA
$ 102,243
NA
$
0.82%
3.07%
3.07%
88.34%
3.07%
3,997 $ 15,053 $ 15,053 $ 15,053 $433,013 $
53,680 $ 53,680 $ 53,680
NA
NA
84,827 $ 68,734 $ 68,734 $117,296 $ 433,013 $
1
48,982
6,486
5,267
13
3,324
4,672
5,986
142
872
4,822
438
3,824
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2
48,982
6,486
5,267
13
3,324
4,672
5,986
142
872
4,822
438
3,824
-
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 84,827
$ 84,827
$
3
48,982
6,486
5,267
13
3,324
4,672
5,986
142
872
4,822
438
3,824
-
$
$
$ 84,827
(D)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(E)
4
42,645
4,202
3,412
8
1,949
2,739
3,509
83
453
2,507
228
3,962
1,672
1,365
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 68,734
5
42,645
4,202
3,412
8
1,949
2,739
3,509
83
453
2,507
228
3,962
1,672
1,365
$
$ 68,734
(F)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(G)
6
72,775
7,170
5,823
14
3,326
4,673
5,988
142
774
4,279
388
6,761
2,854
2,329
$
$
$117,296
(I)
(H)
100.00%
183,692
100.00%
490,165
942,258
Total
7
Demand Cost
$ 222,865 $ 527,877
$ 19,810 $
54,840
$ 16,087 $
44,533
$
39 $
109
$ 18,733 $
35,930
$ 26,326 $
50,492
$ 33,731 $
64,695
$
801 $
1,535
$ 7,446 $
11,742
$ 41,186 $
64,945
$ 3,738 $
5,895
$ 3,890 $
30,046
$ 21,122 $
27,321
$ 17,239 $
22,299
$
$
$
$
$433,013 $ 942,258
$/kW
average
$ 267.22
Total
PerkW
$ 284.63
$ 324.57
$ 324.57
$ 324.57
$ 243.83
$ 243.83
$ 243.83
$ 243.83
$ 20747
$ 20747
$ 20747
$ 593.81
$ 170.91
$ 170.91
$
$
Large Industrial Customers
Distribution studies have shown that very large industrial customers are not placed on a
circuit in the same manner as residential or smaller commercial and industrial customers.
Rather the customer is located very close to a substation (the average distance in Oregon
is 2/3 of a mile) and has a dedicated circuit for their exclusive use. Since they have a
dedicated circuit, they do not share in the costs of other common distribution
investments, but they are responsible for the entire cost of the dedicated circuit. Dividing
the total cost of a 2/3 of a mile circuit by the customer's kW determines the demand cost
in dollars per kW for these customers. Table 10 shows this calculation for Oregon.
Table 10- Oregon Dedicated Circuit Trunk Costs for Large Customers
Voltage Delivery
Large GS + 4 MW (pri)
Po!es
1 Construction Cost Per Mile
2 Average Trunk Length
3 Total Construction Cost
$
$
Large GS + 4 MW (sec)
Conductor
55,691 $ 105,804
0.67 miles
37,313 $
70,889
4 Customer Peak Demand
4,532 kW
5 Demand Cost $/kW
$8.23
Po!es
$
$
Conductor
55,691 $ 105,804
0.67 miles
37,313 $
70,889
3,097 kW
$15.64
$12.05
$22.89
Summary
The final step in the circuit model is to bring the various results together in a single
summary page. Table 11 shows the results calculated earlier in the study. Note that the
$/customer and $/circuit kW is the distribution investment to serve that customer and not
the price that the customer is expected to pay.
Tab 1
Page 11 of 12
Table 11 - Oregon Summary of Results
Commitment
Class
$/Customer
Poles
Conductor
Residential
$
882 45
$
426 19
$
195 19
$
284.63
901.6
1,854 63
$
362,008
$
GS 0-15 kW (sec) (23)
$
1,076.48
$
519.90
238.03
$
324.57
125 8
168.96
$
54,840
$
1,076 48
$
519 90
238 03
$
324.57
20.2
137.21
$
$
40.217
GS >15 kW (sec) (23)
$
$
32,659
$
44,533
GS (pri) (23)
$
1.07648
$
519.90
$
238.03
$
324 57
0.1
0 34
$
80
$
109
GS < 50 kW (sec) (28)
$
673 89
$
325 46
$
153 35
$
243.83
8.5
147.36
$
22,597
$
35.930
GS 51-100 kW (sec) (28)
$
673 89
$
325 46
$
153.35
$
243 83
6.6
207.08
$
31,756
$
50,492
GS > 100 kW (sec) (28)
$
673.89
$
325.46
$
153.35
$
243.83
3.7
265.33
$
40,688
$
64,695
GS (pri) (28)
673 89
$
325.46
$
153.35
$
243 83
0 1
6.30
$
966
$
1,535
492.62
$
237.92
$
115 21
$
207.47
04
56.60
$
6,520
492.62
$
237.92
$
115 21
$
207.47
11
313.04
$
36,065
$
$
11,742
GS >300 kW (sec) (30)
$
$
$
GS (pri) (30)
$
492.62
$
237.92
$
115.21
$
207.47
0.1
28.41
$
3,273
$
5,895
lrngation
$
2,438.27
$
1,177.59
$
516.84
$
593.81
13 7
50 60
$
26,151
$
30,046
Large GS 1 - 4 MW (sec)
$
320 55
$
154.81
$
75.00
$
170.91
02
159.85
$
11,988
$
27,321
Large GS 1 - 4 MW (pn)
$
320.55
$
154.81
$
75.00
$
170.91
0.1
130.47
9,785
$
22,299
$
923.98
$
446.25
$
177.18
$
267.22
1,082.1
3,526.2
$
$
624,754
$
942.258
GS 0-300 kW (sec) (30)
Total.
Tab 1
Page 12 of 12
527,877
64,945
Table 1
PacifiCorp
Oregon Marginal Cost Study
Summary of Marginal Costs
Demand & Energy in Mills/kWh
December 2014 Dollars
(A)
(B)
(D)
(C)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
(F)
Demand & Ener•
Ener
Line
(E)
1 Year
10 Year
20 Year
1 Year
10 Year
20 Year
37.71
117.05
119.77
37.71
37.72
36.61
113.88
112.18
105.48
116.59
114.89
107.77
Description
I
Res - Schedule 4
(sec)
37.71
48.32
51.05
GS - Schedule 23
0-15 kW
15+ kW
Primary
(sec)
(sec)
(pri)
37.71
37.72
36.61
48.32
48.32
47.07
51.05
51.05
49.61
GS - Schedule 28
0-50 kW
51-100 kW
> 101kW
Primary
(sec)
(sec)
(sec)
(pri)
37 71
37.71
37.71
36.66
48.32
48.32
48.32
46.95
51.05
51.05
51.05
49.61
37.71
37.71
37.71
36.66
116.25
110.34
109.66
104.61
118.97
113.06
112.38
107.26
GS - Schedule 30
0-300 kW
301+ kW
Primary
(sec)
(sec)
(pri)
37.72
37.71
36.65
48.32
48.32
46.96
51.05
51.05
49.61
37.72
37.71
36.65
101.75
105.95
104.26
104.48
108.67
106.91
LPS - Schedule 48T
1-4 MW
1-4 MW
> 4MW
> 4MW
(sec)
(pri)
(sec)
(pri)
37.71
36.65
37.72
36.65
48.32
46.96
48.33
46.96
51.05
49.61
51.05
49.61
37.71
36.65
37.72
36.65
104.70
97.63
95.41
93.11
107.42
100.27
98.11
95.75
i(trn)
35.84
45.92
48.51
I
35.84
77.10
79.68
(sec)
37.71
48.32
51.05
I
37.71
106.41
109.14
Trans
Schedule 41-lrrigation
I
I
Sources:
(A) Tab 2.13 (1 Year MC:) ·1 Year Marginal Costs by Load Class'
(B) Tab 2.11 (10 Yr FC:) '10 Year Marginal Cost By Load Class'
Tab 2.10 (10 Yr UC:) '10 Year Run Costing Inputs and Customer Data Marginal Unit Costs'
(C) Tab 2.4 (Table 4:) '20 Year Marginal Cost By Load Class December 2014 Dollars'
Tab 2.3 (Table 3:) '20 Year Costing Inputs and Customer Data Marginal Unit Costs'
(D) Column (A)
(E) Tab 2.11 (10 Yr FC:) '10 Year Marginal Cost By Load Class'
Tab 2.10 (10 Yr UC:) '10 Year Run Costing Inputs and Customer Data Marginal Unit Costs'
(F) Tab 2.4 (Table 4:) '20 Year Marginal Cost By Load Class December 2014 Dollars'
Tab 2.3 (Table 3:) '20 Year Costing Inputs and Customer Data Marginal Unit Costs'
Energy costs include both generation and transmission energy-related costs.
Tab:2.1
(Table 1)
Table 2
PacifiCorp
Oregon Marginal Cost Study
Summary of Marginal Costs
Commitment and Billing in $ I Customer I Month
December 2014 Dollars
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
Description
(A)
(B)
1 Year
10 & 20 Year
1&3 Phase
1&3 Phase
Res - Schedule 4
(sec)
$15.59
$40.93
GS - Schedule 23
0-15 kW
15+kW
Primary
(sec)
(sec)
(pri)
17.82
30.55
179.67
50.68
69.95
198.79
GS -Schedule 28
0··50 kW
51-100 kW
> 101kW
Primary
(sec)
(sec)
(sec)
(pri)
34.00
35.16
72.88
182.98
106.24
115.86
158.69
194.95
GS - Schedule 30
0-300 kW
301+ kW
Primary
(sec)
(sec)
(pri)
85.85
127.38
195.89
187.16
228.92
204.64
Total
1-4 MW
1-4MW
> 4MW
> 4MW
T1·ans
(sec)
(pri)
(sec)
(pri)
(trn)
396.74
254.22
396.74
254.22
4,465.95
496.78
259.91
491.08
254.22
4,465.95
Schedule 41-lrrigation
Schedule 41-lrrigation
(sec)
(sec)
10.85
10.85
127.80
127.80
Footnote:
Short-run commitment and billing costs include the cost of metering, meter overhead and
maintenance, service drops, service drop overhead and maintenance, customer accounting and informational
expenses, and billing expenses.
Sources:
Tab 2.7 (Table 7} 'Marginal Distribution & Billing Costs By Load Size'
Tab: 2.2
(Table 2)
Table3
PacifiCorp
Oregon Marginal Cost Study
20 Year Costing Inputs and Customer Data
Marginal U111t Costs
December 2014 Dollars
(A)
Residential
line
Description
(sec)
(B)
(D)
(C)
(E)
General Service ~ Schedule 23
0-15kW
15+kW
Primary
(sec)
(sec)
(pri)
(F)
0-50 kW
(sec)
(G)
(I)
(H)
General Service - Schedule 28
> 101kW
51-100 kW
(sec)
(sec)
Pnmary
(pn)
(K)
(J)
(L)
General Serv1ce ~ Schedule 30
0-300 kW
301+ kW
Primary
(sec)
(sec)
(pn)
(M)
1-4MW
(sec)
(N)
(0)
(0)
lmgat1on
Sch41
(P)
Large Power Service Schedule 48T
> 4MW
1-4MW
> 4MW
(pri)
(sec)
(pri)
Trans
(tm)
(sec)
Billing Unrts
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
Demand
Peak MW @ Meter
System
Distribution
Transformer
Demand Loss Factor
Peak MW @ Generator
~
Energy - Annual MWh
Energy Loss Factor
Energy - Annual MWh
System
Distribution
Transforrner
@Meter
@Generator
Customer
Annual Customers
Average Customers
849
976
3,327
91
89
184
79
72
127
11106
1.1106
11106
943
1,083
3,695
102
99
205
87
80
141
5,379.569
11001
5,917,848
589.432
1.1001
648,411
510,378
11001
561,446
485,586
63,644
10,200
$100.30
$165.04
$100 65
$2 80
$100 30
$165 04
$112.55
$2.80
$100 30
$1135.04
$112 55
$2 80
0
0
2
1 0792
0
0
N/A
1,147
1 0690
1,226
43
73
78
141
101
109
189
133
3
3
19
140
234
11106
11106
11106
81
86
157
112
121
210
147
155
437,292
11001
481,048
662,698
11001
729,008
4,489
3,455
$100.30
$165.04
$88 78
$2 80
$100.30
$165 04
$88 78
$2 80
1 0792
259
874.287
11001
%:::1
28
30
49
153
165
259
14
15
22
1 0792
78
84
132
11106
65
69
102
1 0792
7
6
14
1 0426
26
27
150
11106
3
4
NIA
31
33
54
169
183
288
15
16
NIA
86
93
147
18,574
1 0690
19,856
204,293
1.1001
224,734
1,041,871
1.1001
1.146,121
91,598
10690
97,922
524,179
1.1001
576,628
467.708
10690
499.998
51.567
1.1001
56.727
1.061,765
1 0690
1.135069
829,896
1 0453
867.465
238,210
11001
262.045
56
200
515
47
102
61
2
32
9
8.046
3.920
$100 30
$165.04
$88.78
$000
$100.30
$165.04
$78.07
$2.80
$100 30
$165.04
$78.07
$100 30
$165.04
$78.07
$0.00
$100.30
$165.04
$67 03
$2 80
$100.30
$165.04
$67 03
$0.00
$100.30
$165.04
$3672
$2.80
$100 30
$165.04
$3512
$0.00
$100 30
$165.04
$0.00
$0.00
$100 30
$165.04
$191 32
$2.80
8
7
15
1.0792
94
0
164
11106
71
74
NIA
11106
151
150
228
163
162
NIA
97
NIA
NIA
11106
29
30
167
Unit Costs
Generation
Transmission
Poles, Cond., Subst
Transformers
Energy - @ Generator
Generation
Transmiss1on
Poles
Condudor
Transformers
Service Drop
Meters
Meter Reading
Billing & Collections
Uncollectables
Customer Service I Other
Total Commitment & Billing
Sources:
Lines 1 -3
Lines 5 & 13
$ I System Peak kW
$ I System Peak kW
$1Dist kW
$1XfmrkW
$100.30
$165 04
$11255
$000
$100 30
$165 041
$88 78
$2 80
$2.80
I
i
$/kWh
$/kWh
$/Cust
$I Cust
$/Cust
$/Cust
$I Cust
$I Cust
$ I Cust
$I Cust
$1 Cust
$I Cust
/Year
I Year
/Year
/Year
I Year
I Year
I Year
I Year
I Year
I Year
$0 04337
$0.00304
$0 04337
$0 00304
$0 04337
$0 00304
$0 04337
$0 00304
$0 04337
$0 00304
$0 04337
$0 00304
$0 04337
$0 00304
$0 04337
$0 00304
$0.04337
$0 00304
$0.04337
$0 00304
$0.04337
$0 00304
$0 04337
$0 00304
$0.04337
$0 00304
$0.04337
$0.00304
$0.04337
$0 00304
$0 04337
$0 00304
$0.04337
$0 00304
$126.83
$61.26
$11605
$98.36
$1848
$16 74
$3418
$1036
$895
$49121
$154.72
$74.72
$164 88
$127.15
$1974
$2378
$3247
$1.87
$8.86
$608.19
$154 72
$74.72
$24334
$265.42
$:34 25
$23.78
$3247
$1.87
$8 86
$839 43
$154 72
$74 72
$000
$000
$2,089.04
$23 78
$3247
$1 87
$8.86
$2,38546
$9686
$46 77
$72323
26761
33.59
4136
35.20
20.25
9.94
$1,274.83
$9686
$46 77
$82473
278 79
3636
41 36
3520
2025
994
$1,390 27
$96 86
$46 77
$886 16
536.10
231 67
41 36
35.20
20 25
9.94
$1 904 32
$96.86
$46 77
$0.00
$70.81
$34.19
$1,110.75
535.87
232.62
7100
3520
141.35
14.14
$2,245.93
$7081
$34.19
$1,11340
1,03404
23287
71 00
3520
141 35
1414
$2747 00
$7081
$3419
$0.00
$4608
$2226
$1,13209
$3,498 63
$300 67
185 03
130.21
61326
3310
$5,96133
$46 08
$2226
$000
$000
$2,089 04
$185 03
$13021
$613 26
$3310
$3,118 97
$0 00
$0.00
$1,132.09
$3,498 63
$300 67
$185.03
$130 21
$613 26
$3310
$5,892 99
$0.00
$000
$000
$0.00
$2,089 04
$18503
$130 21
$613 26
$33.10
$3,050 64
$0.00
$000
$000
$0.00
$52,630
$185 03
$130.21
$613 26
$33.10
$53,591
$35044
$169.25
$883.68
$0.00
$33.93
$5241
$3247
$1.71
$9.66
$1,533.55
2,089 04
4136
3520
2025
9.94
$2.33943
.
2,089 04
71 00
3520
141 35
1414
$2,455 73
Tab 17_4 {Cust Data 4:) 'Customer loads12 Months Ended December 2014'
Tab 16_1 (losses:) ·Energy Loss Factors'
lines 12 & 17 Tab 17-2 (Cust Data 2·) ·eustomers and MWh's12 Months Ended December 2014- Normalized'
Tab 3.1 {Capacity:) ·Marginal Capacity Costs Based on Avoided Capacity Costs'
Line 22
Line 23
Tab 5_1 (Transm1:) ·Marginal Transmissfon Investment and O&M Expenses'
Line 24
Tab 2_7 (Table 7:) ·Marginal Distribution & Billing Costs By Load Size'
Line 28
Tab 4.1 (Energy:) ·Marginal Generation Energy Costs'
Line 29
Tab 2.6 (Table 6.} ·Marginal Cost of Transmission Investment and Associated Expenses'
Lines 31 -39 Tab 2.7 (Table 7_) ·Marginal Distribution & Billing Costs By Load S1ze'
Tab. 2,3
(Table 3)
Table4
PaafiCorp
Oregon Marg1nal Cost Study
20 Year Marg1nal Cost By Load Class
December 2014 Dollars
(Dollars 1n DOD's)
(A)
(B)
Residential
Line
Descriotion
Total
(sec)
(C)
(E)
(D)
General Serv1ce - Schedule 23
0-15kW
(sec)
15+ k\N
(sec)
Primary
(pn)
(F)
(G)
(I)
(H)
(J)
General Power- Schedule 28
0-50 kW 51-100 kW > 101kW
Primary
(sec)
(sec)
(sec)
(pri)
(l)
(K)
General Power- Schedule 30
0-300 kW
301+ kW Primary
(sec)
lsecl
(on)
(M)
(N)
(0)
(0)
(f')
Laroe Power Service - Schedule 48T
1-4MW
(sec)
1-4 MVI
(pfi)
>4MW
(sec)
>4MW
(pri)
Trans
(tm)
(R)
(S)
lrr~
Sch 51 53 54
Streetlighting
(sec)
Sch 41
(sec)
Demand Related Ma!];Jinal Cost
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
Generation
Transmission
Distribution
Poles
Conductor
Substations
Subtotal Pole, Cond, Subs
Transfonners
Distribution subtotal
Total Demand Related
(lines 1+2+9)
$215,252
$354,191
$94,605
$155,669
$10,187
$16,763
$8,758
$14,411
$17
$28
$8,171
$13,445
$11,251
$18.514
$14.790
$24.337
$285
$469
$3,092
$5,088
$16,990
$27,956
$1.508
$2.481
$8,647
$14,229
$7,079
$11,649
$806
$1,326
$16,371
$26,937
$9.779
$16,091
$2,916
$4,798
$52,618
$79,429
$70,546
$202 593
$14.967
$217,560
$30,387
$44,324
$34,339
$109 050
$10 359
$119,409
$3,377
$4,603
$3,128
$11109
~
$11,682
$2,742
$3,738
$2,540
$9 021
~!M
$9,415
$7
$9
$6
$2,667
$4239
$3834
$10 740
$589
$11,329
$3,417
$5433
$4,913
$13 762
$78
$125
$113
$798
$1,819
$2,347
$4964
$0
$0
$0
E!
W1
E!
$1,260
$6,671
$4,964
$11
$23
$218
~
$43
$295
$191
$364
$5,126
$5681
$317
$3,030
$5,452
$5,796
$14 277
~
$15,085
$1,006
$2,294
$2,960
$6260
$14,489
$548
$986
$1,048
$2582
~
$2,734
$268
$481
$511
$1 260
$22
$1,897
$3,017
$2,728
$7 642
$441
$8,083
$5,681
$0
$2,196
$2,523
$937
$5.656
$468
$6,124
$787,003
$369,683
$38,632
$32584
$67
$29,699
$41,094
$53.616
$1,071
$10,914
$60,031
$5,249
$29,547
$23,692
$2,427
$48,989
$25,870
$13,838
$616.337
$43168
$659,505
$256,657
$17 976
$274,633
$28,122
$1 970
$30.091
$24,350
$53
$20.863
$1461
$22,324
$31.617
$2 214
$33.831
$41.712
$2.921
$44,633
$861
~
$921
$9,747
~
$10,429
$49,707
$3.481
$53,189
$4,247
$25,008
$1.752
$26,760
$21,685
~
$23,204
$2,460
$49.228
lill
lM1§
$4.544
$2,633
$52,676
$37.622
$2.635
$40.257
$11,365
flg§
$12,161
$80,224
$37,186
$85,223
$62,761
$12,746
$10,598
$19,550
$5,608
$5.163
$319,060
$61 587
$29,746
$56,351
$47,762
$8 972
$8131
$16,596
$5,029
$4.347
$238,521
$9,847
$4,756
$10,495
$8,093
$1,256
$1.513
$2,066
$119
1§§1
$38,709
$435
$211
$3.247
$1,201
$151
$186
$158
$91
M§
$5,724
$334
$162
$2,849
$963
$126
$143
$122
$70
~
$4,803
$186
$90
$1,706
$1.032
$446
$80
$68
$39
$6
$3
$0
$0
$117
$2
$2
$1
$37
$17
$573
$532
$120
$37
$18
$73
$3
$1
$0
$0
$98
$3
$2
$7
$0
$0
$0
$0
$474
$2
$1
$6
ll
$2,819
$1,362
$7,111
$0
$273
$205
$127
$7
.$}§
$11,942
$3,362
$61
$69
$132
$3
$1
$0
$0
$127
$11
$8
$37
.$;;
$190
$0
$0
$0
$0
$67
$6
$4
$20
lli
$4
$3
$115
$357
$31
$19
$13
$63
~
$608
$0
$0
$3
$7
$1
$0
$0
$1
$3,665
$14
$7
$222
$107
$47
$14
$7
$28
~
$449
$831,589
$397,359
$482,954
$19,550
$23,344
$5163
$1,759,960
$351,262
$173,645
$314,855
$16.596
$17,103
$4 347
$877,808
$38309
$18,733
$44,872
$2,066
$2,769
1§§1
$107,313
$42.868
$20,728
$15,638
$122
$269
$56.502
$27,258
$17,503
$68
$526
$1,146
$529
$325
$2
$119
$1,033
$72
$3,493
$25
$5
~
lli
ll
$79,659
$101.876
$2.123
$12,839
$5,771
$3,084
$7
$61
~
$21,764
$5,608
$1,765.568
$5,029
$882,837
$119
$107 432
$70
$79,729
$39
$101 915
$1
$2124
$21J92
$0
$4,635_
m
E!
llii
ruz
E!
E!
E!
E!
Energ~
Related Marginal Cost
Generation Energy Related
Transmission Energy Related
Total Energy
lliQ§
.H
$26.055
$57
$1,578
$763
$2.482
$2,708
$349
$243
$331
$19
$7
$3
$0
$0
$90
$1
$1
$0
.$2QI
$1,033
m
$1,106
Customer Related Mar:ginal Cost
Poles
Conductor
Transformers
Service Drops
Meters
Meter Reading
Billing & Collections
Uncollectables
Customer Service I Other
Total Commttment & Billing Rei.
.$ill)
E!
$8,563
$103
$33,108
$16,116
$16,945
$331
$592
$70
$32
$32
$1
$91
E
ll
$1,414
$115
$66.697
$31,437
$16,245
$18
$156
$5,755
$2,778
$1.264
$2
$102
E!
ll
E!
$12
$98
$482
$28,764
$13,168
$4,969
$8
$139
.$;;
$47,049
$3,266
$1,498
$305
$0
$1
$65.599
$30,385
$5,681
$4
$73
$47.401
$18,726
$0
$1
$475
$37
$47 086
$2
$2
$25
$0
E
$3,529
Total Revenue@ Full MC
Generation
Transm1ssJon
Distribution
Customer - Billing
Customer- Metering
Customer - Other
Revenue (less Uncollectables)
Customer - Uncollectables
Total Revenue
I
.$ill)
E!
$67,183
$226
$29.034
$14.906
$13,177
$158
$336
M§
$57,657
$19
$67,202
$0
$226
$91
$57.748
$28
E
ll
$114.562
$9,901
$33,655
$15,981
$7.150
$13
$50
~
$56.853
$73
$114,635
$7
$63
$9,9~~5
E!
ll
E!
$5,071
$101742
$66.604
$14,281
$5.594
$17,415
$127
$478
.$}§
$37,934
$1
$20
$6
$5 072 !.llQ,tzE;2 $66 609
$7
$37,940
Source: Tab 2.3 {Table 3:) ·20 Year Costing Inputs and Customer Data Marginal Unit Costs'
Tab 2.7 (Table 7:) 'Marginal Distribution & Billing Costs By Load S1ze'
Line 1
Generation (Table 3. Row 7) x (Table 3, Row 22)/1000
line 2
Transmission (fable 3, Row7) x (fable 3, Row23)/1000
Lines 4--6
Poles, Cond_, Subst (Table 3, Row 8) x {Table 7, Row 1 - 3} x (1 + .423) (Dist OM, Row 32)
Transformers (Table 3, Row 9} x (Table 7, Row 7) x (1 + 423) (01st OM. Row 32)
Une 8
Unes 15--16 Energy Related (Table 3, Row 14) x (Table 3, Row 28- 29)
Lines20-29 Commitment Related (Table 3, Row 17) x (Table 7, Row 13- 27) including O&M Adders
Tab 2.4
{Tab!e 4)
E
$4,635
Table 5
PacifiCorp
Oregon Marginal Cost Study
Summary of Marginal Generation Costs
In Nominal Dollars
(A)
(B)
(C)
Resource Cost
(Mills I kWh)
Energy Only
(Mills I kWh)
Capacity Only
(Mills I kWh)
92 0~1
93.96
95.40
97.07
98.91
100.78
34.28
38.28
40.09
42.19
44.90
47.47
47.83
49.94
53.33
55.17
54.79
57.07
59.20
61.15
62.74
64.12
64.99
66.05
67.30
68.57
22.68
23.13
23.57
24.02
24.48
24.92
25.34
25.80
26.26
26.74
27.22
27.71
28.20
28.74
29.29
29.84
30.41
31 02
31.61
32.21
$100.34
$102.34
$104.29
$106.28
$108.30
$110.25
$112.12
$114.14
$116.19
$118.28
$120.41
$122.58
$124.77
$127.15
$129.57
$132.02
$134.54
$137.24
$139.84
$142.50
@ 7.66%
56.96
34.28
22.68
$100.34
2014-2018 5 yearSum of PV Costs
I
Annual Cost
I
@ 7.66%
@ 22.27%
273.65
60.94
171.67
38.23
101.98
22.71
$451.17
$100.48
2014 - 2023 10 years Sum of PV Costs
I
Annual Cost
I
@ 7.66%
@ 12.66%
502.17
63.58
322.97
40.89
179.20
22.69
$792.80
$100.37
2014 - 2033 20 years Sum of PV Costs
I
Annual Cost
I
@ 7.66%
@ 804%
821.46
66.04
539.47
43.37
281.99
22.67
$'1,247.49
$100.30
Year
(D)
Capacity Only
_ _($1kW)
(8)+(1~
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2014
I
56.96
61.41i
63.66
66.21
69.38
72.39
73.17
75.74
79.59
81.91
82 01
84.78
87.40
89.8~1
1 yearSum of PV Costs
Footnotes:
(B) Tab 4.1 (Energy:) 'Marginal Generation Energy Costs'
(C) Tab 3.1 (Capacity:) 'Marginal Capacity Costs Based on Avoided Capacity Costs'
(D) Tab 3.1 (Capacity:) 'Marginal Capacity Costs Based on Avoided Capacity Costs'
Tab: 2.5
(Table 5)
Table 6
PacifiCorp
Oregon Marginal Cost Study
Marginal Cost of
Transmission Investment and Associated Expenses
Line
1
2
3
4
5
6
7
8
9
10
Item
Growth Related Investments- (2014 to 2018 in $000's)
System Growth MW's fmm 2014 to 2018
Marginal Investment
(growth invest I k\N)
Annualized Investment
Admin. & General Factor
Annual O&M Expenses
Annualized Marginal Cost
8.00%
X 1.33%
X 1.415%
X
$'s
$632,039
364 MW
$1,736.37 I kW
138.91 I kW
23.09
24.57 lkW
$186.57 I kW
11
12
13
14
15
16
Marginal Cost of Demand-Related Transmission
Marginal Cost of Energy-Related Transmission (Line 10 - Line 12)
Marginal Cost of Energy-Related Transmission
$21.521 (8760 x 80.87% LF))
$165.04 I kW
$21.52 I kW
$0.00304 I kWh
Sources:
Tab 5.2 (Transm2:) '2014-2018 Forecasted Transmission'
Tab 5.1 (Transm1 :) 'Marginal Transmission lnvE~stment and O&M Expenses'
Tab: 2.6
(Table 6)
Table?
PacifiCorp
Oregon Marginal Cost Study
Marginal Disllibution & Billing Costs By Load Size
2014 Dollars
(A)
Residential
Line
Description
(sec)
(B)
(C)
(D)
(E)
General Servie<> - Schedule 23
0-15kW
15+ kW
Primary
(sec)
(sec)
(Eri)
(F)
(G)
(I)
(H)
General Serv1ce Schedule 28
51-100 kW > 101kW
Primary
0-50 kW
(sec)
(sec)
(pri)
(sec)
(J)
(l)
(K)
General Serv1ce - Schedule 30
301+ kW
0-300 kW
Primary
(sec)
(pri)
(sec)
1-4MW
(sec)
(N)
(M)
(P)
(0)
Large Power Service Schedule 48T
> 41111W
1-4MW
> 4MW
(pri)
(sec)
(pri)
Trans
(trn)
(0)
lrrg
Sch 41
i!
(sec)
!I
1
Demand Related Costs ($/kW)
I
i
1
2
3
4
5
Poles
Conductors
Substation
Dist. O&M @of Total Investment
Total$/ D1st kW
42 30%
19.71
28.75
22.27
29.92
$100.65
24 04
3278
22.27
33_46
$11255
2404
32 78
22.27
3346
$112.55
1.97
0.83
$2.80
197
0_83
$2.80
197
083
$2.80
24.04
32.78
22.27
33.46
$112.55
15.49
$24.63
22.27
26.39
$88.78
1549
24.63
22.27
26.39
$88.78
1549
24.63
22.27
26.39
$88.78
1549
24.63
22.27
26.39
$88.78
11.64
20 95
2227
2321
$78.07
11 64
20 95
22.27
23.21
$78_07
11.64
20.95
22.27
23.21
$78.07
7.57
17.26
22.27
19.93
$87.03
7 57
17 26
22.27
19_93
$67_03
1.22
2.31
22.27
10.92
$3672
0.83
1.58
22.27
10.44
$35.12
1.97
0.83
$2.80
197
0.83
$2.80
1_97
083
$2_80
NA
NA
1.97
0.83
$2.80
1.97
0.83
$2_80
NA
NA
1.97
0.83
$2.80
NA
NA
1.97
0_83
$280
NA
NA
NA
NA
5220 1
59.981
NA
NA
22.271
5687
$191321
6
7
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Transfonners
42 30%
Dist. O&M @of Total Investment
Total$/ Transfonner kW
NA
NA
$0.00
$0.00
$0.00
$000
NA
NA
-
-
l
Commitment Related Costs ($/Customer)
Poles
Conductors
Transformers
42.30%
Dis!. O&M@ of Total Investment
Total Commrtment Related
Billing Related Costs ($/Customer/Yr)
Service Drop
Service Drop O&M @
42 30%
Meter
MeterO&M at
6586%
Meter Reading
Billing & Collections
Uncollectables
Customer Service I Other
Total Billing Rela1ed
Monthly Billing Related (line 281 12)
Total Distribution (Comm & Billing Costs)
Line 17 +Line 28
Monthly Commrtment & Bill (line 33 I 12)
89.13
43.05
81.55
90.41
$304.14
69.12
29.24
11.14
7.34
16.74
34.18
10.36
8.95
$187.07
108.73
52.51
115.87
117.22
$394.33
108.73
!:12.51
17'1.01
1L,054
$47'279
89.35
3780
11.90
7_84
23.78
32.47
187
8.86
$213.87
186.52
7890
20.65
1360
23.78
32.47
187
886
$366 65
10873
52.51
NA
68.20
$229.44
NA
NA
$1,259.52
829.52
23.78
32.47
1.87
8.86
$2,156.02
6807
32.87
508.24
257.68
$866.86
188.06
79.55
20.25
13.34
41.36
35.20
20.25
9.94
$407.96
6807
32.87
579.57
287.86
$968.37
195.92
82.87
21.92
14.44
41.36
35.20
20.25
9.94
$421.91
68.07
32.87
622.74
306.12
$1.029 80
376_74
159.36
139.68
91.99
41_36
35.20
20.25
9.94
$874.53
68.07
32.87
NA
42.70
$143.64
NA
NA
1,259.52
829.52
41.36
35.20
20.25
9.94
$2,195.80
4976
24.03
780.57
361 39
$1,215.75
376.58
159.29
140.25
9237
$7100
$35.20
$141.35
14.14
$1,030.18
49.76
2403
782.43
362.18
$1,218 40
726.66
30738
140.40
92.47
$71.00
$35.20
$141_35
14.14
$1,528 60
49.76
24.03
NA
31.21
$105.00
NA
NA
1,259.52
829.52
$71.00
$35.20
$141.35
14.14
$2,350.73
32.38
15.64
795.57
356.84
$1,200.43
$2,456.63
1,040.00
$181.28
119.39
165.03
130.21
613.26
33.10
$4,760.90
NA
NA
NA
NA
32 38
1564
NA
20 31
$68 33
NA
NA
$1.259 52
82952
18503
130.21
613.26
33_10
$3.050 64
79557
33653
$1.132.10
$2,458.63
1,040.00
$181.28
119.39
185.03
130.21
613.26
33.10
$4.760.90
$15.59
$17.82
$30 55
$179.Ei7
$34.00
$35.16
$7288
$182.98
$85.85
$127 38
$195 89
$396.74
$254 22
$396.74
$491.21
$608 20
$839 43
$2,385.46
$1,274.82
$1,390.28
$1,904.33
$2,339.44
$2,245.93
$2,747 00
$2_455.73
$5,961.33
$3,11897
$5.893.00
$40.93
$50.68
$69 95
$198.79
$106 24
$115.86
$158.69
$194.95
$187 16
$228 92
$204.64
$496 78
$259 91
$491.08
NA
24627
118 94
62100
417 17
$1.403.38
NA
NA
NA
NA
$1,259.52 $31,731.44
829.52 20,898.33
185.03
185.03
130.21
130.21
613.26
613.26
33.10
33.10
$3,050.64 $53,591.37
20.46
13.47
52.41
32.47
1.71
9.66
$130.18
$4,465.95
$10 85
$1,533.55
$254.22
$254.22
$4,465.95
Tab 11.5 (Meters 5:) "Distribution Meters Expense Loading Factor' ( for65.86% Factor)
Tab 13.1 (CUst Exp Sum:) ·summary of Customer Accounting Expense By Schedule'
Tab 2.7
NA
NA
$3,050.64 $53,591.37
Sources· Llnes
Lme 1 - 2
Tab 7.1 (PC 1:) 'Hypothetical Circuit Study Results Annual Demand and Commitment Costs'
L1ne 3
Tab 6.1 (Oist Sub 1:) 'Distribution Substation Costs I kW
Line 4
Sum of lines 1 to 3 multiplied by 42 30%
Tab 9.1 (Dist OM·) 'Distribution O&M Expense Loading Factor as a Percent of Dist_ Plant' ( for42.30% Factor)
L1ne 7
Tab 8.2 (XFMR 2:) 'Transformer Demand Costs'
Lme 13- 14 Tab 7.1 (PC 1:) 'Hypothetical Circuit Study Results Annual Demand and Commitment Costs'
L1ne 15
Tab 8.1 (XFMR 1:) 'Transformer Commitment Costs'
Lme 20
Tab 10.1 (Services 1:) 'Weighted Average Installed Service Drop Costs'
Tab 11.1 (Meters 1:) 'Weighted Average Installed Meter Costs'
Line 22
Une 23
Lme 24 -27
1971
083
$280 I
(Table 7)
$127 80
Billing Costs
PacifiCorp
Oregon Marginal Cost Study
Total 20 Year Demand Costs Divided by Billing kW
December 2014 Dollars
(Dollars in OOO's)
(A)
(B)
Residential
Line
Description
Total
(sec)
(C)
(D)
(E)
(F)
General Service - Schedule 23
0-15kW
15+kW
Primary
(sec)
(sec)
(pri)
(G)
(H)
(I)
General Power- Schedule 28
0-50kW
51-100 kW > 101kW
Primary
(sec)
(sec)
(sec)
(pri)
(J)
(K)
(L)
General Service - Schedule 30
301+ kW
0-300 kW
Primary
(sec)
(sec)
(pri)
(M)
1-4MW
(sec)
(N)
(0)
(P)
Laroe Power Service - Schedule 48T
>4M
1-4M
>4MW
(sec)
(pri)
(pri)
(R)
(Q)
lrrg
Sch41
Trans
(tm)
~
(sec)
'
Demand Rela1ed Marginal Cost
1
GenerationTransmission 2
3
4
Distribution 5
Poles, Wire, Sub
6
Transfonners
7
Distribution Subtotal
8
9 Total Demand Related
10
11 Average Billing kW
12
Generation 13
14
Transmission 15
16
Distribution17
Poles, Wire, Sub
18
Transformers
19
Distribution subtotal
20
21
22
23
24
Total Demand Related
25
26
Monthly Demand Costs
$215,252
$354,191
$155,669
"'M'
$10,187
$16,763
$14,411
$17
$28
$8,171
$13,445
$11,251
$18,514
$14,790
$24,337
$285
$469
$3,092
$5,088
$16,990
$27,956
$1,508
$2,481
$8,647
$14,229
$7,079
$11,649
$806
$1,326
$16,371
$26,937
$9,779
$16,091
$2,916
$4,798
$202,593
$14,967
$217,560
$109,050
$10,359
$119,409
$11,109
$573
$11,682
$9,021
$394
$9,41:>
$22
$0
$22
$7,642
$441
$8,083
$10,740
$589
$11,329
$13,762
$727
$14,489
$317
$0
$317
$2,582
$152
$2,734
$14,277
$808
$15,085
$1,260
$0
$1,260
$6,260
$411
$6,671
$4,964
$0
$4,964
$252
$43
$295
$5,681
$0
$5,681
$0
$0
$0
$5,656
$468
$6,124
$787,003
$369,683
$38,632
$32,584
$67
$29,699
$41,094
$53,616
$1,071
$10,914
$60,031
$5,249
$29,547
$23,692
$2.427
$48,989
$25,870
$13,838
7,114,825
4,966,196
263,233
180,731
1,550
141,470
189,067
233,629
18,698
48,729
259,445
21.716
132,222
102,469
13,624
227,830
164,031
150,187
$8,75B
$19.05
$31.35
$38.70
$63.68
$48.46
$79.74
$10.97
$18.06
$57.76
$95.04
$59.51
$97.92
$63.31
$104.17
$15.24
$2508
$63.45
$104.42
$65.49
$107.75
$69.44
$114.25
65.40
107.61
69.08
113.68
59.16
97.33
71.86
118.23
59.62
98.10
19.42
31.95
$21.96
$2.09
$24.04
$42.20
$2.18
$44.38
$49.91
$2.18
$52.09
$14.01
$0.00
$14.01
$54.02
$3.12
$57.14
$56.81
$3.12
$59.92
$58.91
$3.11
$62.02
$16.94
$0.00
$16.94
$52.99
$3.12
$56.11
$55.03
$3.12
$58.14
$58.01
$0.00
$58.01
47.34
3.11
50.45
48.45
0.00
48.45
18.51
3.13
21.64
24.93
0.00
24.93
0.00
000
0.00
37.66
3.12
40.77
$74.44
$146.76
$180.29
$43.04
$209.93
$217.35
$229.49
$57.27
$223.98
$231.38
$241.70
$223.47
$231.21
$178.14
$215.02
$157.71
$92.14
$8.20
$12.23
$15.02
$3.59
$17.49
$18.11
$19.12
$4.77
$18.66
$19.28
$20.14
$18.62
$19.27
$14.84
$17.92
$13.14
$7.68
Tab: 2.8
(Brlling Costs)
Full MC%
PacifiCorp
Oregon Marginal Cost Study
Marginal Cost Percentage @ Meter
December 2014 Dollars
Line
Description
(A)
(B)
(C)
Marginal Cost
(OOO)s
Mills/
kWh
%of
Total
Demand Related Marginal Cost1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
$215,252
354,191
202,593
14,967
$787,003
16.55
27.23
15.58
1.15
60.51
12.2%
20.1%
11.5%
0.8%
44.6%
Generation
Transmission
Total Energy Related
$616,337
43,168
$659,505
47.39
3.32
50.71
34.9%
2.4%
37.4%
Commitment & Billing Commitment
Billing
Total Commitment & Billing
202,633
116.427
$319,060
15.58
8.95
24.53
11.5%
6.6%
18.1%
TOTAL MARGINAL COST
$1,765,568
135.75
100.0%
Generation
Transmission
Dist. Poles, Cond., Subst.
Dist. Transformers
Total Demand Related
Energy Related Marginal Cost-
Note: Total MWh
=
13,006,121
Tab: 2.9
(Full MC %)
1()YrUC
PacrfrCorp
Oregon Marginal Cost Study
10 Year Run Cost1ng Inputs and Customer Data
Marg1nal Unit Costs
December 2014 Dollars
(A)
Residential
line
Desaiption
(sec)
(8)
(C)
(E)
(D)
General Serv1ce - Schedule 23
0-15kW
15+kW
(sec)
(sec)
(pn)
I
I
(F)
(G)
(H)
(I)
General Serv1ce Schedule 28
0-SOkW
51-100 kW > 101kW
Primary
(sec)
(sec)
(sec)
(pn)
(J)
(l)
(K)
General Service - Schedule 30
301+ kW
Pnmary
0-300 kW
(sec)
(sec)
(pn)
(M)
1-4MW
(sec)
(0)
(N)
Laroe Power Servrce - Schedule 48T
1-4MW
>4MW
> 4MW
(pri)
(sec)
(pn)
(P)
(0)
(tm)
lrrg
Sch 41
(sec)
Billi~Units
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
Demand
Peak MW@ Meter
Demand loss Factor
Peak MW @ Generator
Energy
Energy- Annual MWh
Energy Loss Factor
Energy- Annual MWh
System
Distribution
Transformer
System
Distribution
Transformer
@Meter
@Generator
Customer
Annual Customers
Average Customers
849
976
3,327
11106
943
1,083
3,695
91
89
184
11106
102
99
205
79
n
121'
1.1106
87
80
141
0
0
2
1 0792
0
0
NIA
I
73
78
141
11106
81
86
157
101
109
189
11106
112
121
210
133
140
234
1.1106
147
155
259
3
3
19
1 0792
3
4
NIA
28
30
49
1.1106
31
33
54
153
165
259
1.1106
169
183
288
14
15
22
1 0792
15
16
NIA
78
84
132
1.1106
86
93
147
65
69
102
1 0792
71
74
NIA
7
6
14
1 1106
8
7
15
151
150
228
1 0792
163
162
NIA
94
0
164
1.0426
97
NIA
26
27
150
11106
29
30
167
5,379,569
1.10006
5.917,848
589,432
1.10006
648411
510,378
110006
561446
1,147
1 06904
1,226
437,292
110006
481,048
662.698
110006
729,008
874,287
110006
961,768
18,574
1 06904
19,856
204,293
1 10006
224,734
1,041.871
1 10006
1.146.121
91,598
1 06904
97,922
524,179
110006
576,628
467.708
1.06904
499,998
51.567
110006
561'27
1,061.765
1 06904
1,135,069
829,896
1.04527
867,465
238,210
110006
262,045
485.586
63,644
10,200
43
4,489
3,455
1,925
56
200
515
47
102
61
2
32
9
8.046
3.920
$100.37
$165.04
$100.65
$2.80
$100.37
$165 04
$11255
$2.80
$100 37
$165.04
$112.55
$2 80
$100.37
$165.04
$88.78
$2.80
$100.37
$165.04
$88 78
$2 80
$10037
$16504
$88.78
$2 80
$100.37
$165.04
$8878
$000
$100.37
$165.04
$78 07
$2 80
$100.37
$165.04
$78.07
$2.80
$100 37
$165 04
$78.07
$0 00
$100.37
$165.04
$67.03
$2.80
$100 37
$165.04
$6703
$0.00
37
04
72
80
$100 37
$165.04
$3512
$000
$100.37
$165.04
$0.00
$0.00
$100 37
$165.04
$191 32
$2.80
Unit Costs
I
Generation
Transmission
Poles, Cond , Subst.
Transtormers
$ I System Peak kV\
$ I System Peak kV\
$1Dist kW
$/XfmrkW
Energy @ Generator
$/kWh
$004393
$0 04393
$0 04393
$0 04393
$0.04393
$0 04393
$004393
$004393
$0 04393
$0 04393
$0.04393
$0.04393
$0.04393
$0 04393
$0 04393
$0 04393
$0.04393
Commitment & Billing
$1 Gust I Year
$49121
$608 20
$839 43
2.38546
$1,274 82
$1,39028
$1,90433
$2,339 44
$2245 93
$2,747 00
$2,45573
5,961 33
$3,11897
$5,893 00
$3,05064
$53,591.37
1,533.55
$100.371
$16504
$112.55
$0.00
Tab 2.10
$100
$165
$36
$2
(10 YrUC)
10YrFC
PacifiCorp
Oregon Marginal Cost Study
10 Year Marginal Cost By Load Class
December 2014 Dollars
(Dollars in OOO's)
(A)
(B)
Residential
Line
Total
(sec)
{C)
(D)
(E)
General Service - Schedule 23
0-15kW
15+kW
(sec)
(sec)
(pri}
(F)
(G)
(H)
(I)
General Service - Schedule 28
> 101kW
0-50 kW 51-100 kW
Primary
(sec)
(sec)
(sec)
(pri)
(J)
(K)
(L)
General Service - Schedule 30
0-300kW
301+ kW
Primary
(sec)
(sec)
(pri)
(M)
1-4MW
(sec)
(N)
(0)
(P)
Large Power Service - Schedule 48T
>4MW
>4MW
1-4MW
(pri)
(sec)
(pri)
(0)
(R)
(trn)
lrrg
Sch 41
(sec)
Demand Related Marninal Cost
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
Generation -
Transmission -
$215,402
$354,191
$94,671
$155,669
$10,194
$16,763
$8,764
$14.411
$'17
$28
$8,176
$13,445
$11,259
$18,514
$14,801
$24,337
$285
$469
$3,094
$5,088
$17,002
$27,956
$1,509
$2,481
Distribution Poles, Conductor, Substations
Transformers
Distribution subtotal
$202,592
$14 946
$217,538
$109,049
$10 347
$119,396
$11,109
$9,021
$22
$2,581
$14,277
~
$11,328
~
$317
iill
$11,682
~
$22
$13,761
.lli.§
$14,487
$317
~
$9,414
$7,643
$440
$8,083
$10,740
iill
$2,733
~
$15,084
$1,2591
~
$1,259
$787,131
$369,736
$38,639
$32,589
$67
$29,704
$41,101
$53,625
$1,071
$10,915
$60,042
$623,215
$259,957
$28,483
$24,663
$54
$21,131
$32,024
$42,248
$872
$9,872
$315,532
$238,525
$38,708
$8,562
$103
$5,723
$4,803
$3,666
$131
$1,725,878
$868,218
$105,830
$65,814
$224
$56,558
$77,928
$99"539
$2,074
Total Demand Related
(Lines 1+2+7)
$8,653
$14,229
$7,084
$11.649
$807
$1,326
$16,382
$26,937
$6,260
$4,965
$253
1lli
$6,671
~
$4,965
14~
$295
$5,249
$29,553
$23,698
$50,346
$4,301
$25,330
$449
$1,415
$115
$608
$21,236
$111,803
$9,665
$55,491
$9,786
$16,091
$2,918
$4,798
$5,680
$0
$5,655
~
$5,680
~
$0
~
$6,122
$2,428
$48,999
$25,877
$13,838
$21,964
$2,492
$49,861
$38,106
$11,511
$190
$12
$98
$482
$11,942
$4,932
$98,958
$64,465
Ene[!lY Related Marninal Cost
Total Energy Related
Customer Related Marninal Cost
Commitment & Billing Rei
I
I
Total Revenue@ Full MC
--
Tab: 2.11
$45,85L
(10YrFC)
$37,291 I
5 Year MC
PacifiCorp
Oregon Margrnal Cost Study
5 Year Margrnal Costs by Load Class
December 2014 Dollars
(Dollars rn OOO's)
(A)
(B)
RestdentJal
Line
Total
(sec\
(C)
(D)
(F)
(E)
General Service - Schedule 23
0-15kW
15+ kW
(sec)
(sec)
iE")
0-50 kW
(sec)
(H)
(G)
(K)
(J)
(I)
General Service - Schedule 28
> 101kW
51-100 kW
Primary
(sec)
(sec)
(pn)
(M)
(L)
General Serv1ce - Schedule 30
301+ kW
0-300 kW
Primary
(sec)
(sec)
(pri)
(N)
1-4MW
(sec)
(0)
(P)
Large Power Service - Schedule 48T
> 4MW
1-4MW
>4MW
(pri)
(sec)
(pri)
(Q)
(R)
(tm)
lrrg
Sch41
(sec)
Billing Units
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Demand
Peak MW@ Meter
Demand Loss Factor
Peak MW@ Generator
Energy
Energy- Annual MWh @ Meter
Energy Loss Factor
Energy - Annual MWh @ Generator
System
System
12,984,464
849
11106
943
91
1.1106
102
79
1 '1106
87
0
1 0792
0
73
1.1106
81
101
1.1106
112
133
11106
147
3
1 0792
3
28
1.1106
31
153
11106
169
14,187,322
5,379,569
110006
5,917.848
589.432
110006
648,411
510,378
110006
561.446
1,147
1 06904
1,226
437,292
110006
481,048
662,698
1.10006
729,008
874,287
110006
961,768
18,574
1 06904
19,856
204,293
110006
224,734
1.041.871
1 10006
1.146,121
578.412
485,586
63,644
10,200
43
4.489
3,455
1.925
56
200
515
$100 48
$0 03823
$213.87
$100 48
$0 03823
$366 65
$100 48
$0 03823
$2,156.02
$100 48
$0 03823
$407 96
$100 48
$0 03823
421.91
14
1 0792
15
91598
1 06904
97,922
78
11106
86
65
1 0792
71
7
11106
8
151
1.0792
163
94
1.0426
97
26
11106
29
524,179
110006
576,628
467,708
1.06904
499,998
51,567
110006
56,727
1,061,765
1.06904
1,135,069
829,896
1.04527
867,465
238,210
1.10006
262,045
102
61
2
32
9
8.046
3,920
Customer
Average Customers
471
Unit Costs
Generation - $ I System Peak kW
Energy @ Generator $/kWh
Billing Related Costs
$100 48
$0 03823
$187.07
$100.48
$0 03823
$874 53
$100 48
$0 03823
$2,19580
$100.48
$0 03823
$1,03018
$100 48
$0 03823
$1,528 60
$100 48
$0 03823
$2,350 73
$100 48
$0 03823
$4,760 90
$100 48
$0 03823
$3,050 64
$10048
$0 03823
$4,760.90
$100.48
$0 03823
$3,05064
$10048
$0.03823
$53,591.37
$10048
$003823
$33.93
$9625
Marginal Costs $000
Total Demand Related
$215,639
$94.775
$10,206
$8,774
$17
$8,185
$11,271
$14,817
$286
$3,097
$17,020
$1,511
$8,663
$7,092
$807
$16,400
$9.796
$2,921
Total Energy Related
$542,381
$226,239
$24,789
$21.464
$47
$18,390
$27,870
$36,768
$759
$8,592
$43,816
$3.744
$22.044
$19,115
$2,169
$43,394
$33,163
$10,018
Billing Related Costs
$116,392
$90,838
$13,611
$3,740
$93
$1 831
$1 458
$1,683
$123
$206
$787
$110
$486
$186
$10
$98
$482
Total Revenue@ Full MC
~!!74,412_.__~411,852
$48,606
$33,978
$157
$28.406
$40,599
$53,268
$1,168
$11,895
$61,623
$5,365
$31,193
$26,393
$2,986
$59,892
$43,441
Tab 2.12
(5 Year MC)
$650.
$13,589
1 YearMC
PacifiCorp
Oregon Margma! Cost Study
1 Year Marginal Costs by Load Class
December 2014 Dollars
(Dollars rn OOO's)
(A)
(B)
Residential
Line
Total
(C)
(D)
(E)
(F)
(H)
(G)
(I)
(J)
Genera! Serv1ce - Schedule 23
0-15 kW
15+kW
(sec)
(sec)
(pn)
0-50 kW
(sec)
5,379.569
110006
5,917,848
589.432
110006
648.411
510,378
110006
561.446
1,147
1 06904
1,226
437,292
1.10006
481,048
662.698
110006
729,008
874.287
110006
961,768
18.574
1 06904
19.856
204,293
110006
224,734
485,586
63,644
10,200
43
4,489
3.455
1.925
56
$0 03428
$0 03428
$0 03428
$0 03428
$003428
$0 03428
$0 03428
$187 07
$213 87
$366 65
215602
$407 96
421 91
$202.888
$22,230
$19.249
$42
$16,492
$24.993
(sec)
(K)
(M)
(l)
(N)
(P)
(0)
(Q)
(R)
(tm)
lrrg
Sch 41
(sec)
General Serv1ce - Schedule 30
0-300 kW 301+ kW
Primary
(sec)
(pn)
(sec)
1-4MW
(sec)
1.041,871
110006
1,146,121
91,598
1.06904
97,922
524,179
110006
576,628
467,708
1 06904
499,998
51.567
1.10006
56,727
1.061,765
1 06904
1,135069
829,896
1 04527
867,465
238.210
110006
262,045
200
515
47
102
61
2
32
9
8,046
3,920
$0 03428
$0 03428
$0.03428
$0 03428
$0 03428
$0.03428
$0.03428
$0 03428
$0.03428
$003428
$874.53
$2,195 80
$1,03018
$1.528.60
$2.350 73
$4,760.90
$3,050.64
$4,760.90
$3,050 64
$53.59137
$33.93
$96.25
$32,973
$681
$7,705
$39,294
$3.357
$19.769
$17,142
$1,945
$38,915
$29,740
$8,984
General Serv1ce - Schedule 28
> 101kW
51-100 kW
(sec)
(sec)
Pnmary
(pri)
Large Power Service - Schedule 48T
> 4MW
> 4MW
1-4MW
(pri)
(pri)
(sec)
Billin9 Unrts
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
Energy
Energy - Annual MWh @ Meter
12,984,464
Energy Loss Factor
Energy- Annual MWh @ Generartor 14,187,322
Customer
Average Customers
578,412
UnrtCosts
Energy @ Generator
$/kWh
Billing Related Costs
Marginal Costs $000
Total Energy Related
$486,399
'
Billing Relarted Costs
$116,392
$90,838
$13,611
$3,740
$93
$1,831
$1,458
$1.683
$123
$206
$787
$110
$486
$186
$10
$98
$482
$650
Total Revenue@ Full MC
$602 791
$293 726
$35,841
$22 989
$135
$18 323
$26,451
$34,656
$804
$7,911
$40 081
$3467
$20,255
$17 328
$1 955
$39 013
$30,222
$9.634
Tab 2.13
(1 YearMC)
Capacity
PacifiCorp
Oregon Marginal Cost Study
Marginal Capacity Costs
Based on Avoided Capacity Costs
(A)
(B)
(C)
(D)
(E)
Calendar
Year
(12 Mo Ended DecL
Projected
Capacity
$/kW
Present
Value
Factors
@ 7.66%
PVof
Capacity
$/kW
(A) x(B)
Capacity
PVof
Capacity
Mills/kWh
(B)* (D)
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
$100.34
$102.34
$104.29
$106.28
$108.30
$110.25
$112.12
$114.14
$116.19
$118.28
$120.41
$122.58
$124.77
$127.15
$129.57
$132.02
$134.54
$137.24
$139.84
$142.50
1.0000
0.9289
0.8628
0.8014
0.7444
0.6915
0.6423
0.5966
0.5542
0.5148
0.4782
0.4442
0.4126
0.3833
0.3560
0.3307
0.3072
0.2854
0.2651
0.2462
100.34
95.06
89.98
85.17
80.62
76.24
72.01
68.10
64.39
60.89
57.58
54.45
51.48
48.74
46.13
43.66
41.33
39.17
37.07
35.08
2014
1 Year-
Sum of PV Costs
2014-2018
5 Year-
Short RunSum of PV Costs
@ 7.66%
Annual Cost of Capacity @ 22.27%
2014-2023
2014-2033
@ 7.66%
10 Years - Medium Run Sum of PV Costs
@ 7.66%
Annual Cost of Capacity@ 12.66%
20 Years- Long RunSum of PV Costs
@ 7.66%
Annual Cost of Capacity @ 8.04%
Mills/kWh
(A) I 0.505
/8,760
22.68
23.13
23.57
24.02
24.48
24.92
25.34
25.80
26.26
26.74
27.22
27.71
28.20
28.74
29.29
29.84
30.41
31.02
31.61
32.21
22.68
21.49
20.34
19.25
18.22
17.23
16.28
15.39
14.55
13.77
13.02
12.31
11.64
11.02
10.43
9.87
9.34
8.85
8.38
7.93
$/kW
100.34
mills /kWh
22.68
$451.17
100.48
$101.98
22.71
$792~80
100.37
179.20
22.69
$1,247.49
100.30
281.99
22.67
Footnote:
ColumnA:
Oregon Approved Avoided Cost Study, Total Cost of SCCT- Table 8, page 1, column (f)
Tab: 3.1
(Capacity)
Energy
PacifiCorp
Oregon Marginal Cost Study
Marginal Generation Energy Costs
Nominal Mills I kWh
(A)
I
(B)
(C)
(D)
(E)
(F)
(G)
(H)
(I)
(J)
(K)
(L)
(M)
(N)
(P)
(0)
(Q)
Capttalized
Capttalized
Total
Total
CCCT
Variable
Energy Cost Avoided Energy Wind Oregon Avoided Energy
Calendar
SCCT
SCCT
CCCT
CCCT
Capitaliz•ed Energy Cost Purchase Updated Energy Costs
Avoided
Year
Fixed Costs Fixed Costs Fixed Costs Fixed Costs Energy Cost 50.5% CF
Cost
Gas Price 6,960 Btu/kWh Energy Cost 50.5%CF
Cost
Cost
RPS
Cost (Wgt)
Present Value Present Value
($/kW-mo)
($/kW-yrl
($/kW-mol ($/kW-mQ}
($/MWh)
($/MWh) ($/MMBtu)
($/MWh)
($/MWh)
(12 MoEnded Dec) ($/kW-vrl
($/MWh)
($/MWh)
($/MWhl
~'!Mll
Factors
of Energy
~
(F)=(K)
(J) + (K) =(L)
(M) * (N) +
@ 7.66%
(O)*(P) = (Q)
(G) +(I) =(J)
((L)*(1 - N)) = (0)
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
I
100.34
102.34
104.29
106.28
108.30
110.25
112.12
114.14
116.19
118.28
120.41
122.58
124.77
127.15
129.57
132.02
134.54
137.24
139.84
142.50
I
8.36
8.53
8.69
8.86
9 03
9.19
9.34
9.51
9.68
9.86
10.03
10.22
10.40
10.60
10.80
11.00
11.21
11.44
11.65
11.88
I
112.36
114.62
116.78
119.02
121.29
123.46
125.54
127.81
130.12
132.47
134.85
137.28
139.74
142.41
145.12
147.87
150.67
153.69
156.62
159.61
I
9.36
9.55
9.73
9.92
10.11
10.29
10.46
10.65
10.84
11.04
11.24
11.44
11.65
11.87
12.09
12.32
12.56
12.81
13.05
13.30
I
1.00
1.02
1.04
1.06
1.08
1.10
1.12
1.14
1.16
118
1.20
1.23
1.25
1.27
1.30
1.32
1.34
1.37
1.40
1.43
I
2.72
2.78
2.82
2.88
2.94
2.99
3.03
3.09
3.15
3.21
3.26
3.32
3.38
3.45
3.52
3.58
3.65
3.72
3.79
3.87
1 Year-
Sum of PV Costs
2014-2018
5 Year-
Short RunSum of PV Costs
Annual Cost of Energy
@ 7.66% =
@22.27% =
171.67
38.23
Medium RunSum of PV Costs
Annual Cost of Energy
@ 7.66% =
@ 12.66% =
322.97
40.89
Long Run Sum of PV Costs
Annual Cost of Energy
@ 7.66% =
@ 8.04% =
539.47
43.37
2014-2033
10 Years-
20 Years -
4.37
4.62
4.89
5.21
5.63
6.03
5.90
6.23
6.79
7.07
6.95
7.17
7.51
7.81
804
8.23
8.32
8.44
8.60
8.76
30.42
32.16
34.03
36.26
39.18
41.97
41.06
43.36
47.26
49.21
4837
49.90
52.27
54.36
55.96
57.28
57.91
58.74
59.86
60.97
30.42
32.16
34.03
36.26
39.18
41.97
41.06
43.36
47.26
49.21
48.37
49.90
52.27
54.36
55.96
57.28
57.91
58.74
59.86
60.97
2.72
2.78
2.82
2.88
2.94
2.99
3.03
3.09
3.15
3.21
3.26
3.32
3.38
3.45
3.52
3.58
3.65
3.72
3.79
3.87
33.13
34.93
36.86
39.14
42.12
44.95
44.10
46.45
50.41
52.41
51.64
53.23
55.65
57.81
59.47
60.86
61.55
62.46
63.65
64.84
56.17
57.29
58.38
59.49
60.62
61.72
62.76
63.89
65.03
66.21
67.41
68.62
69.86
71.18
72.53
73.90
75.31
76.81
78.27
79.76
5%
15%
15%
15%
15%
15%
20%
20%
20%
20%
20%
25%
25%
25%
25%
25%
25%
25%
25%
25%
34.28
38.28
40.09
42.19
44.90
47.47
47.83
49.94
53.33
55.17
54.79
57.07
59.20
61.15
62.74
64.12
64.99
66.05
67.30
68.57
34.28
35.56
34.59
33.81
33.42
32.83
30.72
29.79
29.56
28.40
26.20
25.35
24.43
23.44
22.33
21.21
19.97
18.85
17.84
16.88
1.0000
0.9289
0.8628
0.8014
0.7444
0.6915
0.6423
0.5966
0.5542
0.5148
0.4782
0.4442
0.4126
0.3833
0.3560
0.3307
0.3072
0.2854
0.2651
0.2462
Mills/kWh
34.28
2014
2014-2023
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
I
Footnote:
ColumnA:
Column C:
Column H:
Column 1:
Oregon Approved Avoided
Oregon Approved Avoided
Oregon Approved Avoided
Oregon Approved Avoided
Cost
Cost
Cost
Cost
Study,
Study,
Study.
Study,
Total Cost of SCCT- Tabl•e 8, page 1, column (f)
Total Cost of CCCT- Table 8, page 2, column (f)
Gas Price- Table 9, column (b)
Heat Rate for CCCT- Table 8, page 3
Tab: 4.1
(Energy)
Calendar
Year
PacifiCorp
Marginal Generation Costs
Filed
12 Months Ended December
Avoided Simple Cycle Avoided Combined Cycle
Gas
CT Fixed
CT Fixed
Price
Costs
Costs
($/kW-yr)
($/kW-yr)
($/MMBtu)
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
CCCT Capacity Factor
CCCT Heat Rate (Btu/kWh)
Source:
Oregon
Oregon
Oregon
Oregon
100.34
102.34
104.2B
106.28
108.30
11 0.2~;
112.12
114.14
116.19
118.2ti
120.41
122.5ti
124.77'
127.1!;;
129.57'
132.02
134.54
137.24
139.84
142.50
I
112.36
114.62
116.78
119.02
121.29
123.46
125.54
127.81
130.12
132.47
134.85
137.28
139.74
142.41
145.12
147.87
150.67
153.69
156.62
159.61
4.37
4.62
4.89
5.21
5.63
6.03
5.90
6.23
6.79
7.07
6.95
7.17
7.51
7.81
8.04
8.23
8.32
8.44
8.60
8.76
12 Months Ended December
Avoided Firm
Combined
Gas
Capacity
Cycle CT
Price
Costs
Fixed Cost
($/kW-yr)
($/kW-yr)
($/MMBtu)
100.34
102.34
104.29
106.28
108.30
110.25
112.12
114.14
116.19
118.28
120.41
122.58
124.77
127.15
129.57
132.02
134.54
137.24
139.84
142.50
112.36
114.62
116.78
119.02
121.29
123.46
125.54
127.81
130.12
132.47
134.85
137.28
139.74
142.41
145.12
147.87
150.67
153.69
156.62
159.61
QF
Avoided
Costs
($/kW-yr)
4.37
4.62
4.89
5.21
5.63
6.03
5.90
6.23
6.79
7.07
6.95
7.17
7.51
7.81
8.04
8.23
8.32
8.44
8.60
8.76
56.17
57.29
58.38
59.49
60.62
61.72
62.76
63.89
65.03
66.21
67.41
68.62
69.86
71.18
72.53
73.90
75.31
76.81
78.27
79.76
50.5')~
6,960
Approved Avoided Cost Study, Total Cost of SCCT- Table 8, page 1, column (f)
Approved Avoided Cost Study, Total Cost of CCCT- Table 8, page 2, column (f)
Approved Avoided Cost Study, Gas Price- Table 9, column (b)
AC Study (Renewable Only), column (f)
(Fiscal Year):
(Previous Year* 75%)+(Current Year* 25%)
(Calendar Year):
(Previous Year* Oo/o)+(Current Year* 100%)
=
Previous Yr
Current Yr =
0%
100%
---
Tab: 4.2
---------
(Avoided Costs)
Transm1
PacifiCorp
Oregon Marginal Cost Study
Marginal Transmission Investment and O&M Expenses
2014 Dollars
(B)
(A)
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Footnote:
Lines 1-7
Line 9
Line 13
Line 14
Line 15
Line 20
2D14
2015
2D16
2D17
2D18
Forecasted
Forecasted
Forecasted
Forecasted
Forecasted
172,399
149,716
115,297
104,037
90,590
Growth Related Investments- (2014 to 2D18 in $DOD's)
$632,D39
131,867
132,795.
103,438
103,368
87,647
$559,115
(7) I (9)
Energy
Related
40,532
16,921
11,859
669
2,943
$72,924
MW
364
System Growth MW's from 2D14-2D18
Marginal Investment
Demand
Related
Total
(B)+ (C)
Item
(C)
$1,736.37
$1,536.03
$200.34 /kW
Annualized Investment
Admin. & General Factor
Annual O&M Expenses
(11) X 8.00%
(11) X 1.33%
( 11) X 1.415%
$138.91
$23.09
$24.57
$122.88
$20.43
$21.73
$16.03 /kW
$2.66 /kW
$2.83 /kW
Annualized Marginal Cost
Sum (13) to (15)
$186.57
$165.D4
$21.52 /kW
$0.0D3D4 /kWh
Marginal Cost of Energy-Related Transmission
$21.52/8760 hours /80.87% Load Factor))
Tab 5.2 (Transm2:) '2014-2018 Forecasted Transmission'
Peak Load Forecast Detail, Dec. 16, 2009- Forecasting Dept.
Tab 15.1 (Charge 1:) ·calculation of Annual Charges' (for 8.00% factor)
Tab 15.1 (Charge 1:) ·calculation of Annual Charges' (for 1.33% factor)
Tab 5.3 (Tran_OM:) 'Transmission 0 & M Expenses'
(for 1.415% factor)
See Tab "TransLF"
Tab: 5.1
(Transm1)
Transm2
PacifiCorp
Oregon Marginal Cost Study
2014-2018 Forecasted Transmission
December 2014 Dollars( in GOO's)
(A)
(B)
(D)
(C)
(E)
(F)
Forecast
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Description
Bulk Power Lines (grid)
price adjustment factor
Adjusted Bulk Power Lines (grid)
Growth Related Major Projects (local)
price adjustment factor
Adjusted Growth Related Major Projects (local)
2014
2015
2016
(H)
(G)
2017
2018
I
Total
60,589
1.019
61,720
25,295
1.019
25,767
17,728
1.019
18,058
1,000
1.019
1,019
4,400
1.019
4,482 I
111,046
108,651
1.0187
110,679
121,678
1.0187
123,949
95,458
1.0187
97,239
101,130
1.0187
103,018
84,531
1.0187
86,108 I
520,993
Bulk Power Lines - Demand Related
Line (3) x Demand Factor 34.33%
21,188
8,846
6,199
350
1,539
Bulk Power Lines - Energy Related
Line (3) - Line (9)
40,532
16,921
11,859
669
2,943
I
72,924
131,867
132,795
103,438
103,368
87,647
I
559,115
$ Demand Related
$ Energy Related
$131,867
$40,532
$132,795
$16,921
$103,438
$11,859
$103,368
$669
$87,6471
$2,943
$559,115
$72,924
Total Marginal Transmission Investment
$172,399
$149,716
$115,297
$104,037
$90,59o
Total Growth Demand Related
Line (7) + Line (9)
I
$632,039
Footnotes:
line 1 & 5
line 10
Bulk power line & growth related projects data provided in 2012 dollars for each year
Demand Portion of Transmission =22.67 I (22.67+43.37) =
34.33%
!.
l
Index
2013
1.0180
Tab: 5.2
2014
1.0370
Escalation
Factor
2013- 2014
1.0187
(Transm2)
Tran_OM
PacifiCorp
Transmission 0 & M Expenses
(Dollars in OOO's)
Line
-
(A)
(B)
(C)
(D)
(E)
(F)
(G)
(H)
(I)
(J)
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
Description
102,419
105,962
105,324
115,283
136,930
154,195
174,010
172,875
195,628
204,716
Wheeling
76,949
77,497
76,944
83,360
94,111
106,592
121 '167
117,161
136,855
138,235
3
Net Transmission O&M
Line (1)- (2)
25,469
28,465
28,379
31,922
42,820
47,603
52,843
55,713
58,774
66,481
4
Transmission Plant
2,299,173 2,396,665
2,487,677
2,578,317 2,688,839
2,874,659
3,054,529 3,342,914
4,339,114
4,500,418
5
Tran. O&M Loading
Line (3) I (4)
1
Transmission O&M Exp.
2
1.108%
1.188%
1.141%
1.238%
1.593%
1.656%
1.730%
1.667%
1.355%
1.477%j1.415o/~]
Source:
PacifiCorp FERC Form 1
(1) page 321. line 112
(2) page 321, line 96
Tab: 5.3
(Tran_OM)
Dist Sub 1
PacifiCorp
Oregon Marginal Cost Study
Distribution Substation Costs I kW
2014 Dollars
Line
1
2
3
4
5
Incremental Substation Cost- $1 kW
$228.69
Annual Distribution Carrying Charge
9.74%
$22.27 I kW
Substation Marginal Cost - $ I kW
Tab: 6.1
(Dist Sub 1)
Dist Sub 2
PacifiCorp
Marginal Cost Study
Substation Investment
In Service
Year
2012
2012
2013
2016
2013
2014
2016
2016
Substation
Capacity Project
Riddle
Deschutes
Canyonville
Dodge Bridge
Knott
Selah
Independence
Vine Street
State
OR
OR
OR
OR
OR
WA
OR
OR
Capacity
Installed Cost
Increase (MVA) (Dollars in OOO's)
61.0
12.5
10.1
12.5
10.0
25.0
5.0
10.0
$7,166
$2,085
$4,914
$2,000
$4,291
$5,989
$2,461
$3,313
146.1
$32,219
Index
2012
1.0000
2014
1.0370
Tab:6.2
Cost Per MVA
(Dollars in OOO's)
$117
$167
$487
$160
$429
$240
$492
$331
Escalation
Factor
2012-2014
1.0370
(Dist Sub 2)
PC 1
PacifiCorp
Oregon Marginal Cost Study
Hypothetical Circuit Study Results
Annual Demand and Commitment Costs
December 2014 Dollars
(A)
(8)
(C)
(D)
Demand
Investment $ I kW **
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Load Class
Poles
Conductor
Annual $ I kW **
Poles
(A) x 9.74%
Conductor
(8) X 9.74%
(E)
(F)
(G)
(H)
Commitment
Investment $1 Customer
Annual $ I Customer
Poles
Conductor
Poles
{E) x 9.74%
Conductor
(F) X 9.74%
Res- Schedule 4
(sec)
$202.41
$295.16
$19.71
$28.75
$915.10
$441.96
$89.13
$43.05
GS - Schedule 23
0-15 kW
15+kW
Primary
(sec)
(sec)
(pri)
$246.83
$246.83
$246.83
$336.58
$336.58
$336.58
$24.04
$24.04
$24.04
$32.78
$32.78
$32.78
$1,116.31
$1,116.31
$1,116.31
$539.14
$539.14
$539.14
$108.73
$108.73
$108.73
$52.51
$52.51
$52.51
GS - Schedule 28
0-50 kW
51-100 kW
> 101kW
Primary
(sec)
(sec)
(sec)
(pri)
$159.02
$159.02
$159.02
$159.02
$252.85
$252.85
$252.85
$252.85
$15.49
$15.49
$15.49
$15.49
$24.63
$24.63
$24.63
$24.63
$698.82
$698.82
$698.82
$698.82
$337.50
$337.50
$337.50
$337.50
$68.07
$68.07
$68.07
$68.07
$32.87
$32.87
$32.87
$32.87
GS - Schedule 30
0-300 kW
301+ kW
Primary
(sec)
(sec)
(pri)
$119.47
$119.47
$119.47
$215.14
$215.14
$215.14
$11.64
$11.64
$11.64
$20.95
$20.95
$20.95
$510.85
$510.85
$510.85
$246.72
$246.72
$246.72
$49.76
$49.76
$49.76
$24.03
$24.03
$24.03
LPS - Schedule 48T
1··4MW
1··4MW
> 4MW
> 4MW
(sec)
(pri)
(sec)
(pri)
$77.77
$77.77
$12.50
$8.54
$177.24
$177.24
$23.74
$16.22
$7.57
$7.57
$1.22
$0.83
$17.26
$17.26
$2.31
$1.58
$332.41
$332.41
$0.00
$0.00
$160.54
$160.54
$0.00
$0.00
$32.38
$32.38
$0.00
$0.00
$15.64
$15.64
$0.00
$0.00
Irrigation- Schedule 41
(sec)
$535.96
$615.78
$52.20
$59.98
$2,528.49
$1,221.16
$246.27
$118.94
Footnotes:
**$ I kW are in terms of Distribution kW.
Tab: 7.1
(PC 1)
PC2
PacifiCorp
Oregon Marginal Cost Study
Calculation of Escalation Factors
Poles and Conductor
Three Phase Costs as Demand
(A)
(8)
(C)
Poles
Cost
Conductor
Cost
Poles
Cost
Res - Schedule 4
$195.19
$284.63
$882.45
$426.19
$202.41
$295.16
$915.10
$441.96
GS - Schedule 23
$238.03
$238.03
$238.03
$324.57
$324.57
$324.57
$1,076.48
$1,076.48
$1,076.48
$519.90
$519.90
$519.90
$246.83
$246.83
$246.83
$336.58
$336.58
$336.58
$1 '116.31
$1 '116.31
$1 '116.31
$539.14
$539.14
$539.14
GS - Schedule 28
$153.35
$153.35
$153.35
$153.35
$153.35
$243.83
$243.83
$243.83
$243.83
$243.83
$673.89
$673.89
$673.89
$673.89
$673.89
$325.46
$325.46
$325.46
$325.46
$325.46
$159.02
$159.02
$159.02
$159.02
$159 02
$252.85
$252.85
$252.85
$252.85
$252.85
$698.82
$698.82
$698.82
$698.82
$698.82
$337.50
$337.50
$337.50
$337.50
$337.50
GS - Schedule 30
$115.21
$115.21
$115.21
$207.47
$207.47
$207.47
$492.62
$492.62
$492.62
$237.92
$237.92
$237.92
$119.47
$119.47
$119.47
$215.14
$215.14
$215.14
$510.85
$510.85
$510.85
$246.72
$246.72
$246.72
LPS - Schedule 48T
$75.00
$75.00
$12.05
$8.23
$170.91
$170.91
$22.89
$15.64
$320.55
$320.55
$0.00
$0.00
$154.81
$154.81
$0.00
$0.00
$77.77
$77.77
$12.50
$8.54
$177.24
$177.24
$23.74
$16.22
$332.41
$332.41
$0.00
$0.00
$160.54
$160.54
$0.00
$0.00
$2,438.27
$1,177.59
$535.96
$615.78
$2,528.49
$1,221.16
2014
1.0370
Escalation
Factor
2012-2014
1.0370
Demand
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
Irrigation - Schedule 41
$516.84
$593.81
(D)
Commitment
Conductor
Cost
Index
2012
1.0000
(E)
(F)
2014 Demand
Poles
Conductor
Cost
Cost
(C) X 1.0370
(D) X 1.0370
(G)
(H)
2014 Commitment
Poles
Conductor
Cost
Cost
(8) X 1.0370
(A) X 1.0370
Footnotes:
Escalation Factors: Cost Trends of Electric Utility Construction, Table A14
Pole and conductor costs from Distribution Circuit Model.
Tab: 7.2
(PC2)
PC 3
PacifiCorp
Oregon Marginal Cost Study
Circuit Distribution Model
Inputs & Calculations
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
(A)
(B)
(C)
(D)
(E)
(F)
Number
Annual
MWh
Customers
Average
MWhper
Customer
(A) I(B)
Distribution
Peak
MW
Average
kWper
customer
(D)/(B) • 1,000
Pen:ent
Single
Phase
of
Class
Res - Schedule 4
GS - Schedule 23- 0-15 kW
GS- Schedule 23- 15+ kW
GS - Schedule 23 - Primary
GS- Schedule 28- 0-50 kW
GS- Schedule 28- 51-100 kW
GS - Schedule 28 - > 101 kW
GS - Schedule 28 - Primary
GS - Schedule 30 - 0-300 kW
GS - Schedule 30 ~ 301 + kW
GS - Schedule 30 - Primary
Irrigation - Sch 41
LPS - Schedule 48T - 1 - 4 MW
LPS - Schedule 48T - 1 - 4 MW
LPS - Schedule 48T - > 4 MW
LPS - Schedule 48T - > 4 MW
Total-
sec
sec
sec
(pri
sec
sec
sec
(pri
sec
sec
(pri
sec
sec
(Dri
sec
(pri
5,408,536
604,893
523 765
1,163
444,385
673 448
888469
18,661
202011
1,030,233
90,666
217,837
531189
492 307
52,257
1,117,609
12,297,428
474.231
66.169
10 605
44
4,487
3,453
1,924
57
215
553
51
7,211
107
64
2
33
569,206
11.40
9.14
49.39
26.15
99.04
195.01
461.70
329.16
939.23
1863.67
1,791.92
30.21
4961.68
7690.63
26128.40
33801.48
976
89
72
0
78
109
140
3
30
165
15
27
84
69
6
150
2,011
206
1 34
6.81
3.98
17.27
31.54
72.52
5843
138.41
297.86
295.37
3.69
785.38
1072.05
3,096.54
453191
100 00%
82.15%
45.12%
29.81%
12.44%
1.93%
-
0.39%
14.57%
-
-
CUstomer Distribution on the Hypothetical Circuit Branch
A
B
c
1
2
3
Class
18
19
20 ..
21
22
23
24
25
26
27
28
29
30
31
32
33
Res- SChedule 4 (sec)
GS- Schedule 23- 0-15 kW sec
GS - Schedule 23 - 15+ kW sec
GS - Schedule 23 - Primary (pri)
GS - Schedule 28 - 0-50 kW sec
GS-Schedule28- 51-100kW sec
GS - Schedule 28 - > 101 kW sec
GS - Schedule 28 - Primary pri)
GS -Schedule 30 - 0-300 kW sec
GS - Schedule 30- 301 + kW
sec
GS - Schedule 30 - Pnmary (pri)
l~tion- Sch 41
LPS - Schedule 48T- 1 - 4 MW sec
LPS - Schedule 48T- 1 - 4 MW Iori
LPS - Schedule 48T - > 4 MW sec
LPS- Schedule 48T- > 4 MW (pri
34
35
~tern E!~e!!l records & engineering information
Number of pole feet in Oregon
Number of pole miles in Oregon
Number of trench feet in Oregon
Number of trench miles in Oregon
Total miles in Oregon
36
37
38
39
40
41
42
43
44
45
46
47
46
49
50
51
Number of circuits in Oregon
Number of po!es m Oregon
0.90%
1.30%
1.30%
1.30%
0.76%
0.76%
0.76%
0.76%
0.52%
0.52%
0.52%
.2.56%
D
E
Hypothetical Circuit Branch
4
5
F
G
6
7
3.62%
3.62%
3.62%
3.92%
3.92%
3.92%
3.92%
3.92%
3.92%
3.92%
3.92%
3.92%
2.08%
2.08%
2.08%
2.08%
2.08%
2.08%
208%
2.08%
2.08%
2.08%
2.08%
2.08%
1.26%
1.26%
1.26%
126%
1.26%
1.26%
1.26%
1.26%
1.26%
12.34%
12.34%
12.34%
1.65%
1.65%
1.65%
1.65%
1.65°/o
1.65%
Lame Customers are on dedicated circuits and are not included here
LarQe Customers are on dedicated circuits and are not included here
0.90%
1.30%
1.30%
1.30%
0.76%
0.76%
0.76%
0.76%
0.52%
052%
0.52%
2.56%
0.90%
1.30%
1.30%
130%
0.76%
0.76%
0.76%
076%
052%
0 52%
0.52%
256%
75,818,501
14,360
26,922,011
5,099
19,458
526
371,373
Poles per mile
Customers per mile
MWh per customer
MWh per circuit
Branches per circuit
Distance per circuit
Distance per branch
I
86.45%
84.34%
84.34%
84.34%
91.45%
91.45%
91.45%
91.45%
94.65%
94.65%
94.65%
55.31%
95.05%1
95.05%
H
Branch
Total
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100 00%
100 00%
100 00%
100 00%
100.00%
25.86
2925
21.60
23,379
7
36.99
528
12 kV circuit 12 miles long has approx. 3 miles of single phase
which is approx 25 percent of c1rcuit distance.
9.25 :: 25 percent of typ1cal Oregon c1rcu1t
5 clivide by outer branches
1.850 distance of single phase on outer branch
35.00% equals percentage of s~ng!e phase outer branch Segments
Tab: 7.3
(PC3)
PC4
PacifiCorp
Oregon Circuit Model Study
Customer Distribution on the Hypothetical Circuit Branch
(A)
I
(B)
I
(C)
1
I
2
I
3
Class
1
I
I
(D)
(E)
I
(F)
I
(G)
I
6
I
7
(H)
Hypothetical Circuit Branch
I
I
4
5
Branch
Total
Residential
0.90%
0.90%
0.90%
3.62%
3.62%
3.62%
86.45%
1oo.oo%
I
2
GS 0-15 kW (sec) (23)
1.30%
1.30%
1.30%
3.92%
3.92%
3.92%
84.34%
100.00%
!
3
GS >15 kW (sec) (23)
1.30%
1.30%
1.30%
3.92%
3.92%
3.92%
84.34%
100.00% '
4
GS (pri) (23)
1.30%
1.30%
1.30%
3.92%
3.92%
3.92%
84.34%
100.00%'
5
GS < 50 kW (sec) (28)
0.76%
0.76%
0.76%
2.08%
2.08%
2.08%
91.45%
100.00% •
6
GS 51-100 kW (sec) (28)
0.76%
0.76%
0.76%
2.08%
2.08%
2.08%
91.45%
100.00%
7
GS > 100 kW (sec) (28)
0.76%
0.76%
0.76%
2.08%
2.08%
2.08%
91.45%
100.00% '
8
GS (pri) (28)
0.76%
0.76%
0.76%
2.08%
2.08%
2.08%
91.45%
0.52%
0.52%
0.52%
1.26%
1.26%
126%
94.65%
100.00% '
100.00%
0.52%
0.52%
0.52%
1.26%
1.26%
1.26%
94.65%
94.65%
9
10
GS 0-300 kW (sec) (30)
GS >300 kW (sec) (30)
100.00% •
100.00%.
11
GS (pri) (30)
0.52%
0.52%
0.52%
1.26%
1.26%
1.26%
12
Irrigation
2.56%
2.56%
2.56%
12.34%
12.34%
12.34%
55.31%
100.00% '
13
Large GS 1-4 MW (sec)
-
1.65%
1.65%
95.05%
Large GS 1 - 4 MW (pri)
-
1.65%
14
-
1.65%
1.65%
1.65%
95.05%
100.00% •
100.00%'
-
-
-
-
-
-
-
-
-
15
16
Large GS + 4 MW (sec)
Large GS + 4 MW (pri)
•
Except where customers own their own transformers.
Tab: 7.4
(PC 4)
PC5
PacifiCorp
Oregon Circuit Model Study
Average Customers by Hypothetical Circuit Branch
Class
~··-·-
...
---~
................
1 Residential
8 07
8.07
8.07
3266
32.66
32.66
779 38
90158
2 GS 0-15 kW (sec) (23)
1.64
1 64
164
4 93
4.93
4.93
106.10
12580
3 GS >15 kW (sec) (23)
026
026
026
0 79
079
0.79
17 00
20.16
4 GS (pri) (23)
0.00
0.00
000
0 00
0.00
000
0.07
008
5 GS < 50 kW (sec) (28)
0.07
0 07
0 Ot
018
018
0.18
7 80
8.53
6 GS 51-100 kW (sec) (28)
0.05
0.05
0 05
014
014
014
6.00
657
7 GS > 100 kW (sec) (28)
003
003
0.03
008
008
0.08
3 35
366
8 GS (pri) (28)
000
0.00
000
000
0.00
0.00
010
0.11
9
000
0 00
0 00
0 01
0.01
0.01
0 39
041
GS 0-300 kW (sec) (30)
10 GS >300 kW (sec) (30)
0.01
0.01
0 01
0.01
0.01
0.01
099
1.05
11
GS (pri) (30)
0.00
0.00
0 00
000
0.00
0.00
0.09
010
12
Irrigation
0.35
0 35
0 35
1.69
169
169
7 58
13 71
13
Larqe GS 1 - 4 MW (sec)
-
0 00
0.00
0.00
019
0.20
14
Large GS 1 - 4 MW (pri)
-
0.00
0.00
0.00
012
012
15
Laroe GS + 4 MW (sec)
-
-
-
-
16 Large GS + 4 MW (pri)
17 Total
10.48
10.48
10 48
40 49
40.49
40.49
929.17
1,082 07
Source- 'Circuit Distribution Mode/Inputs & Calculations' (PC 3) Tab 7.3
Source- 'Customer Distribution on the Hypothetical Circuit Branch' (PC 4) Tab 7.4
Customers multiplied by Customer Distribution on the Hypothetical Circuit Branch divided by circuits in the state.
For Example 8.07 is 474,231 Residential Customers X .895% customers on Branch 1 divided by 526 circuits.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
Percent of Customers
Residential
GS 0-15 kW (sec) (23)
GS >15 kW (sec) (23)
GS (pri) (23)
GS < 50 kW (sec) (28)
GS 51-100 kW (sec) (28)
GS > 100 kW (sec) (28)
GS (pri) (28)
GS 0-300 kW (sec) (30)
GS >300 kW (sec) (30)
GS (pri) (30)
lrriqation
Larqe GS 1 - 4 MW (sec)
Large GS 1 4MW(pri)
Large GS + 4 MW (sec)
Large GS + 4 MW (pri)
Total
77.05%
15.63%
2.50%
0.01%
0.62%
0.48%
0.27%
0.01%
0.02%
0.05%
0.00%
3.35%
77.05%
15.63%
2.50%
0.01%
0.62%
0.48%
0.27%
0.01%
0.02%
0.05%
0.00%
3.35%
77.05%
15.63%
2.50%
0.01%
0.62%
048%
0.27%
0.01%
0.02%
0.05%
0.00%
3.35%
-
-
-
-
-
-
-
100.00%
100.00%
100.00%
••
••
80.66%
12.17%
1.95%
0.01%
044%
0.34%
0.19%
0.01%
0.01%
0.03%
0.00%
4.18%
0.01%
0.00%
80.66%
12.17%
1.95%
0.01%
0.44%
0.34%
0.19%
0.01%
0.01%
0.03%
0.00%
4.18%
0.01%
0.00%
80.66%
12.17%
1.95%
0.01%
0.44%
0.34%
0.19%
0.01%
0.01%
0.03%
0.00%
4.18%
0.01%
0.00%
83.88%
11.42%
1.83%
0.01%
0.84%
0.65%
0.36%
0.01%
0.04%
0.11%
0.01%
0.82%
0.02%
.0.01%
-
-
-
-
-
-
-
-
100.00%
100.00%
100.00%
100.00%
83.32%
11.63%
1.86%
0.01%
0.79%
0.61%
0.34%
0.01%
0.04%
0.10%
0.01%
1.27%
0.02%
0.01%
-
100.00%
-------
Sum of Branch Customers
18
19 '--'-='-''-'--'-'--'-'-'--"1 ,2,3,6
I '.
M'
M'
M'
~~
M'
•
M
M'
1 ,2,3,4,5,6,7
Tab 7_5
(PC 5)
PC6
PacifiCorp
Oregon Circuit Model Study
Circuit kW Load by Branch
Class
Circuit kW Loads
1 Restdentia!
166
166
166
67 2
67.2
67.2
1.603.2
18546
2 GS 0-15 kW (sec) (23)
22
22
2.2
6.6
66
66
142.5
1690
3 GS >15 kW (sec) (23)
18
18
18
54
5.4
5.4
1157
137.2
4 GS (pn) (23)
0.0
0.0
00
00
00
0.0
03
03
5 GS < 50 kW (sec) (28)
11
11
11
31
3.1
3.1
1348
147 4
6 GS 51-100 kW (sec) (28)
1.6
16
16
4.3
4.3
4.3
189.4
207 1
7 GS > 100 kW (sec) (28)
20
20
2.0
55
5.5
5.5
2427
265 3
8 GS (pri) (28)
0.0
00
0.0
01
01
0.1
58
63
9
03
03
03
07
07
07
536
566
GS 0-300 kW (sec) (30)
10 GS >300 kW (sec) (30)
1.6
16
1.6
40
4.0
4.0
2963
313 0
11
GS (pri) (30)
0.1
01
01
0.4
04
04
269
28.4
12
lrngation
13
13
1.3
6.2
6.2
6.2
280
50.6
26
26
2.6
151 9
1599
2.2
2.2
1240
130.5
108.3
3.115.0
3,526 2
5147%
4.57%
3.72%
0.01%
4.33%
608%
7.79%
0.18%
1.72%
9.51%
0.86%
0.90%
4.88%
3.98%
52.60%
4.79%
3.89%
0.01%
4.18%
5.87%
7.52%
0.18%
1.61%
8.88%
0.81%
143%
4.53%
3.70%
13 Large GS 1 -4 MW (sec)
-
-
14 Large GS 1 -4 MW (pri)
22
15 Large GS + 4 MW (sec)
-
-
16 Large GS + 4 MW (pn)
17 Total
28.8
28 8
28 8
108 3
108.3
Source- 'Circuit Distribution Model Inputs & Calculations' (PC 3) Tab 7.3
Source- 'Average Customers by Hypothetical Circuit Branch' (PC 5) Tab 7.5
Customers multiplied by circuit kW per customer.
For Example 16.6 is 8.07 Residential Customers multiplied by 2 06 average Dist. kW per Customer.
Percent of Branch Load
1 Residential
2 GS 0-15 kW (sec) (23)
3 GS >15 kW (sec) (23)
4 GS (pri) (23)
5 GS < 50 kW (sec) (28)
6 GS 51-100 kW (sec) (28)
7 GS > 100 kW (sec) (28)
8 GS (pri) (28)
9 GS 0-300 kW (sec) (30)
10 GS >300 kW (sec) (30)
11 GS (pri) (30)
12 Irrigation
13 Large GS 1 - 4 MW (sec)
14 Large GS 1 - 4 MW (pri)
15 Large GS + 4 MW (sec)
16 Large GS + 4 MW (pri)
17 Total
57.74%
~?65%
6.21%
0.02%
3.92%
5.51%
706%
0.17%
'1.03%
5.68%
0.52%
4.51%
57.74%
7.65%
6.21%
0.02%
3.92%
5.51%
7 06%
0.17%
1.03%
5.68%
0.52%
4.51%
-
-
-
-
-
100.00%
10000%
57.74%
7.65%
6.21%
0.02%
3.92%
5.51%
7.06%
0.17%
103%
5.68%
0.52%
4.51%
-
-
100.00%
62.04%
6.11%
4.96%
0.01%
2.84%
3.98%
5.10%
012%
0.66%
3.65%
0.33%
5.76%
243%
1.99%
100.00%
62.04%
6.11%
4.96%
0.01%
2.84%
3.98%
5.10%
0.12%
0.66%
3.65%
0.33%
5.76%
243%
1.99%
10000%
6204%
6.11%
4.96%
0.01%
2.84%
3.98%
5.10%
0.12%
0.66%
3.65%
0.33%
5.76%
243%
1.99%
-
-
-
-
100 00%
100.00%
100.00%
..
~~-
Sum of Branch Loads
1,2,3.6
1.2.3.4,5,6,7
1,2,3,6
1,2,3,4,5,6,7
Tab: 7.6
(PC 6)
PC7
PacifiCorp
Oregon Circuit Model Study
System-wide Pole and Conductor Costs
Adjusted Oregon Line Costs per Mile
Account365
Conductor
Cost per Mile
" 'Wire Sizes
1
3
3
3
Phase -1/0 ACSR
Phase- 1/0 ACSR
Phase - 447 AAC & 4\0 AAC
Phase -795 AAC & 477 AAC
27,300
47,186
53,129
56,254
$
$
$
$
State
27,027
46,714
52,598
55,691
$
$
$
$
12,430,368
22,947,921
75,818,501
60,059,546
18,879,273
38,426,986
228,562,595
55,887
99,188
371 373
350,610
98696
155,389
1,131143
1 Phase -1/0 ACSR
$
$
$
Wire Size
Poles
Conductors
Total
Costs for Branch 6
3 Phase - 447 AAC & 4\0 AAC
$
277 965
$
252,674
530 640
$
Miles per Branch
Single Phase Miles Per Branch
Three Phase Miles Per Branch
Source: Input Tab
23.74
22.82
2586
30.82
27.60
21.35
26.13
2,354
4,346.
14360
11,375
3,576
7,278
43,288
Costs for Branches 1,2,3,4,5
Total
3 Phase -1/0 ACSR
49 991 $
160,467 $
98,518 $
24,144 $
258,985 $
74,134 $
Wire Size
Poles
Conductors
Total
13 053
28,680
47,812
105,804
$
$
$
$
40,080
75,394
100,410
161,495
Adjustment
Factor
State Specific Account 364 Pole Statistics
Pole Feet
I
Pole Miles
Poles
California
Idaho
Oregon
Utah
Washinqton
IWVominq
Total
$
$
$
$
0.990
0.990
0.990
0.990
Total Line
Construction
Cost
0.908
0.873
0.990
1.180
1.056
0.817
1.000
I
210,458
122,662
333,120
Cost for Branch 7
3 Phase -795 AAC & 477 AAC
$
294,315 I
559,147 I
$
$
853,462 I
5.28
1.85
3.44
Commitment and Demand Costs Per Branch
Wire Sizes
Branches 1,2,3,4,5
1 Phase -1/0 ACSR
3 Phase- 1/0 ACSR
Total Branches 1,2,3,4,5
BranchG
3 Phase- 447 AAC & 4\0 AAC
Branch?
3 Phase -795 AAC & 477 AAC
Total All Branches
Poles
Commitment
I
Total Cost
Conductor
I
I
1 Total Cost 1 Commitment
Demand
.I
Demand
-
$
$
$
49,991
160,467
210,458
$
$
$
49,991
92,840
142,831
$
$
$
67,627
67,627
$
$
$
24,144
98,518
122,662
$
$
$
24,144
44,838
68,982
$
$
$
53,680
53,680
$
277,965
$
142,831
$
135,135
$
252,674
$
68,982
$
183,692
$
$
294,315
1,624,570
$
$
142,831
999,816
$
$
151,484
624,754
559,147
$
$ 1,425,131
$
$
68,982
482,872
$
$
490,165
942,258
Tab: 7.7
-
(PC7)
PC8
PacifiCorp
Oregon Circuit Model Study
Calculation of Hypothetical Circuit Model Branch Cost
(B)
I
Total Cost
Poles
I Conductor
(A)
Conductors Type
(F)
Conductor
Conductor
Branch 1
1 Phase -1/0 ACSR
3 Phase- 1/0 ACSR
Total segment
$
~
$
49,991
160,467
210,458
$
49,991
160,467
210,458
$
~
$
24,144
98,518
122,662
$
§
$
49,991
92,840
142,831
$
24,144
98,518
122,662
$
$
49,991
92,840
142,831
$
'§
24,144
98,518
122,662.
$
§
$
49,991
92,840
142,831
$
24,144
98,518
122,662
$
§
49,991
92,840
142,831
$
$
§
49,991
92,840
142,831
$
142,831
142,831
~
$
NA
NA
24,144
44,838
68,982
$
24,144
44,838
68,982
§
$
24,144
44,838
68,982
§
$
~
67,627
67,627
~
$
53,680
53,680
Branch 2
1 Phase -1/0 ACSR
3 Phase- 1/0 ACSR
Total Segments
$
§
$
~
$
~
$
NA
67,627
67,627
NA
~
$
53,680
53,680
Branch 3
1 Phase -1/0 ACSR
3 Phase- 1/0 ACSR
Total Se_gments
§
$
$
49,991
160,467
210,458
1 Phase -1/0 ACSR
3 Phase- 1/0 ACSR
Total Segments
$
~
$
49,991
160,467
210,458
$
1 Phase -1/0 ACSR
3 Phase- 1/0 ACSR
Total Segments
$
$
49,991
160,467
210,458
$
§
$
24,144
98,518
122,662
$
$
277,965
277,965
$
$
252,674
252,674
$
~
$
~
$
NA
67,627
67,627
NA
~
$
53,680
53,680
Branch 4
~
$
$
NA
24,144
44,838
68,982
§
§
$
24,144
44,838
68,982
$
$
68,982
68,982
~
$
$
67,627
67,627
NA
~
$
53,680
53,680.
Branch 5
~
$
~
NA
$
NA
~
67,627
67,627
$
135,135
135,135
$
53,680
53,680
Branch 6
3 Phase- 447 AAC & 4\0 AAC
Total Segments
$
$
~
$
~
183,692
183,692
Branch 7
~--
.............
3 Phase -795 AAC & 4 77 AAC
Total segment
$3,049,700
$
$
294,315 $ 559,147
294,315 $ 559,147
$1,624,570
$1,425,131
Source- 'System-wide Pole and Conductor Costs' (PC 7) Tab
Tab: 7.8
~
$
142,831 ~
142,831 $
$999,816
68,982 §
68,982 $
$482,872
151,484 ~
151,484 $
$624,754
490,165
490,165
$942,258
7.7
(PC8)
PC9
PacifiCorp
Oregon Circuit Model Study
Pole Demand Calculations
Poles
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
Branch
%Demand
Branch 6 Cost
%Demand
Branch 7 Cost
Branch Demand Cost
Total
Class Cost per Branch(4)
Residential
GS 0-15 kW (sec) (23)
GS >15 kW (sec) (23)
GS (pri) (23)
GS < 50 kW (sec) (28)
GS 51-100 kW (sec) (28)
GS > 100 kW (sec) (28)
GS (pri) (28)
GS 0-300 kW (sec) (30)
GS >300 kW (sec) (30)
GS (pri) (30)
Irrigation
Large GS 1 - 4 MW (sec)
Large GS 1 - 4 MW (pri)
Large GS + 4 MW (sec)
Large GS + 4 MW (pri)
Check Total
$
$
$
$
(D)
(A)
(B)
(C)
1
14.78%
19,973
0.82%
1,235
67,627
88,835
2
14 . 78%
19,973
0.82%
1,235
67,627
88,835
7
3
4
6
5
14.78%
NA
55.66%
NA
NA
19,973
NA
NA
$ 75,215
NA
$
0.82%
3.07%
88.34%
3.07%
3.07%
1,235 $ 4,652 $ 4,652 $ 4,652 $133,822 $
67,627 $ 67,627 $ 67,627
NA
NA
88,835 $ 72,279 $ 72,279 $ 79,868 $133,822 $
1
51,297
6,792
5,516
14
3,482
4,893
6,269
149
913
5,050
458
4,004
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 88,835
$
$
$
$
2
51,297
6,792
5,516
14
3,482
4,893
6,269
149
913
5,050
458
4,004
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 88,835
$
$
$
$
$
$
$
$
$
$
$
$
3
51,297
6,792
5,516
14
3,482
4,893
6,269
149
913
5,050
458
4,004
$
$
$
$
$
$
$
$
$ 88,835
4
44,845
4,418
3,588
9
2,049
2,880
3,690
88
477
2,637
239
4,166
1,759
1,435
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 72,279
Sources: Line 1 & 3 -'Circuit kW Load by Branch' (PC 6)
Line 2 - 'Calculation of Hypothetical Circuit Model
Line 1 X $135,135
Line 4 'Calculation of Hypothetical Circuit Model
Line 3 X $151,484
Line 5- 'Calculation of Hypothetical Circuit Model
Line 7 to 18 -Line 6 X Percent of Branch Load
Tab: 7.9
(E)
5
44,845
4,418
3,588
9
2,049
2,880
3,690
88
477
2,637
239
4,166
1,759
1,435
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 72,279
(F)
6
49,553
4,882
3,965
10
2,264
3,182
4,077
97
527
2,914
264
4,604
1,943
1,586
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$ 79,868
(G)
(H)
100.00%
135,135
100.00%
151,484
624,754
Total
7
Demand Cost
$ 68,876 $ 362,008
40,217
$ 6,122 $
$ 4,972 $
32,659
12 $
$
80
22,597
$ 5,790 $
31,756
$ 8,136 $
$ 10,425 $
40,688
247 $
966
$
2,301
6,520
$
$
$ 12,728 $
36,065
$ 1,155 $
3,273
26,151
$ 1,202 $
11,988
$ 6,528 $
9,785
$ 5,328 $
$
$
$
$
$133,822 $ 624,754
Tab 7.6
Branch Cost' (PC 8) Tab
7.8 For $135,135
Branch Cost' (PC 8) Tab
7.8 For $151,484
Branch Cost' (PC 8) Tab 7.8
'Circuit kW Load by Branch' (PC 6) Tab
(I)
$/kW
Average
$ 177.18
Total
PerkW
$ 195.19
$ 238.03
$ 238.03
$ 238.03
$ 153.35
$ 153.35
$ 153.35.
$ 153.35
$ 115.21
$ 115.21 !
$ 115.21
$ 516.84
$ 75.00
$ 75.00
$
$
-
7.6
(PC9)
PC 10
PacifiCorp
Oregon Circuit Model Study
Conductor Demand Calculations
Conductors
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
'
Branch
%Demand
Branch 6 Cost
%Demand
Branch 7 Cost
Branch Demand Cost
Total
Class Cost per Branch(4)
Residential
GS 0-15 kW (sec) (23)
GS >15 kW (sec) (23)
GS (pri) (23)
GS < 50 kW (sec) (28)
GS 51-100 kW (sec) (28)
GS > 100 kW (sec) (28)
GS (pri) (28)
GS 0-300 kW (sec) (30)
GS >300 kW (sec) (30)
GS (pri) (30)
Irrigation
Large GS 1 - 4 MW (sec)
Large GS 1 - 4 MW (pri)
Large GS + 4 MW (sec)
Large GS + 4 MW (pri)
Check
Total
26
(A)
(B)
$
$
$
1
14.78%
27,150
0.82%
3,997
53,680
84,827
14.78%
27,150
0.82%
3,997
53,680
84,827
$
$
$
$
$
$
$
$
$
$
$
$
1
48,982
6,486
5,267
13
3,324
4,672
5,986
142
872
4,822
438
3,824
$
$
$
-
$
$
$ 84,827
(C)
$
$
$
-
(H)
(G)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
3
48,982
6,486
5,267
13
3,324
4,672
5,986
142
872
4,822
438
3,824
$
2
$ 48,982
$ 6,486
$ 5,267
$
13
$ 3,324
$ 4,672
$ 5,986
$
142
$
872
$ 4,822
$
438
$ 3,824
$
$
$
$
$ 84,827
(F)
3
6
7
4
5
NA
14.78%
55.66%
NA
NA
$ 102,243
27,150
NA
NA
$
NA
0.82%
3.07%
3.07%
3.07%
88.34%
3,997 $ 15,053 $ 15,053 $ 15,053 $433,013 $
NA
53,680 $ 53,680 $ 53,680
NA
84,827 $· 68,734 $ 68,734 $117,296 $433,013 $
2
$
(E)
(D)
$
-
$
$
$
$ 84,827
$
$
$
$
$
$
$
$
$
$
$
$
4
42,645
4,202
3,412
8
1,949
2,739
3,509
83
453
2,507
228
3,962
1,672
1,365
$
$
$
$
$ 68,734
Sources: Line 1 & 3 -'Circuit kW Load by Branch' (PC 6)
Line 2- 'Calculation of Hypothetical Circuit Model
Line 1 X $183,692
Line 4- 'Calculation of Hypothetical Circuit Model
Line 3 X $490,165
Line 5- 'Calculation of Hypothetical Circuit Model
Line 7 to 18 -Line 6 X Percent of Branch Load
Tab: 7.10
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
6
5
42,645 $ 72,775
4,202 $ 7,170
3,412 $ 5,823
14
8 $
1,'949 $ 3,326
2,739 $ 4,673
3,509 $ 5,988
142
83 $
774
453 $
2,507 $ 4,279
388
228 $
3,962 $ 6,761
1,672 $ 2,854
1,365 $ 2,329
- $
$
68,734 $117,296
(I)
100.00%
183,692
100.00%
490,165
942,258
Total
7
Demand Cost
$222,865 $ 527,877
54,840
$ 19,810 $
44,533
$ 16,087 $
$
109
39 $
$ 18,733 $
35,930
50,492
$ 26,326 $
$ 33,731 $
64,695
801 $
1,535
$
11,742
$ 7,446 $
$ 41,186 $
64,945
$ 3,738 $
5,895
30,046
$ 3,890 $
$ 21,122 $
27,321
22,299
$ 17,239 $
$
-
-
$
$433,013
$
$
$
-
942,258
Tab 7.6
Branch Cost' (PC 8) Tab
7.8 For $183,692
Branch Cost' (PC 8) Tab
7.8 For $490,165
Branch Cost' (PC 8) Tab 7.8
'Circuit kW Load by Branch' (PC 6) Tab
$/kW
average
$ 267.22
Total
PerkW
$ 284.63.
$ 324.57.
$ 324.57.
$ 324.57.
$ 243.83!
$ 243.83 i
$ 243.83!
$ 243.83 i
$ 207.471
$ 207.47!
$ 207.47
$ 593.81
$ 170.91
$ 170.91
$
- i
$
•
7.6
(PC 10)
PC 11
PacifiCorp
Oregon Circuit Model Study
Pole Commitment Calculations
Poles
Line
Branch
%customer
1
2 Branch 6 Cost
%customer
3
4 Branch 7 Cost
5 Branch Commitment Cost
.6 Total
7
8
9
10 Class Cost per Branch(2)
11 Residential
12 GS 0-15 kW (sec) {23)
13 GS >15 kW (sec) (23)
14 GS (pri) (23)
15 GS <50 kW (sec) (28)
16 GS 51-100 kW (sec) (28)
17 GS > 100 kW (sec) (28)
18 GS (pri) (28)
19 GS 0-300 kW (sec) (30)
20 GS >300 kW (sec) (30)
GS (pri) (30)
21
22 Irrigation
23 Large GS 1 - 4 MW (sec)
24 Large GS 1 - 4 MW (pri)
25 Large GS + 4 MW (sec)
26 Large GS + 4 MW (pri)
27 Check Total
$
(A)
(B)
{C)
(D)
1
14.57%
2
14.57%
3
14.57%
4
NA
NA
3.74%
-
0.97%
$
$142,831
$142,831
1
$110,055
$ 22,318
$ 3,577
15
$
890
$
685
$
381
$
11
$
29
$
75
$
7
$
$ 4,788
$
$
$
$
$142,831
$
0.97%
$
$142,831
$142,831
2
$ 110,055
$ 22,318
$ 3,577
15
$
$
890
$
685
$
381
11
$
$
29
$
75
$
7
$ 4,788
$
$
$
$
$142,831
-
$
0.97%
$
$142,831
$142,83.1
3
$ 110,055
$ 22,318
$ 3,577
15
$
890
$
$
685
381
$
11
$
29
$
75
$
7
$
$ 4,788
$
$
$
$
$142,831
-
$
$142,831
$142,831
4
$115,209
$ 17,384
$ 2,786
12
$
627
$
483
$
269
$
$
8
18
$
47
$
4
$
$ 5,965
12
$
7
$
$
$
$142,831
(E)
(F)
(I)
(H)
(G)
7
6
5
56.30%
NA
100.00%
NA
NA
$
$Per
NA
$
3.74%
85.87%
100.00% Customer
3.74%
$
$
$
$
average
$142,831 $142,831 $142,831
$142,831 $142,831 $142,831 $ 999,816 $ 923.98
~
5
$ 115,209
$ 17,384
$ 2,786
$
12
$
627
$
483
$
269
$
8
$
18
$
47
$
4
$ 5,965
$
12
$
7
$
$
$142,831
6
$115,209
$ 17,384
$ 2,786
12
$
627
$
483
$
269
$
8
$
18
$
47
$
4
$
$ 5,965
12
$
7
$
$
$
$142,831
7
$ 119,805
$ 16,310
$ 2,614
11
$
$ 1,199
923
$
514
$
15
$
59
$
153
$
14
$
$ 1,165
30
$
18
$
$
$
$142,831
Total
Commitment
Cost
$ 795,597
$ 135,417
$ 21,704
91
$
$
5,749
4,424
$
2,465
$
73
$
201
$
518
$
47
$
$ 33,425
65
$
39
$
$
$
$ 999,816
$Per
Customer
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
882.45
1,076.48
1,076.48
1,076.48
673.89
673.89
673.89
673.89
492.62
492.62
492.62
2,438.27
320.55
320.55
-
-
Sources: Line 1 & 3 -'Average Customers by Hypothetical Circuit Branch' (PC 5) Tab 7.5
Line 2- 'Calculation of Hypothetical Circuit Model Branch Cost' (PC 8) Tab 7.8 For$ 0
Line 1 X$ 0
Line 4- 'Calculation of Hypothetical Circuit Model Branch Cost' (PC 8) Tab 7.8 For$ 0
Line 3 X$ 0
Line 5- 'Calculation of Hypothetical Circuit Model Branch Cost' (PC 8) Tab 7.8
Line 7 to 18 -Line 6 X Percent of Customers 'Average Customers by Hypothetical Circuit Branch' (PC 5) Tab
Tab: 7.11
7.5
(PC 11)
PC 12
PacifiCorp
Oregon Circuit Model Study
Conductor Commitment Calculations
Conductors
Line
1
2
3
4
s,
e;
Branch
%customer
Branch 6 Cost
%customer
Branch 7 Cost
Branch Commitment Cost
Total
$
(A)
(B)
(C)
(D)
(E)
1
14.57%
2
14.57%
3
14.57%
4
NA
NA
3.74%
6
5
56.30%
NA
NA
$
3.74%
3.74%
-
$
0.97%
$
$ 68,982
$ 68,982
0.97%
$
$ 68,982
$ 68,982
$
-
0.97%
$
$ 68,982
$ 68,982
$
$ 68,982
$ 68,982
$
$ 68,982
$ 68,982
(F)
$
$ 68,982
$ 68,982
(H)
(G)
7
100.00%
NA
$Per
NA
$
100.00% Customer
85.87%
-
$
$ 68,982
$ 68,982
7
8
91
10
11
12
13
14
15,
16
17
18
19
20
21
22
23
24
25
26
27
Class Cost per Branch(2)
Residential
GS 0-15 kW (sec) (23)
GS >15 kW (sec) (23)
GS (pri} (23)
GS <50 kW (sec) (28)
GS 51-100 kW (sec) (28)
GS > 100 kW (sec) (28)
GS (pri) (28)
GS 0-300 kW (sec) (30)
GS >300 kW (sec) (30)
GS (pri) (30)
Irrigation
Large GS 1 - 4 MW (sec)
Large GS 1 - 4 MW (pri)
Large GS + 4 MW (sec)
Large GS + 4 MW (pri)
Check Total
1
$ 53,152
$ 10,779
$ 1,728
7
$
430
$
331
$
184
$
$
5
$
14
$
36
$
3
$ 2,312
2
$ 53,152
$ 10,779
$ 1,728
7
$
430
$
$
331
184
$
$
5
14
$
$
36
3
$
$ 2,312
$
$
$
$
$
-
$
-
$
$ 68,982
-
$
$ 68,982
3
$ 53,152
$ 10,779
$ 1,728
$
7
$
430
$
331
$
184
$
5
$
14
$
36
$
3
$ 2,312
$
$
$
$
$ 68,982
-
4
$ 55,641
$ 8,396
$ 1,346
$
6
303
$
233
$
130
$
4
$
9
$
23
$
2
$
$ 2,881
6
$
3
$
$
$
$ 68,982
5
$ 55,641
$ 8,396
$ 1,346
$
6
$
303
$
233
130
$
$
4
$
9
$
23
2
$
$ 2,881
$
6
$
3
$
$
-
U~,_913~
6
$ 55,641
$ 8,396
$ 1,346
6
$
303
$
233
$
130
$
4
$
9
$
23
$
2
$
$ 2,881
6
$
3
$
$
$
$ 68,982
(I)
7
$ 57,861
$ 7,877
$ 1,262
$
5
$
579
$
446
$
248
7
$
$
29
$
74
$
7
$
563
$
14
$
9
$
$
$ 68,982
$
-
$ 482,872
Total
Commitment
Cost
$ 384,243
$ 65,401
$ 10,482
44
$
2,776
$
2,137
$
1,191
$
35
$
97
$
250
$
23
$
$ 16,143
32
$
19
$
$
$
$ 482,872
$
average
446.25
$Per
Customer
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
426.19
519.90
519.90
519.90
325.46
325.46
325.46
325.46
237.92
237.92
237.92
1,177.59
154.81
154.81
-
-
Sources: Line 1 & 3 -'Average Customers by Hypothetical Circuit Branch' (PC 5) Tab 7.5
Line 2- 'Calculation of Hypothetical Circuit Model Branch Cost' (PC 8) Tab 7.8 For$ 0
Line 1 X$ 0
Line 4- 'Calculation of Hypothetical Circuit Model Branch Cost' (PC 8) Tab 7.8 For$ 0
Line 3 X$ 0
Line 5- 'Calculation of Hypothetical Circuit Model Branch Cost' (PC 8) Tab 7.8
Line 7 to 18 - Line 6 X Percent of Customers 'Average Customers by Hypothetical Circuit Branch' (PC 5) Tab
Tab: 7.12
7.5
(PC 12)
PC 13
PacifiCorp
Oregon Circuit Model Study
Dedicated Circuit Trunk Costs
For Large Customers
Voltage Delivery
Large GS + 4 MW (pri)
Poles
Conductor
1 Construction Cost Per Mile
2 Average Trunk Length
3 Total Construction Cost
$
$
55,691 $ 105,804
0.67 miles
37,313 $
70,889
4 Customer Peak Demand
4,532 kW
5 Demand Cost $/kW
$8.23
Large GS + 4 MW (sec)
Poles
Conductor
$
$
55,691 $ 105,804
0.67 miles
70,889
37,313 $
3,097 kW
$15.64
$12.05
$22.89
Construction Costs for Distribution Line type - 3 Phase -795 AAC & 477 AAC.
Line 1 -'System-wide Pole and Conductor Costs" (PC 7) Tab 7.7
Line 2 - Distribution Engineering Studies
Line 3- Line 1 multiplied by Line 2
Line 4- 'Circuit Distribution Model Inputs & Calculations' (PC 3) Tab
Line 5 - Line 3 divided by Line 4
Tab:7.13
7.3
(PC 13)
PC 14
PacifiCorp
Oregon Circuit Model Study
Trunk All Demand Costs
Outer Branches Commitment & Demand
Three Phase As Needed
[
I
Class
(C)
(B)
(A)
I
Commitment $/Customer
]
I
Poles
(D)
Demand $/Dist. kW
Conductor
Poles
I
Conductor
Conductor
Residential
$
882.45
$
426.19
$
195.19
$
284.63
901.6
1,854.63
$
362,008
$
GS 0-15 kW (sec) (23)
$
1,07648
$
519.90
$
238.03
$
324.57
125.8
168.96
$
40,217
$
54,840
GS >15 kW (sec) (23)
$
1,07648
$
519.90
$
238.03
$
324.57
20.2
137.21
$
32,659
$
44,533
GS (pri) (23)
$
1,07648
$
519.90
$
238.03
$
324.57
0.1
0.34
$
80
$
109
GS < 50 kW {sec) (28)
$
673.89
$
32546
$
153.35
$
243.83
8.5
147.36
$
22,597
$
35,930
GS 51-100 kW (sec) (28)
$
673.89
$
32546
$
153.35
$
243.83
6.6
207.08
$
31,756
$
50,492
GS > 100 kW (sec) (28)
$
673.89
$
325.46
$
153.35
$
243.83
3.7
265.33
$
40,688
$
64,695
GS (pri) (28)
$
673.89
$
325.46
$
153.35
$
243.83
0.1
6.30
$
966
$
1,535
$
492.62
$
237.92
$
115.21
$
207.47
0.4
56.60
$
6,520
$
11,742
313.04
64,945
GS 0-300 kW {sec) (30)
GS >300 kW (sec) (30)
$
492.62
$
237.92
$
115.21
$
207.47
1.1
GS (pri) (30)
$
492.62
$
237.92
$
115.21
$
207.47
0.1
Irrigation
$
2,438.27
$
1,177.59
$
516.84
$
593.81
Large GS 1 - 4 MW (sec)
$
320.55
$
154.81
$
75.00
$
Large GS 1 - 4 MW (pri)
$
320 55
$
154.81
$
75.00
$
$
923.98
$
446.25
$
177.18
TotalLarge GS + 4 MW (sec)
$
$
$
Large GS + 4 MW (pri)
$
$
f$
Commitment
Source
$
36,065
$
28.41 '
$
3,273
$
5,895
13.7
50.60
$
26,151
$
30,046
170.91
0.2
159.85
$
11,988
$
27,321
170.91
0.1
130.47
$
9,785
$
22,299
$
267.22
1,082.1
3,526.2
$
624,754
$
942,258
12os l $
22.89
$
37,313
$
70,889
$
37,313
$
70,889
$
699,380
$
1,084,035
Demand
$
999,816
$
699,380
$
Conductor
$
482,872
$
1,084,035
$
1,566,908
Total
$
.. - 1,482,688
$
1,783,<4_1.(3
$
3,266,104
(A)- PoleCommrtmentCalculatJons' (PC 11) Tab 711
(B)- Conductor Commitment Calculations' (PC 12) Tab 7 12
(C)- Pole Demand Calculatrons' (PC 9) Tab 7 9
(D)- Conductor Demand Calculatrons' (PC 10) Tab 8 10
(E)- Average Customers by Hypothetical Circuit Branch' (PC 5) Tab
(F)- Circurt kW Load by Branch' (PC 6) Tab 7.6
Tab 7.14
3,096.54
I
Total
Poles
Column
Column
Column
Column
Column
Column
527,877
1,699,196
75
(PC 14)
XFMR 1
PacifiCorp
Oregon Marginal Cost Study
Transformer Commitment Costs
Line
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
Customer Type
(A)
(B)
(C)
(D)
(E)
(F)
(G)
Percent of
Customers
Dollars
I Tran.
Weighted
$/Tran.
(A)x(B)
#Cust.
I Tran.
Transformer
$/Gust.
(C) I (D)
Average
Customers
Tot. Trans.
Commitment $
(E)x(F)
Res - Schedule 4
100.00%
300.92
300.92
3.69
$81.55
485,586
$39,599,538
GS - Schedule 23
1 Phase
3 Phase
0-15kW
82.15%
17.85%
100.00%
300 92
855.06
247.20
152.64
3.37
3.59
$73.35
$42.52
$115.87
63,644
$7,374,508
1 Phase
3 Phase
15+ kVV
45.12%
54.88%
100.00%
300.92
855.06
$40.28
$130.72
$171.D1
10,200
$1,744,264
Primary
100.00%
43
$0
$65.60
$442.65
$508.24
4,489
$2,281,505.21
$27.38
$552.19
$579.57
3,455
$2,002,414
$4.23
$618.51
$622.74
1,925
$1,198,773
56
$0
$1.17
$779.40
$780.57
200
$156,114
$0.00
$782.43
$782.43
515
$402,951
GS - Schedule 28
1 Phase
3 Phase
0-50 kW
3.37
3.59
-
29.81%
70.19%
100.00%
30092
855 06
1 Phase
3 Phase
51-100 kW
12.44%
87.56%
100.00%
300.92
855.06
1 Phase
3 Phase
> 101kW
1.93%
98.07%
100.00%
300.92
855.06
89.71
600.16
37.44
748.69
5.79
838.60
1.37
1.36
1.37
1.36
1.37
1.36
-
Primary
100.00%
GS - Schedule 30
1 Phase
3 Phase
0-300 kW
0.39%
99.61%
100.00%
300.92
855.06
0.00%
100.00%
100.00%
300.92
855.06
1 Phase
3 Phase
301+ kW
135.76
469.29
1.17
851.75
85506
1.00
1.09
1.00
1.09
0
0
0.00
0
47
$0
85506
1.07
0.00
1.07
0.00
0.00
795.57
0
795.57
0
0
102
61
2
32
9
$81,148
$0
$1,591
$0
$0
43.84
730.49
1.50
1.23
8,046
$4,996,533
Primary
100.00%
LPS - Schedule 48T
1-4 MW (sec)
1-4MW (pri)
>4MW (sec)
> 4MW (pri)
Trans (trn)
100.00%
100.00%
100.00%
100.00%
100.00%
855.06
855.06
855.06
Schedule 41- Irrigation
1 Phase
3 Phase
Total
14.57%
85.43%
100.00%
300 92
855.06
Tab: 8.1
$29.13
$591.86
$621.00
(XFMR1)
XFMR2
PacifiCorp
Oregon Marginal Cost Study
Transformer Demand Costs
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Customer Type
(A)
(B)
Weighted
$/kW
Transformer
Peak
kWs
(C)
Tot. Trans.
Demand$
(A) X (B)
Res - Schedule 4
(sec)
$1.97
3,327,351
$6,554,882
GS - Schedule 23
0-15 kW
15+ kW
Primary
(sec)
(sec)
(pri)
$1.97
$1.97
$0.00
184,263
126,512
0
$362,999
$249,228
$0
GS - Schedule 28
0-50 kW
51-100 kW
> 101kW
Primary
(sec)
(sec)
(sec)
(pri)
$1.97
$1.97
$1.97
$0.00
141,470
189,067
233,629
0
$278,696
$372,462
$460,249
$0
GS - Schedule 30
0-300 kW
301+ kW
Primary
(sec)
(sec)
(pri)
$1.97
$1.97
$0.00
48,729
259,445
0
$95,995
$511,107
$0
LPS - Schedule 48T
1-4 MW
1-4 MW
> 4MW
> 4MW
Trans
(sec)
(pri)
(sec)
(pri)
(trn)
$1.97
$0.00
$1.97
$0.00
$0.00
132,222
0
13,624
0
0
$260,477
$0
$26,838
$0
$0
Irrigation- Schedule 41 (Average)
Secondary
(sec)
$1.97
150,187
$295,868
4,806,498
$9,468,801
Totals
Tab: 8.2
(XFMR 2)
XFMR3
PacifiCorp
Oregon Marginal Cost Study
Calculation of Escalation Factors for Transformers
(Regression weighted by number of transformer banks)
Line
1
2
3
4
5
6
7
8
9
10
11
12
Description
(A)
(B)
(C)
(D)
(E)
Demand
Related
Adjusted for
System Power
Factor of 0.95
Commitment
Related
Indexed to
2014
Annualized $
@ 9.74%
(A) I 0.95
(B) or (C)
X 1.0370
(D) x 9.74%
1 Phase $/kW
$18.53
$19.51
$20.23
$1.97
3 Phase $/kW
$18.53
$19.51
$20.23
$1.97
$3,089.52
$300.92
$8,778.83
$855.06
1 Phase
$/Transformer
$2,979.28
3 Phase
Dummy Variable
$5,486.32
3 Phase
$/Transformer
$8,465.60
I
Index
2012
1.0000
2014
1.0370
I
Escalation
Factor
2012-2014
1.0370
Tab: 8.3
(XFMR 3)
DistOM
PacifiCorp
Oregon Marginal Cost Study
Distribution O&M Expense
Loading Factor as a Percent of Dist. Plant
(Excluding Meters and St Ltg)
line
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
Description
Distribution 0 & M Expenses
Total Distribution 0 & M Expense
Less:
585 St Ltg & Signal Systems
586 Meter Expense
587 Customer Installation Expense
596 Main. of St Ltg & Signal Systems
597 Main. of Meters
Total Adjusted Distribution 0 & M Expense
line 1 - (Lines 3 through 7)
Distribution Plant
Total Distribution Plant
Less:
370 Meters
373 Street lighting
Adjusted Distribution Plant
Line 14- Line 16- Line 17
0 & M Expense Loading Factor
Distribution 0 & M Loading
Line 9/ Line 19
(A)
(B)
(C)
(D)
(E)
(F)
(G)
(H)
(I}
(J)
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
48,559,856
48,811,823
71,993,550
67,011,911
68,781,531
71,602,482
73,614,647
71,075,634
69,087,864
66,557,786
1,800,451
9,542
814,491
825,166
13,067
2,010,097
90,751
756,545
1,190,462
89,965
1,892,897
62,896
885,374
1,237,234
45,553
2,122,259
48,057
2,058,440
843,436
1,348,150
851,273
1,669,096
75,549
2,206,057
3,636,287
945,804
1,560,945
64,882
2,848,811
3,568,921
910,118
1,433,131
59,174
2,878,301
4,456,390
1,008,869
1,465,615
58,882
2,873,361
4,466,370
1,065,645
1,360,896
63,875
3,548,094
4,633,258
1,251,031
1,386,968
45,110,206
44,750,901
67,825,184
62,652,513
64,154,665
63,177,840
64,788,784
61,207,285
59,262,711
55,674,560
1,303,063,520
1,341,098,219
1,384,196,236
1,431,636,624
1,476,365,173
1,530,307,351
1,590,201,846
1,645,851,699
1,694,776,599
1,733,406,361
57,067,003
16,135,274
56,828,689
16,827,066
56,705,794
17,637,977
58,095,163
18,351,472
58,456,991
19,120,699
59,168,811
20,208,050
59,791,712
21,082,794
60,319,849
21,494,031
60,008,209
21,743,089
59,771,898
21,961,746
1,229,861,243
1,267,442,464
1,309,852,465
1 ,355,189,989
1,398,787,483
1,450,930,490
1,509,327,340
1,564,037,819
1,613,025,300
1,651,672,717
3.67%
3.53%
4.59%
4.35%
4.29%
3.91%
3.67%
3.37%
Average Distribution 0 & M Loading
Average of Line 24
4.12%
Distribution Annual Charge
9.74%
Annualized Distribution 0 & M Loading Factor
Line 27 I line 30
I
5.18%
4.62%
.. 423o";,J
Footnotes:
Source: FERC Form 1 (State of Oregon) & Results of Operations
Tab: 9.1
(DistOM)
Services 1
PacifiCorp
Oregon Marginal Cost Study
Weighted Average Installed Service Drop Costs
Res - Schedule 4 I GS - Schedule 23 I GS - Schedule 28
(A)
(B)
(C)
(D)
% of Customers
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
Load Class
Res - Schedule 4
Annualized- Line 1 x 9J4%
Customers
1 & 3 Phase
(A)I(A,Ttl)
1 Phase
(A)/10
474,231
100.00%
100.00%
47,268
2,367
7,089
9,446
66,169
71.44%
3.58%
10.71%
14.28%
10000%
86.96%
15+ kW
1 Phase
3 Phase
Total 15+ kW
Annualized- Line 16 x 9J4%
4,785
5,820
10,605
45.12%
54.88%
100.00%
Primary
12.47 KV 4-wire Wy_e
Annualized- (Line 20) x 9.74%
44
100 00%
GS - Schedule 23
0-15 kW
kW 0, 1 Phase
kW 0, 3 Phase
kW > 1, 1 Phase
kW > 1, 3 Phase
Total 0-15 kW
Annualized- line 10 x 9.74%
=
=
GS - Schedule 28
0-50 kW
1 Phase
3 Phase
Total 0-50 kW
Annualized- Line 27 x 9J4%
3 Phase
(A)/30
20.04%
13.04%
100.00%
79.96%
100.00%
100.00%
100.00%
100.00%
100.00%
(E)
Overhead
Service
Drop Cost
$914
$1,121
$1,022
$1,207
$1,835
$2,170
(F)
(G)
Underground
Service
Overhead
%
Oro~ Cost
$737
$1,021
$780
$1 076
$1,376
$1,969
67.2%
67.2%
67.2%
67.2%
67.2%
67.2%
(H)
(I)
Underground
%
Weighted
Service
Oro~ Cost
32.8%
32.8%
32.8%
32.8%
32.8%
32.8%
1,338
3,149
4,487
29.81%
70.19%
100.00%
100.00%
51-100 kW
1 Phase
3 Phase
Total 51-100 kW
Annualized- Line 33 x 9.74%
430
3,024
3,453
12.44%
87.56%
10000%
100.00%
>101kW
1 Phase
3 Phase
Total > 101kW
Annualized - Line 39 x 9. 74%
37
1,887
1,924
1.93%
98.07%
100.00%
Primary
12.47 KV 4-wire Wye
Annualized- (Line 43) x 9.74%
57
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
100.00%
$1,835
$2,170
$1,835
$2,170
$3,311
$3,880
100.00%
$1,376
$1,969
$1,376
$1,969
$4,153
$3 861
49.8%
49.8%
49.8%
49.8%
49.8%
49.8%
50.2%
50.2%
50.2%
50.2%
50.2%
50.2%
1 & 3 Phase
(B)x(E)
1 Phase
(C)x(E)
$709.69
$69.12
$709.69
$69.12
$856
$1,088 .
$943
$1,164
$611.26
$38.93
$101.00
$166.18
$917.37
$89.35
$744.10
$1,685
$2104
$1,605
$2,069
$1,605
$2,069
$3,734
$3 871
$0
(L)
Weighted Service DroE! Cost
$710
$0
$(1.00
100.00%
(K)
(J)
$760.02
$1,154.96
$1,914.98
$186.52
$0.00
$218.05
$122.95 .
$867.05
$84.45
$930.90
$1,148.95
$111.91
$1,684.59
$1,684.59
$164.08
$2,104.36
$2,104.36
$204.96
$0.00
$0:00
$0.00
$0.00
$478.36
$1,452.47
$1,930.83
$188.06
$1,604.66
$199.62
$1,811.92
$2,011.54
$195.92
$1,604.66
$71.89
$3,796.04
$3,867.93
$376.74
$3,734.24
$0.00
$0.00
3 Phase
(D)x(E)
$1,604.66
$156.29
$1,604.66
$156.29
$2,069.36
$2,069.36
$201.56
$2,069.36
$2,069.36
$201.56
$3,734.24
$363.71
$3,870.55
$3,870.55
$376.99
$0.00
$0.00
$0.00
Footnote:
Column A -Customer inputs from Pricing Dept- data based on 12 months ended June 2012.
Tab: 10.1
(Services 1)
Services 2
PacifiCorp
Oregon Marginal Cost Study
Weighted Average Installed Service Drop Costs
GS - Schedule 30 I LPS -Schedule 48T
(A)
(B)
% of Customers
line
Load Class
Customers
1 & 3 Phase
(A) I (A, Ttl)
(E)
(F)
Overhead Underground
Service
Service
Drop Cost
Drop Cost
(G)
(H)
(I)
Overhead
%
Underground
%
Weighted
Service
Drop Cost
(J)
Weighted Service Drop Cost
1 & 3 Phase
(B) x (E)
GS- Schedule 30
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
0-300 kW
1 Phase
3 Phase
Total 0-300 kW
Annualized - line 6 x 9. 74%
1
214
215
0.39%
99.61%
100 00%
$3,311
$3,880
$4,153
$3,861
26.9%
26.9%
73.1%
73.1%
$3,927
$3,866
$15.22
$3,851.06
$3,866.28
$376.58
301+ kW
1 Phase
3 Phase
Total 301+ kW
Annualized- line 12 x 9.74%
0
553
553
0.00%
100.00%
100.00%
$8,171
$8,171
$7,200
$7,200
26.9%
26.9%
73.1%
73.1%
$7,461
$7,461
$0.00
$7,460.56
$7,460.56
$726.66
Primary
12.47 KV 4-wire Wy_e
Annualized- Line 16 x 9.74%
51
100.00%
$0
$0.00
$0.00
LPS - Schedule 48T
1-4 MW (sec)
Annualized- line 20 x 9.74%
107
100.00%
$25,243
$25,242.65
$2,458.63
1-4MW (pri)
Annualized- line 23 x 9.74%
64
100.00%
$0
$0.00
$0.00
>4MW (sec)
Annualized- line 26 x 9.74%
2
100.00%
$25,243
$25,242.65
$2,458.63
> 4MW
(pri)
Annualized- Line 29 x 9.74%
33
100.00%
$0
$0.00
$0.00
Trans (trn)
Annualized- Line 32 x 9.74%
6
100.00%
$0
$0.00
$0.00
$25,243
$25,243
0.0%
0.0%
1000%
100.0%
Footnote:
Columns (E) & (F)- see Tab 10.3 (Services 3:) ·summary of Average Installed Costs Service Drops'
Tab: 10.2
(Services 2)
Services 3
PacifiCorp
Oregon Marginal Cost Study
Summary of Average Installed Costs
Service Drops
(A)
line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
(B)
(C)
(D)
(E)
Cost
Indexed to
2014
(B) x 1.0370
Percent
Use
Total Cost
~er Service
#2 Triplex•
1/0 Triplex
1/0 Triplex
410 Triplex
$612
$703
$711
$752
$635
$729
$737
$780
OH • 1/0 Triplex
UG • 1/0 Triplex
$881
$711
$914
$737
$1,081
$985
$1,121
$1,021
$986
$752
$1,022
$780
Service
Conductor
Load Class
Residential
OH • small load
OH • all electric
UG • small load
UG - all electric
0-15 kW
kW = 0, 1 Phase
kW = 0, 3 Phase
OH • 1/0 Quadruplex
UG • 1/0 Quadruplex
kW > 1, 1 Phase
OH • 4/0 Triplex
UG - 4/0 Triplex
kW > 1, 3 Phase
OH • 4/0 Quadruplex
UG 410 Quadruplex
$1,164
$1,038
$1,207
$1,076
OH • 2-4/0 Triplex
UG • 2-4/0 Triplex
$1,770
$1,327
$1,835
$1,376
OH • 2-4/0 Quadruplex
UG • 2-4/0 Quadruplex
$2,093
$1,899
$2,170
$1,969
3-500 & 350N
3- 750 & 500 N
$3,193
$4,005
$3,311
$4,153
OH 3-4/0 Quadruplex
4-350 Quad
$3,742
$3,723
$3,880
$3,861
3-750 kcmil Quad
4-750 kcmil Quad
$7,879
$6,943
$8,171
$7,200
$24,342
$25,243
33.6%
29.0%
15.7%
21.7%
$212.94
$211.45
$115 94
$169.35
$709.69
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
16-100 kW
1 Phase
3 Phase
101-300 kW
1 Phase
3 Phase
301 1000 kW
3 Phase
1000 kW and Over
Secondary Volt(1)
12-1000 kcmil Quad.
Primary Volt
Index
2012
1.0000
2014
1.0370
Escalation
Factor
2012.2014
1.0370
Weighted%
Residential Overhead % =
% of Overhead Which Are Small Load=
% of Overhead Which Are All Electric=
62.6%1
53.6%
46.4%
Residential Underground % =
% of Underground Which Are Small Load=
% of Underground Which Are All Electric=
Total OH & UG
37.4%1
42.0%
58.0%
Tab: 10.3
33.6%
29.0%
15.7%
21.7%
100.0%
(Services 3)
Meters 1
PacifiCorp
Oregon Marginal Cost Study
Weighted Average Installed Meter Costs
Res - Schedule 4 I GS - Schedule 23 I GS - Schedule 28
(A)
(B)
(C)
(D)
(E)
% of Customers
Line
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
Load Class
Res- Schedule 4
Annualized- (line 1) x 9.74%
Customers
1 & 3 Phase
(A)/(A,Ttl)
1 Phase
(A) 110
474,231
100.00%
100.00%
47,268
2,367
7,089
9,446
66,169
71.44%
3.58%
10.71%
14.28%
100.00%
86.96%
15+kW
1 Phase
3 Phase WIO KVAR
3 Phase With KVAR
Total 15+ kW
Annualized- (line 17) x 9.74%
4,785
4,536
1,284
10,605
45.12%
42.77%
12.11%
100.00%
Primary
12.47 KV 4-wire Wy_e
Annualized- (line 21) x 9.74%
44
100.00%
GS - Schedule 23
0-15 kW
kW; 0, 1 Phase
kW; 0, 3 Phase
kW> 1,1 Phase
kW > 1, 3 Phase
Total 0-15 kW
Annualized (line 10) x 9.74%
GS - Schedule 28
0-50kW
kW ; 0, 1 Phase
kW; 0, 3 Phase
kW > 1, 1 Phase
kW > 1 , 3 Phase
Total 0-50 kW
Annualized- (line 30) x 9.74%
3 Phase
(A) 130
13.04%
79.96%
100.00%
100.00%
100.00%
77.93%
22.07%
100.00%
100.00%
0
5
1,337
3,145
4,487
0.01%
0.11%
29.80%
70.08%
100.00%
0.03%
51-100 kW
1 Phase
3 Phase WIO KVAR
3 Phase With KVAR
Total 51-100 kW
Annualized- (line 37) x 9.74%
430
1,508
1,516
3,453
12.44%
43.67%
43.89%
100.00%
100.00%
> 101kW
1 Phase
3 Phase WIO KVAR
3 Phase With KVAR
Total > 101kW
Annualized (line 44) x 9.74%
37
716
1,171
1,924
1.93%
37.20%
60.88%
100.00%
100.00%
Primary
12.47 KV 4-wire Wy_e
Annualized (line 48) x 9.74%
57
100.00%
0.15%
99.97%
100.00%
100.00%
100.00%
(G)
(H)
Weighted Metering Cost
20.04%
100.00%
(F)
99.85%
100.00%
49.87%
50.13%
100.00%
37.93%
62.07%
100.00%
100.00%
Metering
Cost
1 & 3 Phase
(B) x(E)
1 Phase
(C)x(E)
$114
$114.39
$11.14
$114.39
$11.14
$94
$209
$167
$209
$66.95
$7.47
$17.90
$29.81
$122.13
$11.90
$81.50
$206
$209
$247
$12,931
$206
$209
$206
$209
$206
$209
$247
$1,057
$1,441
$1,441
$12,931
3 Phase
(D) x(E)
$41.84
$21.79
$103.29
$10.06
$166.99
$208.83
$20.34
$205.78
$92.84
$89.32
$29.86
$212 02
$20.65
$205.78
$20.04
$162.75
$54.40
$217.15
$21.15
$12,931.38
$1,259.52
$0.00
$12,931.38
$1,259.52
$0.02
$0.22
$61.33
$146.36
$207.93
$20.25
$0.06
$0.32
$205.72
$205 78
$2004
$208.52
$208.84
$20.34
$25.60
$91.19
$108.21
$225.00
$21.92
$205.78
$20.36
$536.20
$877.51
$1,434.07
$139.68
$1,057.41
$1,057.41
$102.99
$546.72
$894.74
$1,441.46
$140.40
$12,931.38
$1,259.52
$0.00
$12,931.38
$1,259.52
$205.78
$20.04
$104.15
$123.58
$227.73
$22.18
Footnote:
Column A- Customer inputs from Pricing Dept- data based on 12 months ended June 2012.
Tab: 11.1
(Meters 1)
Meters 2
GS
~
PacifiCorp
Oregon Marginal Cost Study
Weighted Average Installed Meter Costs
Schedule 30 I LPS ~ Schedule 48T I Irrigation ~ Schedule 41 (Annual)
(A)
(B)
Customers
1 & 3 Phase
(A)I(A,Ttl)
(C)
(D)
(E)
(F)
% of Customers
Une
1
2
3
4
5
6
7
Load Class
GS ~ Schedule 30
0~300 kW
1 Phase
3 Phase WIO KVAR
3 Phase With KVAR
Total 0~300 kW
Annuahzed- (line 6) x 9.74%
1 Phase
(A)I10
0.39%
81.52%
100.00%
100 00%
0.00%
10000%
18.09%
(H)
We1ghted Metering Cost
3 Phase
(A)I30
10000%
1
39
175
215
(G)
18.16%
81 84%
Metenng
Cost
$1.057
$1,441
$1,441
100 00%,
1 & 3 Phase
(B)x(E)
1 Phase
(C) x{E)
$4.10
$260.76
$1,175.11
$1,439.97
$140.25
$1.057.41
$0.00
$22635
$1,215.11
$1,441.46
$140.40
$1,193 92
$1,057.41
$10299
3 Phase
{D)x(E)
(F)x974%
$261 78
$1,179.68
$1.441 46
$140 40
8
9
10
11
12
13
14
301+ kW
1 Phase
3 Phase WIO KVAR
3 Phase With KVAR
301+ kW
Annualized- (Line 13) x 9_74%
0
87
466
553
84.30%
100.00%
15
16
17
18
Primary
12 A 7 KV 4~wire Wye
Annualized- (Line 17) x 9.74%
51
100 00%
100 00%
$12,931
$12,931.38
$1,259.52
$12,931.38
$1,259 52
LPS ~ Schedule 48T
1 ~ 4 MW (sec)
Annualized- (Une 21) x 9_74%
107
100 00%
100 OQ%.,
$1,861
$1,861.16
$181.28
$1,86116
$18128
64
100.00%
100 00%
$12,931
$12,931.38
$1,259 52
$12,931 38
$1,259.52
>4MW
(sec)
Annualized- (Une 27) x 9]4%
2
100.00%
100 00%
$1,861
$1,86116
$181.28
$1,86116
$181.28
>4MW (2ri)
Annualized- (Line 30) x 9_74%
33
100 00%
100 00%
$12,931
$12,931.38
$1,259.52
$12,931.38
$1.25952
Trans (tm)
Annualized- (l1ne 33) x 9_74%
6
100 00%
100 00%
$325,785
$325,784.84
$31,73144
$325,78484
$31,731 44
52
187
997
4,865
0.72%
2.59%
13_83%
67.47%
7897%
$94
$209
$167
$209
$0 68
$5.42
$2311
$140 89
1 Phase
3 Phase WIO KVAR
3 Phase With KV AR
1
311
776
505%
12 59%
$206
$209
$247
$003
$901
$26.52
$0.20
10.76%
> 300 kW
1 Phase
3 Phase W/0 KVAR
3 Phase With KVAR
T ota! Irrigation
$1,194
$1,441
$1,441
$000
$0.20
$4.16
$21002
$2046
$0 00
1
21
7,211
$163 48
$1592
$0.23
$4.87
$217.94
$2123
$000
$0.00
$0.00
$000
$0.00
19
20
21
22
23
24
25
26
27
28
29
30
31
1 ~4 MW
Annualized
(2ri)
15_70%
100 00%
15 70%
8430%
100 00%
$1,194
$1,441
$1,441
(Line 24) x 9.74%
$1,193 92
$11629
$226 35
$1,21511
$1,441.46
$140.40
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
lmgat1on - Schedule 41 (Annual)
0 ~50 kW
kW 0, 1 Phase
kW 0, 3 Phase
kW > 1, 1 Phase
kW > 1, 3 Phase
=
=
495%
304%
94 95%
$4.64
$634
$158.64
$164.92
51~300kW
Primary
0.01%
4.31%
0.00%
001%
0.29%
100 00%
100 00%
010%
0.00%
0 02%
100 00%
0.34%
100 00%
100 00%
$0
$10.54
$31.04
Footnote
Co!umn A- Customer inputs from Pnc1ng Dept- data based on 12 months ended June 2012
Tab 11.2
iMeters2)
Meters 3
PacifiCorp
Oregon Marginal Cost Study
Incremental Three Phase
Meter and Services Costs
(A)
(B)
(D)
(C)
(E)
(F)
Meters
Line
Load Class
Single
Phase
Three
Phase
Residential
0-15 kW
(H)
Service Drops
Difference
Annualized
Difference
(B)- (A)
1
2
3
(G)
Single
Phase
Three
Phase
Difference
(F)- (E)
(C) X
9.74%
Annualized
Difference
(G) x
9.74%
$114.39
$208.83
$94.44
$9.20
$709.69
$1,083.72
$374.04
$36.43
$93.72
$208.83
$115.11
$11.21
$942.77
$1 '164.15
$221.38
$21.56
$205.78
$208.83
$3.06
$0.30
$1,684.59
$2,104.36
$419.77
$40.89
$1,193.92
$1,441.46
$247.54
$24.11
$3,734.24
$3,870.55
$136.31
$13.28
N.A
$1,861.16
N.A
4
5
6
7
8
9
16-100 kW
101-1000 kW
1-4MW
N.A.
Tab: 11.3
N.A
$25,242.65
N.A
N.A
(Meters 3)
Meters 4
PacifiCorp
Oregon Marginal Cost Study
Summary of Average Installed Costs
Meters
Load Class
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
(A)
(B)
(C)
(D)
(E)
Metering
Standard
Meter Cost in
2013 Dollars
Indexed to
2014
Percent
Use
Total Installed Cost
eer Meter
_Residential
Small Load
All Electric)
DM221A
DM221D
$92.00
$132.00
$93.72
$134.47
49.28%
50.72%
100.00%
$46.18
$68.20
$114.39
0-15 kW
kW 0. 1 Phase
=
DM221A
$92.00
$93.72
100.00%
$93.72
=0, 3 Phase
DM241A
$205.00
$208.83
100.00%
$208.83
kW > 1, 1 Phase
DM221B
$164.00
$167.07
100.00%
$167.07
kW > 1, 3 Phase
DM241A
$205.00
$208.83
100.00%
$208.83
DM221C
$202.00
$205.78
100.00%
$205.78
3 Phase wo I KVAR
DM241A
$205.00
$208.83
100.00%
$208.83
3 Phase with KVAR
DM241B
$242.00
$246.53
100.00%
$246.53
DM231ABB
$1,038.00
$1.057.41
100.00%
$1,057.41
3 Phase wo I KVAR
DM271AEC
$1,415.00
$1,441.46
100.00%
$1,441.46
3 Phase with KVAR
DM271AEC
$1,415.00
$1.441.46
100.00%
$1,441.46
300-1000 kW
W/0 KVAR, 1 Phase
DM231AFE
$1,172.00
$1,193.92
100.00%
$1,193.92
W/0 KVAR, 3 Phase
DM271AEC
$1,415.00
$1,441.46
100.00%
$1,441.46
W/KVAR, 3 Phase
DM271AEC
$1,441.46
100.00%
$1,441.46
100.00%
$1.861.16
kW
15- 100 kW
1 Phase
.17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
100 300 kW
1 Phase
$1,415.00
1000 kW and over
Secondary Volt
DM271AEG
$1,827.00
$1,861.16
Prima[Y Metering
13.8 KV 3-wire
12.47 KV 4-wire Wye
24.9 KV 4-wire Wye
35 KV 4-wire Wye
DM101ACBI
DM121DBBI
DM121DGBI
DM131DBH
$7,872.00
$12,694.00
$15,232.00
$30,170.00
$8,019.21
$12,931.38
$15.516.84
$30,734 18
Index
2013
1.0180
2014
1.0370
$8,019.21
$12,931.38
$15,516.84
$30,734.18
Escalation
Factor
2013- 2014
1.0187
Tab: 11.4
(Meters 4)
Meters 5
PacifiCorp
Oregon Marginal Cost Study
Distribution Meters Expense
Loading Factor
Line
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Description
Distribution Meters Exeenses
586 Meter Expense
597 Main. of Meters
Total Adjusted Distribution Meters Expens
Line 1 + Line 2
(A)
(8)
(C)
(D)
(E)
(F)
(G)
(H)
(I)
(J)
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
1,800,451
825,166
2,010,097
1'190,462
1,892,897
1,237,234
2,122,259
1,348,150
2,058,440
1,669,096
2,206,057
1,560,945
2,848,811
1,433,131
2,878,301
1,465,615
2,873,361
1,360,896
3,548,094
1,386,968
2,625,617
3,200,559
3,130,131
3,470,409
3,727,536
3,767,002
4,281,942
4,343,916
4,234,257
4,935,062
57,067,003
56,828,689
56,705,794
58,095,163
58,456,991
59,168,811
59,791,712
60,319,849
60,008,209
59,771,898
Distribution Meters
370 Meters
Meters Exeense Loading Factor
Meter O&M Loading
Line 3 I Line 4
4.60%
Average Meter O&M Loading
Averagt~ of Line 5
6.41%
Distribution Annual Charge
9.74%
Annualized Meter O&M Loading Factor
Line 6 I Line 7
[
5.63%
5.52%
5.97%
6.38%
6.37%
7.16%
7.20%
7.06%
6586%1
Tab: 11.5
(Meters 5)
8.26%
Streetlight 1
PacifiCorp
Oregon Marginal Cost Study
Street Light and Recreational Lighting
Commitment & Billing Related Cost per Customer
Schedule 53
Line
Schedule 54
Customer Owned
Description
100 Watt 150 Watt 250 Watt 400 Watt
1
2
3
4
5
6
7
8
9
10
11
12
13
14
HPSV
HPSV
HPSV
HPSV
Light Installation Cost- per lamp
$180.40
$194.70
$217.82
$291.28
N. A.
N. A.
Distribution Commitment Costs - per customer
Acct. 364 Poles
Acct. 365 Conductors
Acct. 368 Transformers
Dist O&M at 42.3% of Annual Charge
Acct. 370 Meters
Meter O&M at 65.86% of Annual Charge
Total Commitment Related
$108.73
$52.51
N. A.
$68.20
N. A.
N. A.
$229.44
$108.73
$52.51
N. A.
$68.20
N. A.
N. A.
$229.44
$108.73
$52.51
N. A.
$68.20
N. A.
N. A.
$229.44
$108.73
$52.51
N. A.
$68.20
N. A.
N. A.
$229.44
$108.73
$52.51
115.87
$117.22
N. A.
N. A.
$394.33
$108.73
$52.51
171.01
$140.54
$11.90
$7.84
$492.52
$39.36
$39.36
$39.36
$39.36
$39.36
$63.13
$268.80
$268.80
$268.80
$268.80
$433.69
$555.66
Billing Costs per Customer
Total Marginal Commitment & Billing Cost per Gust.
Sources:
Line 1
Line 4
Line 5
Line 6
Line 7
Line 14
"Distribution Cost Development For Street Lighting"
·Hypothetical Circuit Study Results Annual Demand and Commitment Costs'
·Hypothetical Circuit Study Results Annual Demand and Commitment Costs'
'Transformer Commitment Costs By Customer Load Class'
Sum of lines 4 to 6 multiplied by
Distribution O&M Expense Loading Factor as a Percent of Dist. Plant'
Sum of Commitment & Billing Costs per Customer
Tab: 12.1
(Streetlight 1)
Streetlight 2
PacifiCorp
Oregon Marginal Cost Study
Street Light and Recreational Lighting
Full Marginal Cost by Schedule
line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
Description
Enemy
Generation Energy $/kWh @ Generator
Transmission Energy $/kWh @ Generator
Energy
Energy
Losses
@Meter 2012
Energy
@Generator- (5)'(6)
Un1t~
9,500 Lumen
16,000 Lumen
27,500 Lumen
50.000 Lumen
100Watl
150Watt
250 Watt
400 Watl
~-
$0 04337
$000304
$0 04337
$0 00304
$0 04337
$0 00304
$0 04337
$0 00304
so 04337
$0 00304
$0.04337
$0 00304
kWh
7.622.922
7,923.559
110006
8.716.390
245.348
255.024
1 10006
280,542
678.794
705,565
1 10006
776.164
2,460,628
2,557,672
1.10006
2,813,593
9.668,960
8,966,764
1.10006
9,863.978
1205.229
1249.347
1 10006
1,374.357
$378.030
$26,477
$12,167
$852
$33.662
$2,358
$122,026
$8,547
$427,801
$29,963
$59.606
$4.175
180,082
15.007
$18040
$2.707.181
3,985
332
$194.70
$64.655
6.136
511
$217.82
$111,378
14,532
1,211
$291 28
$352,741
272
43
62
70
266
104
kWh
Generation Energy Related Marginal Costs (1)"(7)
Transmission Energy Related Marg1nal Costs- (2)*(7)
Average customers- 2014 (from blockmg)
Schedule 53
Schedule 54
Customer Owned
$/kWh
$/kWh
@Meter 2014
Commitment
Total of Monthly Lamp Billing Units 2014
Number of Lamps 2014- (13) /12
Light Installation Cost
light Installation Related
!
Schedule 51
High Pressure Sodium Vapor
l
#
#
$/Lamp
#
Acct_ 364 Poles
Acct. 365 Conductors
Acct 368 Transformers
$108.73
$52 51
NA
$108 73
$5251
$108 73
$5251
$108.73
$52.51
N A
N.A
N A.
364 Poles with O&M
365 Conductors w1th O&M
368 Transformers with O&M
370 Meter with O&M
Poles, Conductors, Transfomers
$42,062
$20.313
$6.653
$3,213
$9.593
$4.633
$10.831
$5.231
N.A
N.A
NA
NA
NA
NA
N.A
NA
$62,375
$9,866
$14,226
$16,061
Total Commitment Marg1nal Cost
Billing I Customer
Billing Related
Meter Reading
Customer Other
Billing Related
Meter Reading
Customer Other
Total Billing Related Marginal Cost
$/Customer
$/Customer
$/Customer
$
$108 73
$52.51
$115 87
$108.73
$5251
$171.01
$11 90
$41.173
$19.884
$43.877
$16,091
$7,771
$25,308
$2,053
$51,222
NA
$104.935
$2,769,556
$74,522
$125.603
$368,802
$104.935
$51.222
$31 10
$31 10
$3110
$31.10
$3110
$8 26
$826
$826
$8 26
$826
$3110
$23 78
$8.26
Total Marginal Cost
Generation
TransmJss1on
D1stnbutwn
Customer- Bll!tng
Customer· Metcnng
(' ustomcr - Other
Generatwn
TransmiSSIOn
D1stnbu110n
Customer- Billing
Customer- Metenng
Customer- Other
23.825,024
$1.033.291
$72,371
817
$126,403
$61,045
$69,185
$2.053
$258,685
$3,494,640
8455
1,337
1.928
2,177
8,276
2245
$10,699
355
$1,692
512
$2.440
578
$2,755
2.197
$10,473
3,234
2,473
859
$6.566
$25,408
$2,473
$6,745
$34,626
$3,184,762
$89.233
$164.063
$502,129
$573,172
$121.569
$4,634,928
Sch. 51
$545,885
$38,233
$3.338,482
$13,897
Sch 53
$427,801
$29,963
$104.935
8,276
3,690
$3,940,187
2.197
$573,172
Sch. 54
$59,606
$4.175
$51,222
3.234
2,473
859
$121,569
Sch 51
$545 88
$3823
$3,338 48
$13.90
$0.00
$3 69
$427 80
$29 96
$104 93
$8 28
$0 00
$2.20
$
$
21.657.931
$3.235,955
Acct. 370 Meters
Acct
Acct.
Acct.
Acct
Total
Total
Street!!gh1J.D_g
Tab: 12 2
Sch 53
Sch-._~
$5961
$417
$51 22
$3 23
$2 47
so 86
Iota!
$1,033.291
$72,371
$3,494,640
$25,408
$2,473
$6,745
$4.634.928
Total
$1,03329
$72 37
$3,494.64
$2541
$247
$6 75
(Streetlight 2)
Streetlight 3
PacifiCorp
Oregon Marginal Cost Study
Distribution Cost Development
For Street Lighting Service
Fully-Loaded Overheads
Wood Pole Installations
Schedule 51
Line No.
Description
High Pressure Sodium Vapor
9,500 Lumen 16,000 Lumen 27,500 Lumen
100 Watt
150 Watt
250 Watt
1
2
3
4
5
6
7
Installed Cost Per Unit
Lamp Cost per unit including pole, luminaire,
p.e.control, mast arm and wiring
Without Pole (Functional)
Wood Pole Cost
Percent of Wood Pole Utilized (see footnote)
Adjusted Wood Pole Cost
50,000 Lumen
400 Watt
$741.00
$816.00
16.67%
$136.00
$756.00
$940.00
20.00%
$188.00
$926.00
$885.00
20.00%
$177.00
$1,339.00
$884.00
50.00%
$442.00
$877.00
1.0187
$893.37
$944.00
1.0187
$961.62
$1,103.00
1 0187
$1,123.59
$1,781.00
1 0187
$1,814.24
$13.55
1.0370
$14.05
$19.81
1.0370
$20.54
$35.33
1.0370
$36.64
$54.21
1.0370
$56.22
$90742
$982.16
$1,160.22
$1,87046
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Installed Lamp Cost for Analysis
Index
RevisedLampCost
2013' $
Transformer Cost
Index
Revised Transformer Cost
2012' $
2014'$
2014' $
Total Installed Cost
Annual Cost @
9.74%
$88.38
$95.66
$113.01
$182.18
Operation & Maintenance
Annual Maintenance Per Unit
Index
2013'$
2014'$
$90.33
1 0187
$92.01
$97.22
1 0187
$99.03
$102.89
1.0187
$104.81
$107.10
1 0187
$109.10
2014' $
$180.40
$194.70
$217.82
$291.28
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
Total Cost per Unit
Assumptions:
Annual Maintenance Per Unit- Percentage of installed cost from 11/99 study.
100 Watt It is assumed, one new wood pole is to be installed per six new lights, therefore, 1/6 X unit cost of wood pole will be utilized here as a component.
200 Watt It is assumed, one new wood pole is to be installed per five new lights, therefore, 1/5 X unit cost of wood pole will be utilized here as a component.
400 Watt It is assumed, one new wood pole is to be installed per two new lights, therefore, 1/2 X unit cost of wood pole will be utilized here as a component.
Tab: 12.3
(Streetlight 3)
Streetlight 4
PacifiCorp
Oregon Marginal Cost Study
Cost of Streetlighting Transformer
Transformer Cost Per Light- 100 Watt
Assume Installed Cost* 25 KVA Transformer is
Lamp Line Watts
=
Transformer Cost= Total Wattsl25,000 X Installed Cost
117 I 25000 X $2896 =
Transformer Cost Per Light- 250 Watt
$
2,896
117 watts
$
Lamp Line Watts
=
Transformer Cost= Total Wattsl25,000 X Installed Cost
171 I 25000 X $2896 =
=
Lamp Line Watts
Transformer Cost= Total Wattsl25,000 X Installed Cost
305 I 25000 X $2896 =
13.55
Transformer Cost Per Light - 150 Watt
Assume Installed Cost* 25 KVA Transformer is
$
Assume Installed Cost* 25 KVA Transformer is
2,896
305 watts
$
35.33
$
2,896
Transformer Cost Per Light- 400 Watt
$
2,896
Assume Installed Cost* 25 KVA Transformer is
171 watts
$
Lamp Line Watts
19.81
Tab: 12.4
=
Transformer Cost= Total Wattsl25,000 X Installed Cost
468 I 25000 X $2896 =
468 watts
$
(Streetlight 4)
54.21
CustExpSum
PacifiCorp
Oregon Marginal Cost Study
Summary of Customer Accounting Expense
By Schedule
December 2014 Dollars
(A)
Line
FERC Account
Sch.4
Residential
Description
Average Number of Customers
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Write-offs By Schedule
901
Supervision
902
Meter Reading Expense
903
Cust. Receipts & Collect.
904
Uncollectibles
905
Mise Cust Acct Expense
Account 902 + 903 + 904
% of Total 902 + 903 +904
Total901 $
Dollars Per Customer
5,322,978
(D)
(C)
(F)
(E)
(G)
(H)
Sch.23
Sch. 28
Sch. 30
Sch. 41
Sch.48T
General Service General Service General Service General Service Irrigation Streetlighting
73,887
145,937
9,924
762
206
3,920
212,760
114,009
133,722
7,103
817
Total
575,102
5,936,510
$29,755,314
83.21%
$752,909
$1.55
$4,293,634
12.01%
$108,643
$1.47
$960,790
2.69%
$24,311
$2.45
$188,631
0.53%
$4,773
$6.26
$191,271 $339,418
0.53%
0.95%
$4,840
$8,588
$23.49
$2.19
$29,649 $35,758,707
100.00%
0.08%
$750
$904,815
$0.92
$1.57
902 Weighting Factor
Weighted Customers
%of Total$
Total902 $
Dollars Per Customer
1.00
485,586
76.71%
$8,130,885
$16.74
1.42
104,920
16.57%
$1,756,823
$23.78
2.47
24,512
3.87%
$410,445
$41.36
4.24
3,231
0.51%
$54,099
$71.00
3.13
11.05
12,269
2,276
1.94%
0.36%
$38,115 $205,439
$52.41
$18503
0.31
253
633,047
100.00%
0.04%
$4,241 $10,600,048
$18.43
$5.19
903 Weighting Factor
Weighted Customers
%of Total$
Total903 $
Dollars Per Customer
1.00
485,586
84.89%
$16,595,627
$34.18
0.95
70,193
12.27%
$2,398,939
$32.47
1.03
10,222
1.79%
$349,343
$35.20
1.03
785
0.14%
$26,824
$35.20
3.81
0.95
3,724
785
0.14%
0.65%
$26,824 $127,268
$130.21
$32.47
0.91
572,037
743
0.13%
100.00%
$25,408 $19,550,232
$31.10
$33.99
Total904 $
% of Write-offs
Dollars Per Customer
$5,028,802
89.67%
$10.36
$137,872
2.46%
$1.87
$201,002
3.58%
$20.25
$107,708
1.92%
$141.35
$126,332
2.25%
$613.26
$29,755,314
83.21%
$75,687
$0.16
$4,293,634
12.01%
$10,921
$0.15
$960,790
2.69%
$2,444
$0.25
$188,631
0.53%
$480
$0.63
$191,271 $339,418
0.53%
0.95%
$487
$863
$2.36
$0.22
485,586
84.43%
$3,518,623
$7.25
73,887
12.85%
$535,395
$7.25
9,924
1.73%
$71 ,911
$7.25
762
0.13%
$5,522
$7.25
Account 902 + 903 + 904
% of Total 902 + 903 +904
Total905 $
Dollars Per Customer
907-910
Supervision, Cust. Assist. Average Number of customers
Info & Instructional Exp.,
%of Total
Mise Cust Svc & Info Exp.
Dollars Per Customer
Total901 -910
485,586
(B)
Total901 - 910$
Dollars Per Customer
$34,102,533
$4,948,594
$1,059,456
$199,406
c:=$7023
$66.98
$106.76
$26169
Tab: 13.1
206
0.04%
$1,493
$7.25
$6,711
0.12%
$1.71
3,920
0.68%
$28,404
$7.25
$198,090 $377,273
$961.60
$96.25
$0
0.00%
$0.00
$5,608,427
$9.75
$29,649 $35,758,707
0.08%
100.00%
$90,957
$75
$0.09
$0.16
817
0.14%
$5,920
$7.25
575,102
100.00%
$4,167,267
$7.25
$36,394 $40,921,746
$44.55
$71.16
I
(Gust Exp Sum)
Cust Exp Year
PacifiCorp
Oregon Marginal Cost Study
Summary of Customer and Metering Expenses
December 2014 Dollars
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
Description
Customer Accounting
901 Supervision
902 Meter Reading Expense
903 Gust Records & Collection
904 Uncollectible Accounts
905 Mise Gust Acct Expense
Total
Customer Service & Info Exeense
907 Supervision
908 Gust Assistance Expense
909 Info & Instructional Expense
910 Mise Gust Svc & Info Expense
Total
Distribution Exeenses
586 Meter Expenses
597 Meter Maintenance
(1) Inflation Adjustment -
(A)
(B)
(C)
(D)
(E)
Actual
2007
Dollars
Actual
2008
Dollars
Actual
2009
Dollars
Actual
2010
Dollars
Actual
2011
Dollars
(F)
Adjusted
2014
Dollars
[(A) X 1.1381+
(B) x 1.1172+
(C) X 1.0968+
(D) X 1.0767+
(E) x 1.0570 ]/5
900,404
9,563,375
17,918,701
3,555,170
124,686
:32,062,336
768,055
9, 190,112
18,662,255
6,272,907
77,974
34,971,303
788,080
9,195,750
18,060,493
4,220,604
87,564
32,352,491
769,087
9,874,311
17,281,809
4,470,369
55,759
32,451,335
897,646
10,531,128
17,116,692
7,138,600
65,934
35,750,000
$904,815
$10,600,048
$19,550,232
$5,608,427
$90,957
$36,754,479
138,616
2,488,601
1,248,551
1,429
3,877,197
77,577
1,998,956
1,236,009
19,976
3,332,518
88,905
2,164,154
1,706,781
46,577
4,006,417
81,203
2,165,667
1,433,382
27,745
3,707,997
92,542
2,441,612
1 ,491 ,095
56,083
4,081,332
$105,437
$2,470,343
$1,558,651
$32,836
$4,167,267
$40,921,746
$2,206,057
$1,560,945
$3,767,002
$2,848,811
$1,433,131
$4,281,942
$2,878,301
$1,465,615
$4,343,916
$2,873,361
$1,360,896
$4,234,257
$3,548,094
$1,386,968
$4,935,062
$3,138,882
$1,583,279
$4,722,161
1.1381
1.1172
1.0968
1.0767
1.0570
Source:
Source: State of Oregon results of operations
Tab: 13.2
(Gust Exp Year)
AG Expenses
PacifiCorp
Oregon Marginal Cost Study
Administrative & General Expense
Loading Factor
Year
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
(A)
(B)
(C)
Administrative
and General
Expenses
(000)
Electric
Plant in
Service
(000)
Admin. & General
to Electric Plant
In Service
Loading Factor
(A) I (B)
$277,395
$251,357
$244,893
$236,709
$238,645
$180,356
$170,044
$162,620
$146,076
$152,657
$12,690,449
$13,208,159
$13,688,398
$14,335,797
$15,317,103
$16,417,338
$18,224,943
$19,645,569
$21,775,587
$22,769,524
2.19%
1.90%
1.79%
1.65%
1.56%
1.10%
0.93%
0.83%
0.67%
0.67%
10 Year Average A&G to EPIS Loading Factor
1.33%
Footnotes:
(A) FERC Form 1 Page 322-323
(B) FERC Form 1 Page 206-207
Tab: 14.1
(AG Expenses)
Charge 1
PacifiCorp
Oregon Marginal Cost Study
Calculation of Annual Charges
(A)
(B)
(C)
(D)
(E)
20 yearsGeneration
10 yearsGeneration
5 yearsGeneration
System
Transmission
Distribution
Levelized Income Taxes*
Levelized Property Tax*
Total
NA
NA
NA
NA
NA
NA
NA
NA
NA
1.93%
1.14%
3.07%
1.94%
1.16%
3.10%
Levelized Income & Property Taxes
(per $1,000 of Investment)
NA
NA
NA
$30.70
$31.00
Expected Life
20
10
5
58
50
7.66%
7.66%
7.66%
7.66%
7.66%
NA
NA
NA
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
Description
Nominal Interest Rate *
Present Value: Income **
Taxes & Property Taxes per
$1,000 of Investment
$395.47
$394.82
(PVof $30.70 per year (PV of $31.00 per year
for 58 years at 7.66%) for 50 years at 7.66%)
Removal Cost Per $1,000 Investment
Present Value: Removal Cost
at End of Useful Life
Investment and Taxes
wlo PVCD (Line 12 +Line 18 + $1000)
$204.38
$463.24
$2.83
(PV of $204.38 in
58 years at 7.66%)
$11.59
(PV of $463.24 in
50 years at 7.66%)
$1,000.00
$1,000 00
$1,000.00
$1,398.30
$1,406.41
NA
NA
NA
0.020533
0.041839
NA
NA
NA
$28.71
$58.84
$1,000.00
$1,000.00
$1,000 00
$1,427.01
$1,465.25
$80.39
$126.64
$222.70
$79.99
$84.11
Annual Economic Carrying
Adm &Gen Expense Loading Factor
8.04%
0.00%
12.66%
0.00%
22.27%
0.00%
8.00%
1.33%
8.41%
1.33%
Annual Econ Carrying + A&G loading
8.04%
12.66%
22.27%
9.33%
9.74%
PVCD Factor
PVCD $
(Line 22 x Line 25)
Total (Line 22 + Line 27)
EOY Annual Charge***
Footnotes:
From Financial Analysis - PV = ln(5) x [1/r- (1/r)/(1+r)Aa]
*** The Annual Charge Formula:
Where:
30.70*(1/0.0766-(1/0.0766)/(1+0.0766)A58) r = Nominallnterest Rate
31 00*(1/0 0766-(1/0 0766)/(1+0.0766)A50) a= Expected Investment Life
Where:
AC% = ln(11) x k x {1/[1 - 1/(1 +k)Aa]}/(1 +k) k = real interest rate= (1 + r) I (1 + i)- 1
i =inflation rate=
1.9%
a = expected investment life
r = nominal interest rate
Tab 15.1
(Charge 1)
Charge 2
PacifiCorp
Oregon Marginal Cost Study
Financial Inputs to the Economic Carrying Charge Calculation
(A)
(C)
(B)
Financial Inputs
1
2
3
4
5
6
Levelized
Weighted Cost of Capital
Borrowing Rate
Inflation
Real Cost of Capital
(1 +0.0766)/(1 +0.0187)-1 =
(D)
7.66%
7.66%
1.87%
L
5.68%1
Income Taxes
T ransm iss ion
Distribution
Property Taxes
Transmission
Distribution
1.93%
1.94%
1.14%
1.16%
Source:
Cost of Capital/Borrowing Rate: Revenue Requirement (OR Jurisdictional Allocation Model)
Income & Property Taxes: Financial Analysis, Use of Facilities Charges 12/31/11 Basis (prepared 7/20/12)
Inflation Rate, 2012 Avoided Cost, Table 8
Tab: 15.2
(Charge 2)
Charge3
PactfiCorp
Oregon Marg1nal Cost Study
Present Value of Cost of 01spers!on Factor
Iowa Curve R 3 0 & 58 Year Average L!fe
Page 1 of2
Rea! Cost of Capital =
YEAR
2
3
4
5
6
7
8
9
m
11
~
~
M
15
m
17
ffi
w
m
~
ll
~
~
~
~
v
~
~
~
~
~
~
~
~
~
~
~
~
~
~
G
G
M
~
•
a
•w
Q
~
~
~
~
~
~
9
~
~
w
5.68%
(A)
(B)
(C)
(D)
(E)
(F)
(G)
(H)
(I)
(J)
PVCD
%RENEWED
NUM1
DEM1
NUM1/DEM1
NUM2
DEM2
NUM2/DEM2
INSTANCE
Iowa R 2.5
((A){yr-1}
((J.{yr-1)J.(J))
(B)
(C)/(0)
(B)
(E)-(H)
(Given)
• 100
1 0568
"58
(F)/(G)
+(I)) /100
1 0568
"Year
0 0159
0.0317
0 0317
0.0408
0 0469
00469
0.0616
0 0679
0 0679
0 0897
0.0952
0 0952
0.1268
01303
0.1303
01745
01745
01799
0 2290
0.2290
0.2421
0 2948
0 2948
0 3183
0.3731
0.3731
04098
0.4648
04648
0 5179
0.5710
05710
0.6445
0 6934
0.6934
0 7917
0.8338
0 8338
0.9634
0 9959
09959
11628
1 1814
11814
1.3928
13928
1.4163
16286
1.6286
1.6795
18831
18831
1.9604
21407
21407
22353
2 3772
2 3772
2.4688
2.5603
1 056843
1116918
1180407
1 247506
1 318418
1 393362
1.472565
1 556271
16M734
1 738227
1 837033
1 941457
2 051816
2 168448
2 291710
2 421978
2 559652
2.705151
2858921
3 021432
3 193180
3.374691
3 566520
3 769254
3.983511
4.209947
4 449255
4 702166
4.969453
5.251933
5.550471
5 865979
6.199421
6 551817
6 9242M
7 317842
7 733813
8 173429
8 638035
9129050
9 647976
10 196400
10.775998
11 388543
12.035906
12.720068
13 443120
14 207273
15 014862
15 868358
16 770369
17 7236~
18.731127
19 795868
20 921132
22 110361
23367189
24695459
26 099233
27 582802
0 015009
0 028403
0 026876
0.032727
0 035570
0 033657
0 041846
0 043650
0 041302
0 051618
0 051808
0049021
0.061812
0.060110
0 056877
0.072041
0.068167
0.066514
0080088
0.075780
0 075830
0.087364
0 082665
0 084449
0 093662
0.088624
0.092104
0 098854
0 093537
0 098617
0.102880
0 097347
0.103959
0 105841
0.100148
0 108186
0.107811
0 102013
0.111536
0 109087
0.103220
0 114043
0 109631
0 103734
0.115717
0 109493
0 105358
0114633
0.108467
0.105841
0 112288
0.106248
0 104659
0 108138
0 102322
0.101098
0.101734
0 096262
0 094593
0.092824
00159
00317
0.0317
0 0408
0 0469
00469
0 0616
0.0679
0 0679
0.0897
00952
0 0952
0.1268
0.1303
0.1303
01745
0.1745
01799
0.2290
0 2290
0.2421
0.2948
0.2948
0.3183
0 3731
0.3731
04098
0 4648
0.4648
0.5179
0.5710
0.5710
0.6445
0.6934
06934
0.7917
0 8338
0 8338
0.9634
0.9959
09959
11628
11814
11814
1.3928
1 3928
14163
16286
1 6286
1 6795
1.8831
1.8831
19604
21407
21407
22353
2 3772
23772
24688
25603
24 695459
24 695459
24 695459
24.695459
24 695459
24 695459
0000642
0.001285
0001285
0 001653
0 001899
0.001899
0002495
0.002751
0 002751
0 003633
0 0038~
0 003854
0 005136
0.005278
0 005278
0 007065
0007065
0 007286
0009272
0 009272
0 009805
0011939
0.011939
0 012889
0.015108
0015108
0 016594
0 018822
0 018822
0 020973
0 023123
0 023123
0 026097
0 028080
0 028080
0 032058
0 033763
0 033763
0 039013
0 040326
0.040326
0 047087
0.047838
0 047838
0.056397
0 056397
0 057352
0 065948
0 065948
0 068009
0 076253
0076253
0 079382
0 086684
0 086684
0 090515
0 096262
0 096262
0 099970
0 103677
0 014367
0027119
0.025591
0 031074
0 033671
0 031758
0 039351
0 040899
0 038551
0 047985
0 047954
0045167
0 056677
0 054832
0.051599
0064976
0.061101
0 059228
0 070817
0 066509
0 066025
0 07~26
0 070727
0 071560
0 078554
0 073516
0.075510
0 080032
0.074715
0 0776«
0 079757
0.074224
0077861
0 077761
0 072068
0 076128
0 074048
0 068250
0 072522
0 068761
0 062894
00001M
0.000415
0.000671
0 000982
0 001318
0 001636
0.002029
0002438
0 002824
0 003304
0.003783
0 004235
0.004802
0 005350
0005866
0.006516
0.007127
0 007719
0.008427
0.009092
0 009752
0.010507
0 011214
0.011930
0012715
0 013450
0.014205
0.015006
0.015753
0016529
0.017327
0 018069
0.018848
0019625
0.020346
0021107
0.021848
0 022530
0 0232~
0023943
0.024572
0025242
0.025860
0026419
0 027012
0 027543
0.028023
0.028510
0 028935
0.029313
0 029673
0.029973
0 030226
0030M1
0.030597
0 030703
0 030758
0.030758
0 030704
0 030595
159%
317%
3.17%
408%
469%
469%
6.16%
679%
6.79%
8.97%
9.52%
9.52%
12.68%
13.03°/o
1303%
1745%
1745%
1799%
22.90%
22_90°/o
24.21%
29.48%
2948%
31.83%
3731%
37.31%
4098%
4648%
4648%
5179%
57.10%
5710%
6445%
69_34%
69.34%
7917%
8338%
83 38%
9634%
9959%
99.59%
11628%
118.14%
11814%
139.28%
13928%
14163%
162 86%
162 86%
167 95%
188.31%
18831%
196.04%
214 07%
214 07%
223 53%
237.72%
237 72%
246 88%
256.03%
Tab 15.3
24.69~59
24 695459
24.695459
24695459
24 695459
24.695459
24.695459
24 695459
24.695459
24 695459
24.695459
24.695459
24.695459
24.695459
24.695459
24 695459
24695459
24.695459
24 695459
24.695459
24.695459
24 695459
24 695459
24 695459
24.695459
24.695459
24695459
24.695459
24695459
24.695459
24 695459
24 695459
2469~59
24 695459
2469~59
24.69~59
24.695459
24.69~59
2469~59
24.695459
24695459
24.695459
24695459
24.695459
24.695459
24.69~59
24 695459
24.695459
24.695459
24.695459
24.69~59
24.695459
24.695459
24.695459
0 066956
0061793
0 055896
0 059320
0 053096
0 048006
0.048685
0.042519
0 037831
0 036035
0 029995
0 025277
0 021455
0.015638
0 010583
0 005472
0 000000
-0 005377
-0 010853
100 0000
99 9841
99 9524
99 9207
99 8799
99 8330
99.7861
99 72«
99 6565
99 5886
99.4989
99 4037
99.3085
991817
99 0513
98.9210
98 7465
98.5720
98 3921
981631
97 9342
97 6920
97.3972
97 1024
96 7841
964110
96 0379
95 6281
95.1632
94 6984
94.1805
93.6094
93 0384
92.3939
91 7005
91.0070
90 2153
89.3816
88 5478
87.5843
86 5884
85.5926
84.4298
832484
82 0670
806742
792815
77 8651
762365
74 6079
72 9284
71.0453
691622
67 2018
650611
62 9204
60.6851
58.3079
55.9306
534618
50.9015
(Charge 3)
Charge4
PacifiCorp
Oregon Margrnal Cost Study
Present Value of Cost of O!spers!on Factor
Iowa Curve R 3 0 & 58 Year Average Life
Page 2 of2
YEAR
~
~
~
M
~
00
~
~
00
ro
n
n
~
N
m
ro
77
~
m
00
~
~
~
M
~
00
~
~
00
00
~
~
~
M
%
%
w
••
100
1m
1~
1ro
1M
(A)
(8)
(C)
(D)
(E)
(F)
(G)
(H)
(I)
(J)
PVCD
%RENEWED
NUM1
DEM1
NUM1/DEM1
NUM2
DEM2
NUM2/DEM2
INSTANCE
Iowa R 2.5
( (A){yr-1}
+(I) )1100
((J,{yr-1})-(J))
'100
(8)
10568
(C)I(D)
(8)
0568
'58
(F)I(G)
(E)-(H)
(Grven)
0 030437
0 030227
0 029967
0 029663
0 029320
0 028939
0.028521
0 028089
0 027631
0 027143
0026678
0 026194
0 025688
0 025243
0 024781
0 024313
0.023921
0 023516
0 023122
0 022801
0 022473
0 022167
0 021924
0.021676
0 021458
0.021289
0021118
0 020979
0 020876
0 020771
0 020699
0 020648
0020597
0020571
0020556
0020540
0.020536
0020535
0.020534
0 020533
0020533
0 020533
0 020533
0 020533
256.03%
261 70%
265 48%
26548%
263 96%
263 31%
263 31%
251.34%
0 087831
0 084947
0 081539
0 077153
0 072586
0 068512
0 064827
0 058551
0 054742
0 051798
0 044283
0 041404
0 039177
0 031282
0 029599
0.027440
0021129
0.019992
0 017989
0 013509
0.012783
0011052
0.008153
0 007715
0 006312
0004570
0 004324
0 003249
0.002277
0 002154
0.001392
0 000910
0 000861
0000413
0 000227
0.000215
0 000054
0 000015
0.000014
0 000001
0000000
0 000000
0 000000
0 000000
2.5603
26170
2.6548
26548
26396
26331
2.6331
25134
2.4834
24834
2.2439
22172
2.2172
18710
1.8710
1 8331
14917
14917
14186
1.1259
11259
1.0287
0.8021
0.8021
06935
0.5307
05307
0.4214
03121
0.3121
02132
0.1472
01472
00746
00434
0.0434
00114
00034
00034
0.0003
00000
0.0000
00000
0.0000
0.103677
0 105972
0107503
0 107503
0 106887
0 106623
0106623
0 101775
0100563
0100563
0 090001
0 089783
0 089783
0 075764
0.075764
0 074228
0 060405
0 060405
0057442
0.045590
0 045590
0.041656
0 032478
0032478
0 028083
0.021489
0 021489
0.017063
0 012637
0 012637
0 000032
0.005962
0 005962
0 003020
0 001759
0 001759
0 000464
0 000140
0 000140
0 000014
0000000
0 000000
0 000000
0 000000
-0.015845
-0021025
-0.025%4
-0030349
-0034301
-0.038111
-0 041796
-0.043224
-0045821
-0048765
-0.046578
-0.048379
-0.050606
-0.044482
-0046165
-0 046789
-0039276
-0.040413
-0039453
-0.032081
-0032807
-0 030605
-0.024325
-0.024764
-0.021771
-0016919
-0.017165
-0013814
-0 010360
-0.010482
-0.007240
-0 005052
-0.005101
-0 002608
-0.001532
-0 001544
-0 000410
-0 000124
-0.000125
-0 000013
0.000000
0 000000
0.000000
0 000000
483411
45.7241
43 0693
40 4144
37.7748
35.1417
32 5086
29.9952
27 5118
25.0283
227845
20.5672
18.3500
16.4790
14.6079
12.7748
11.2831
9.7914
8.3728
72470
61211
50924
42903
34882
2 7947
22640
17333
1.3120
09999
0.6878
04747
0.3274
01802
01056
00621
0.0187
00072
00038
00003
00000
00000
0.0000
00000
0.0000
248_34%
248.34%
224 39%
221 72%
221 72%
187.10%
18710%
183.31%
14917%
149.17%
14186%
11259%
112.59%
102 87%
8021%
8021%
6935%
53_07%
53.07%
4214%
31.21%
3121%
2132%
14 72%
14 72%
746%
4.34%
434%
114%
034%
0.34%
0 03%
000%
000%
0.00%
000%
100.0000
A
2.5603
2.6170
2.6548
26548
26396
26331
26331
2.5134
24834
24834
22439
22172
22172
1.8710
1.8710
1.8331
14917
1 4917
14186
11259
1.1259
1.0287
0.8021
08021
0.6935
05307
0.5307
04214
0.3121
03121
02132
01472
0.1472
0.0746
0.0434
00434
0.0114
0 0034
0.0034
00003
0.0000
00000
0.0000
00000
100 0000
Year
29150703
30 807728
32 558944
34409705
36 365670
38432818
40.617470
42 926305
45366382
47.945162
50 670528
53 550813
56 594823
59811865
63 211775
66 804947
70 602368
74 615646
78 857053
83 339556
88 076860
93.083449
98 374628
103 966577
109 876390
116.122138
122.722915
129 698903
137071430
144 863036
153 097544
161800129
170.997398
180 717472
190 990067
201846592
213 320239
225 446087
238261209
251 8M786
266.118227
281245292
297232231
314.127921
24695459
24.695459
24695459
24 695459
24695459
24695459
24695459
24.695459
24695459
24 695459
24695459
24695459
24695459
24.695459
24 695459
24 695459
24695459
24 695459
24695459
24 695459
24695459
24.695459
24.695459
24695459
24695459
24 695459
24.695459
24 695459
24.695459
24 695459
24 695459
24695459
24695459
24695459
24 695459
24695459
24695459
24 695459
24695459
24695459
24.695459
24 695459
24695459
24 695459
"*Source Iowa Curves (09-17 -2008)
Tab 15 4
(Charge 4)
Charge 5
PacifiCorp
Oregon Marginal Cost Study
Present Value of Cost of Dispersion Factor
Iowa Curve R 2.0 & 50 Year Average Life
Real Cost of Caprtal =
YEAR
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
5.68%
(A)
(B)
(C)
(D)
(E)
(F)
(G)
PVCD
%RENEWED
NUM1
DEM1
NUM1/DEM1
NUM2
DEM2
((A){yr-1}
+(I)) /100
((J,{yr-1})-(J))
* 100
(B)
1.0568
/\Year
(C)/(D)
(B)
1.0568
A 50
(F)/(G)
(E)-(H)
0.000897
0.002589
0.004182
0.005949
0.007612
0.009314
0.011044
0.012672
0.014455
0.016131
0.017832
0.019548
0.021159
0.022904
0.024541
0.026188
0.027837
0.029380
0.031032
0.032575
0.034117
0.035648
0.037075
0.038582
0.039983
0.041369
0.042732
0.043993
0.045305
0.046514
0.047694
0.048838
0.049885
0.050951
0.051919
0.052844
0.053720
0.054504
0.055274
0.055953
0.056575
0.057136
0.057613
0.058045
0.058394
0.058677
10.16%
20.32%
20.32%
23.92%
23.92%
26.00%
28.08%
28.08%
32.72%
32.72%
35.34%
37.96%
37.96%
43.84%
43.84%
47.08%
50.32%
50.32%
57.60%
57.60%
61.62%
65.64%
65.64%
74.52%
74.52%
79.40%
84.28%
84.28%
94.92%
94.92%
100.70%
106.48%
106.48%
118.96%
118.96%
125.56%
132.16%
132.16%
146.00%
146.00%
153.06%
160.12%
160.12%
174.16%
174.16%
180.84%
0.1016
0.2032
0.2032
0.2392
0.2392
0.2600
0.2808
0.2808
0.3272
0.3272
0.3534
0.3796
0.3796
0.4384
0.4384
0.4708
0.5032
0.5032
0.5760
0.5760
0.6162
0.6564
0.6564
0.7452
0.7452
0.7940
0.8428
0.8428
0.9492
0.9492
1.0070
1.0648
1.0648
1.1896
1.1896
1.2556
1.3216
1.3216
1.4600
1.4600
1.5306
1.6012
1.6012
1.7416
1.7416
1.8084
1.056843
1.116918
1.180407
1.247506
1.318418
1.393362
1.472565
1.556271
1 644734
1.738227
1.837033
1.941457
2051816
2.168448
2.291710
2.421978
2.559652
2.705151
2.858921
3.021432
3.193180
3.374691
3.566520
3.769254
3.983511
4.209947
4.449255
4.702166
4.969453
5.251933
5.550471
5.865979
6.199421
6.551817
6.924244
7.317842
7.733813
8.173429
8.638035
9.129050
9.647976
10.196400
10.775998
11.388543
12 035906
12.720068
0.096135
0.181929
0.172144
0.191743
0.181430
0.186599
0.190688
0.180431
0.198938
0.188238
0.192375
0.195523
0.185007
0.202172
0 191298
0.194387
0.196589
0.186015
0.201475
0.190638
0.192974
0.194507
0.184045
0 197705
0.187071
0.188601
0.189425
0.179237
0.191007
0.180733
0.181426
0.181521
0.171758
0.181568
0.171802
0.171581
0.170886
0.161695
0.169020
0.159929
0.158645
0.157036
0.148589
0.152926
0.144700
0 142169
0.1016
0.2032
0.2032
0.2392
0.2392
0.2600
0.2808
0.2808
0.3272
0.3272
0.3534
0.3796
0.3796
0.4384
0.4384
0.4708
0.5032
0.5032
0.5760
0.5760
0.6162
0.6564
0.6564
0.7452
0.7452
0.7940
0.8428
0.8428
0.9492
0.9492
1.0070
1.0648
1.0648
1.1896
1.1896
1.2556
1.3216
1.3216
1.4600
1.4600
1.5306
1.6012
1.6012
1.7416
1.7416
1.8084
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
0.006403
0.012805
0.012805
0.015074
0.015074
0.016385
0.017696
0.017696
0.020620
0.020620
0.022271
0.023922
0.023922
0.027627
0.027627
0 029669
0.031711
0.031711
0.036299
0.036299
0.038832
0.041365
0.041365
0.046961
0.046961
0.050037
0.053112
0.053112
0 059817
0.059817
0.063460
0.067102
0.067102
0.074967
0.074967
0.079126
0.083285
0 083285
0.092007
0.092007
0.096456
0.100905
0.100905
0.109753
0.109753
0.113963
0.089733
0.169124
0.159339
0.176669
0.166356
0.170214
0.172992
0.162736
0.178318
0.167618
0.170105
0.171601
0.161085
0.174545
0.163671
0.164717
0.164878
0.154305
0.165176
0.154339
0.154142
0.153141
0.142680
0.150744
0.140110
0.138564
0.136313
0.126125
0.131190
0.120916
0.117966
0.114419
0.104656
0.106601
0.096835
0.092455
0.087601
0.078409
0.077013
0.067922
0.062189
0.056131
0.047684
0.043173
0.034947
0.028206
Tab: 15.5
(H)
(I)
NUM2/DEM2 INSTANCE
(J)
Iowa R 1.5
(Given)
100.0000
99.8984
99.6952
99.4920
99.2528
99.0136
98.7536
98.4728
98.1920
97.8648
97.5376
97.1842
96.8046
96.4250
95.9866
95.5482
95.0774
94.5742
94.0710
93.4950
92.9190
92.3028
91.6464
90.9900
90.2448
89.4996
88.7056
87.8628
87.0200
86.0708
85.1216
84.1146
83.0498
81.9850
80.7954
79.6058
78.3502
77.0286
75.7070
74.2470
72.7870
71.2564
69.6552
68.0540
66.3124
64.5708
62.7624
(Charge 5)
Charge 5
PacifiCorp
Oregon Marginal Cost Study
Present Value of Cost of Dispersion Factor
Iowa Curve R 2.0 & 50 Year Average Life
Real Cost of Caprtal
YEAR
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
5.68%
(A)
(B)
(C)
(D)
(E)
(F)
(G)
PVCD
%RENEWED
NUM1
DEM1
NUM1/DEM1
NUM2
DEM2
((A){yr-1}
+(I)) I 100
0.058890
0.059028
0.059099
0.059099
0.059030
0.058892
0.058691
0.058421
0.058092
0.057705
0.057263
0.056771
0.056235
0.055655
0.055043
0.054402
0.053724
0.053052
0.052349
0.051647
0.050950
0.050229
0.049567
0.048886
0.048234
0.047615
0.046982
0.046441
0.045889
0.045380
0.044918
0.044448
0.044076
0.043699
0.043367
0.043081
0.042793
0.042595
0.042395
0.042235
0.042116
0.041996
0.041944
0.041892
0.041860
0.041849
0.041839
0.041839
((J,{yr-1})-(J))
* 100
187.52%
187.52%
199.48%
199.48%
204.36%
209.24%
209.24%
215.92%
215.92%
217.28%
218.64%
218.64%
216.76%
216.76%
213.28%
209.80%
209.80%
197.88%
197.88%
189.68%
181.48%
181.48%
161.60%
161.60%
150.60%
139.60%
139.60%
116.92%
11692%
105.82%
94.72%
94.72%
73.88%
73.88%
64.24%
54.60%
54.60%
37.08%
37.08%
29.38%
21.68%
21.68%
9.36%
9.36%
5.60%
1.84%
1.84%
0.00%
(B)
1.0568
•Year
13.443120
14.207273
15.014862
15.868358
16.770369
17.723654
18.731127
19.795868
20.921132
22.110361
23.367189
24.695459
26.099233
27.582802
29.150703
30.807728
32.558944
34.409705
36.365670
38.432818
40.617470
42.926305
45.366382
47.945162
50.670528
53.550813
56.594823
59.811865
63.211775
66.804947
70.602368
74.615646
78.857053
83.339556
88.076860
93 083449
98.374628
103.966577
109.876390
116.122138
122.722915
129.698903
137.071430
144.863036
153 097544
161.800129
170.997398
180.717472
50.9667
(C)/(D)
(B)
1.0568
1.8752
1.8752
1.9948
1.9948
20436
2.0924
2.0924
2.1592
2.1592
2.1728
2.1864
2.1864
2.1676
2.1676
2.1328
2.0980
2.0980
1.9788
1.9788
1.8968
1.8148
1.8148
1.6160
1.6160
1.5060
1.3960
1.3960
1.1692
1.1692
1 0582
0.9472
0.9472
0.7388
0.7388
0.6424
0.5460
0.5460
0.3708
0.3708
0.2938
0.2168
0.2168
0.0936
0.0936
0.0560
0.0184
0.0184
0.0000
99.9816
(H)
(I)
NUM2/DEM2 INSTANCE
(F)/(G)
(E)-(H)
0.118172
0.118172
0.125709
0.125709
0.128785
0.131860
0.131860
0.136070
0.136070
0.136927
0.137784
0.137784
0.136599
0.136599
0.134406
0.132213
0.132213
0.124701
0.124701
0.119533
0.114366
0.114366
0 101838
0.101838
0.094906
0.087974
0.087974
0.073681
0.073681
0.066686
0.059691
0.059691
0.046558
0.046558
0.040483
0.034408
0.034408
0.023367
0.023367
0.018515
0.013662
0.013662
0.005899
0.005899
0.003529
0.001160
0.001160
0 000000
0.021319
0.013816
0.007146
0 000000
-0.006927
-0 013803
-0 020153
-0 026996
-0.032863
-0 038656
-0 044217
-0.049249
-0.053547
-0.058014
-0 061241
-0064113
-0.067776
-0067194
-0.070287
-0.070180
-0 069686
-0.072089
-0 066217
-0 068133
-0.065184
-0.061905
-0 063307
-0.054133
-0 055185
-0 050846
-0.046275
-0 046997
-0.037189
-0 037693
-0 033189
-0.028542
-0.028858
-0.019801
-0.019993
-0.015985
-0.011896
-0.011991
-0 005216
-0.005252
-0 003163
-0.001046
-0 001052
0 000000
(J)
Iowa R 1.5
(Given)
•so
0.139491
0.131989
0.132855
0.125709
0.121858
0.118057
0.111707
0.109073
0.103207
0.098271
0.093567
0.088534
0.083052
0.078585
0.073165
0.068100
0.064437
0.057507
0.054414
0.049354
0.044680
0.042277
0.035621
0.033705
0.029721
0.026069
0.024667
0.019548
0.018497
0.015840
0.013416
0.012694
0.009369
0.008865
0.007294
0.005866
0.005550
0.003567
0.003375
0.002530
0.001767
0.001672
0.000683
0.000646
0.000366
0.000114
0.000108
0 000000
Tab: 15.6
1.8752
1.8752
1.9948
1.9948
2.0436
2 0924
2.0924
2.1592
2.1592
2.1728
2.1864
2.1864
2.1676
2.1676
2.1328
2.0980
2.0980
1.9788
1.9788
1.8968
1.8148
1.8148
1.6160
1.6160
1.5060
1.3960
1.3960
1.1692
1.1692
1.0582
0.9472
0.9472
0 7388
0.7388
0.6424
0.5460
0.5460
0.3708
0.3708
0.2938
0.2168
0.2168
0.0936
0.0936
0.0560
0.0184
0.0184
0.0000
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
15.868358
60.8872
59.0120
57.0172
55 0224
52.9788
50.8864
48.7940
46.6348
44.4756
42.3028
40.1164
37.9300
35.7624
33.5948
31.4620
29.3640
27.2660
25.2872
23.3084
21.4116
19.5968
17.7820
16.1660
14.5500
13.0440
11.6480
10.2520
9.0828
7.9136
6.8554
5.9082
4.9610
4.2222
3.4834
2.8410
2.2950
1.7490
1.3782
1.0074
0.7136
0.4968
0.2800
0.1864
0.0928
0.0368
0.0184
0.0000
0.0000
(Charge 5)
CHARGES
PACIFICORP
Remaining Life Depreciation Rates
[1)
Account
Number
[3)
12/31/2006
Balance
[2)
Description
-----
[4)
IOWA
CURVE
$
[5)
Average
Life
Yrs
[6)
[7)
NET SALVAGE
Percent
Amount
%
$
TRANSMISSION PLANT
350.20
352.00
353.00
353.70
354.00
355.00
356.00
356.20
357.00
358.00
359.00
[1)
Account
Number
352.00
353.00
353.70
354.00
355.00
356.00
356.20
357.00
358.00
359.00
61,181,203
55,260,234
907,682,638
55,509,184
380,678,705
508,938,637
630,352,557
30,355,853
3,277,188
7,274,658
11,494,522
2,652,005,379
Land Rights
Structures & Improvements
Station Equipment
Supervisory Equipment
Towers & Fixtures
Poles & Fixtures
OH Conductors & Devices
Clearing
UG Conduit
UG Conductors & Devices
Roads & Trails
Total Transmission Plant
Description
[3)
12/31/2006
Balance
TRANSMISSION PLANT excludes land accounts
Structures & Improvements
Station Equipment
Supervisory Equipment
Towers & Fixtures
Poles & Fixtures
OH Conductors & Devices
Clearing
UG Conduit
UG Conductors & Devices
Roads & Trails
Total Transmission Plant
55,260,234
907,682,638
55,509,184
380,678,705
508,938,637
630,352,557
30,355,853
3,277,188
7,274,658
11,494,522
2,590,824,176
[2)
R5
S1
R1.5
R2
R5
R2.5
R4
S6
R2
R2
R5
7000
000%
-1 00%..
75.00
58.00
-400%
25.00
0.00%
-7.00%}
65.00
-42.00°/o
52.00
60.00
-42.00°/o
65.00
0.00%
60.00
0.00'%
60.00
0.00'%
70.00
0.00%
-20 44%
58.41
Use 58 Years
1.50
2.00
5.00
2.50
4.00
2.00
2.00
5.00
2.13%
35.03%
2.14%
14.69%
19.64%
24.33%
1.17%
0.13%
0.28%
0.44%
100.00%
(552,602)
(36,307,306)
(26,647,509)
(213,754,228)
(264,748,074)
(542,009,719)
0.5255
0.0429
0.7347
0.4911
0.9732
0.0025
0.0056
0.0222
2.7977
UseR 3
PACIFICORP
Remaining Life Depreciation Rates
[1]
Account
Number
[3]
12/31/2006
Balance
[2]
Description
[4]
IOWA
CURVE
[5]
Average
Life
Yrs
$
[6]
[7]
NET SALVAGE
Percent
Amount
%
$
DISTRIBUTION PLANT (OREGON)
360.20
361.00
362.00
362.70
364.00
365.00
366.00
367.00
368.00
369.10
369.20
370.00
371.00
373.00
361.00
362.00
362.70
364.00
365.00
366.00
367.00
368.00
369.10
369.20
370.00
371.00
373.00
Land Rights
Structures & Improvements
Station Equipment
Supervisory & Alarm Equipment
Poles, Towers & Fixtures
OH Conductors & Devices
UG Conduit
UG Conductors & Devices
Line Transformers
Overhead Services
Underground Services
Meters
IO.CP
Street Lighting & Signal Systems
Total OREGON Distribution Plant
3,556,253
12,345,312
160,587,683
2,779,659
282,793,465
210,301,551
75,474,348
133,175,353
340,095,762
60,741,141
122,060,821
58,792,161
2,433,995
19,600 663
1,484,738,167
DISTRIBUTION PLANT excludes land accounts (OREGON)
Structures & Improvements
Station Equipment
Supervisory & Alarm Equipment
Poles, Towers & Fixtures
OH Conductors & Devices
UG Conduit
UG Conductors & Devices
Line Transformers
Overhead Services
Underground Services
Meters
IO.C.P.
Street Lighting & Signal Systems
Total OREGON Distribution Plant
12,345,312
160,587,683
2,779,659
282,793,465
210,301,551
75,474,348
133,175,353
340,095,762
60,741,141
122,060,821
58,792,161
2,433,995
19,600,663
1,481,181,914
R4
R1.5
R1
R2.5
R2
R1.5
R2.5
R2.5
R1.5
R2
R4
R2.5
S1
R1
0.00%
53.00
-5.00%
65.00
-10.00%
52.00
23.00
0.00°/o
-100.00%
49.00
58.00
-80.00%
60.00
-60.00%
-45 00%
58.00
-20.00%
40.00
-25 00%
65.00
55.00
-20 00%
-2,00'%
26.00
25.00
-40 OOOf:o
40.00
-26.00%
-46 32(1/o
50 08
Use 50 years
15
1
2.5
2
1.5
2.5
2.5
1.5
2
4
2.5
0
1
0.83%
10.84%
0.19%
19.09%
14.20%
5.10%
8.99%
22.96%
4.10%
8.24%
3.97%
0.16%
1.32%
100.00%
(617,266)
(16.058,768)
(282,793,465)
(168,241,241)
(45,284,609)
(59,928,909)
(68,019,152)
(15, 185,285)
(24,412,164)
(1 '175,843)
(973,598)
(5,096,172)
(687,786,473)
0.01
0.11
0.00
0.38
0.21
0.13
0.22
0.34
0.08
0.33
0.10
0.00
0.01
1.94 UseR 2
**Source: Depreciation Rates.xls
Tab 15.7
(Charge 6)
Losses
PacifiCorp
Oregon Marginal Cost Study
Energy Loss Factors
Line
1
2
3
4
5
6
7
(A)
(B)
Voltage Level
Energy
Factor
(C)
Energy
Loss
Percent
(D)
Demand
Factor
(E)
Demand
Loss
Percent
Transmission
1.04527
4.53%
1.04259
4.26%
Primary
1.06904
6.90%
1.07920
7.92%
Secondary
1.10006
10.01%
1.11057
11.06%
8
9
10
11
.12
**Source: 2009 Analysis of System Losses
Tab: 16.1
(Losses)
Cust Data 1
PacifiCorp
Oregon Marginal Cost Study
Customers and MWh's
12 Months Ended June 30, 2012- Actual
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
Description
Res - Schedule 4
GS- Schedule 23
0-15 kW
15+kW
Sec Subtotal
Primary
(A)
(B)
(C)
(D)
(E)
(F)
(G)
Del.
Volt
Average
Customers
%Total
Class
Annual
MWh's
%Total
Class
Average
Billing kW
%Total
Class
(sec)
474,231
100.0%
5,408,536
100.0%
4,966,196
100.0%
(sec)
(sec)
66,169
10,605
76,774
44
76,818
86.2%
13.8%
100.0%
604,893
523,765
1,128,658
1 '163
1 '129,820
53.6%
46.4%
100.0%
263,233
180,731
443,964
1,550
445,514
59.3%
40.7%
100.0%
4,487
3,453
1,924
9,865
57
9,922
45.5%
350%
19.5%
100.0%
444,385
673,448
888,469
2,006,302
18,661
2,024,963
22.1%
33.6%
44.3%
100.0%
141,470
189,067
233,629
2,016,169
18,698
2,034,866
7.0%
9.4%
11.6%
28.0%
215
553
768
51
818
28.0%
72.0%
100.0%
202,011
1,030,233
1,232,244
90,666
1,322,910
16.4%
83.6%
100.0%
48,729
259,445
308,174
21,716
329,890
15.8%
84.2%
100.0%
107
98.2%
1.8%
100.0%
65.9%
34.1%
100.0%
531,189
52,257
583,446
492,307
1 117 609
1,609,916
528,557
2,721,919
91.0%
9.0%
100.0%
30.6%
69.4%
100.0%
132,222
13,624
145,845
102,469
227,830
330,299
164,031
640,175
90.7%
9.3%
100.0%
31.0%
69.0%
100.0%
100.0%
217,837
100.0%
150,187
100.0%
(pri)
Total
GS- Schedule 28
0-50 kW
51-100 kW
> 101kW
Sec Subtotal
Primary
(sec)
(sec)
(sec)
(pri)
Total
GS- Schedule 30
0-300 kW
301+ kW
Sec Subtotal
Primary
(sec)
(sec)
(pri)
Total
LPS -Schedule 48T
1-4MW
> 4MW
Sec Subtotal
1-4MW
> 4MW
Pri Subtotal
Trans
(sec)
(sec)
(pri)
(pri)
(trn)
Total
.f.
109
64
33
97
6
212
Irrigation - Schedule 41 (Average)
(sec)
3,444
Irrigation- Schedule 41 (Annual)
(sec)
7,211
Source:
Columns B & D - PacifiCorp, Pricing Department
Tab: 17.1
(Cust Data 1)
CustData 2
PacifiCorp
Oregon Marginal Cost Study
Customers and MWh's
12 Months Ended December 20'14 Normalized
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
Description
Res - Schedule 4
GS - Schedule 23
0-15 kW
15+ kW
Sec Subtotal
Primary
(A)
(B)
(C)
(D)
(E)
(F)
(G)
DeL
Volt
Average
Customers
%Total
Class
Annual
MWh's
%Total
Class
Average
Billing kW
%Total
Class
(sec)
485,586
1000%
5,379,569
1000%
4,966,196
100.0%
(sec)
(sec)
63,644
10 200
73,844
43
73,887
86.2%
13.8%
1000%
589,432
510 378
1,099,810
1,147
1,100,957
53.6%
46.4%
100.0%
263,233
180 731
443,964
1,550
445,514
59.3%
40.7%
100.0%
4,489
3,455
1,925
9,868
56
9,924
45.5%
350%
19.5%
1000%
437,292
662,698
874 287
1,974,277
18,574
1,992,851
22.1%
33.6%
44.3%
100.0%
141,470
189,067
233,629
564,166
18,698
582,863
7.0%
9.4%
11.6%
280%
200
515
715
47
762
280%
72.0%
1000%
204,293
1 041 871
1,246,164
91,598
1,337,762
16.4%
83.6%
1000%
48,729
259 445
308,174
21,716
329,890
15.8%
84.2%
100.0%
102
98.2%
1.8%
1000%
65.9%
34.1%
100.0%
524,179
51 567
575,746
467,708
1 061 765
1,529,473
829,896
2,935,115
91.0%
90%
100.0%
30.6%
69.4%
1000%
132,222
13 624
145,845
102,469
227,830
330,299
164,031
640,175
90.7%
9.3%
100.0%
31.0%
690%
100.0%
(pri)
Total
GS - Schedule 28
0-50 kW
51-100 kW
> 101kW
Sec Subtotal
Primary
(sec)
(sec)
(sec)
(pri)
Total
GS - Schedule 30
0-300 kW
301+ kW
Sec Subtotal
Primary
(sec)
{sec)
(pri)
Total
LPS - Schedule 48T
1-4MW
> 4MW
Sec Subtotal
1-4MW
> 4MW
Pri Subtotal
Trans
(sec)
(sec)
(pri)
(pri)
(trn)
Total
2
104
61
32
93
9
206
Irrigation - Schedule 41 (Average)
(sec)
3,920
1000%
238,210
100.0%
150,187
100.0%
Irrigation - Schedule 41 (Annual)
(sec)
8,046
100.0%
238,210
100.0%
150,187
1000%
Source:
Columns B & D - PacifiCorp, Pricing Department
Tab 17.2
(Gust Data 2)
Cust Data 3
PacifiCorp
Oregon Marginal Cost Study
Customer Class Split between
Three Phase I Single Phase
Customer
Class
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
(A)
(B)
(C)
(D)
(E)
Voltage
Level
Three
Phase
Total
Customers
Three Phase
%of
Customers
(A) I (B)
Single Phase
%of
Customers
100%- (C)
Res- Schedule 4
(sec)
GS - Schedule 23
0-15 kW
15+kW
(sec)
(sec)
Sec Subtotal
Primary
(pri)
Total
GS - Schedule 28
0-50 kW
51-100 kW
> 101kW
(sec)
(sec)
(sec)
Sec Subtotal
Primary
(pri)
Total
474,231
0.0000%
1000000%
11,812
5,820
17,633
44
17,677
66,169
10,605
76,774
44
76,818
17.8518%
54.8840%
82.1482%
45.1160%
100.0000%
23.0118%
0.0000%
76.9882%
3,149
3,024
1,887
8,061
57
8,117
4,487
3,453
1,924
9,865
57
9,922
70.1895%
87.5598%
98.0750%
29.8105%
12.4402%
1.9250%
100.0000%
81.8146%
0.0000%
18.1854%
214
553
767
51
818
215
553
768
51
818
99.6125%
100.0000%
0.3875%
0.0000%
100.0000%
99.8982%
0.0000%
0.1018%
107
64
2
33
6
212
107
64
2
33
212
100.0000%
100.0000%
100.0000%
100.0000%
100.0000%
100.0000%
0.0000%
0.0000%
0.0000%
0.0000%
0.0000%
0.0000%
6,160
7,211
85.4313%
14.5687%
32,984
569,212
5.7948%
94.2052%
GS - Schedule 30
0-300 kW
301+ kW
Sec Subtotal
Primary
Total
LPS - Schedule 48T
1-4MW
1-4MW
> 4MW
> 4MW
Trans
Total
(sec)
(pri)
(sec)
(pri)
(trn)
Irrigation - Schedule 41 (Annual)
(sec)
TOTAL
Tab: 17.3
6
(Cust Data 3)
Cust Data 4
PacifiCorp
Oregon Marginal Cost Study
Customer Loads
12 Months Ended December 2014
(A)
(B)
(C)
(D)
(E)
MW@Sales
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Description
Res - Schedule 4
Del.
Volt
(sec)
System
849
Distribution
976
Transformer
3,327
GS - Schedule 23
0-15 kW
15+ kW
Primary
(sec)
(sec)
(pri)
91
79
0
89
72
0
184
127
2
GS - Schedule 28
0-50 kW
51-100 kW
> 101kW
(sec)
(sec)
(sec)
73
101
133
78
109
140
141
189
234
(pri)
3
3
19
GS - Schedule 30
0-300 kW
301+ kW
Primary
(sec)
(sec)
(pri)
28
153
14
30
165
15
49
259
22
LPS - Schedule 48T
1-4 MW
1-4 MW
> 4MW
> 4MW
Trans
(sec)
(pri)
(sec)
(pri)
(trn)
78
65
7
151
94
84
69
6
150
0
132
102
14
228
164
Irrigation - Sch 41
(sec)
26
27
150
Primary
Source:
Columns C, D & F - PacifiCorp, Load Research Dept.
Column E - Column F x Column H
Column H - PacifiCorp Distribution Construction Standard, DA 411
Tab: 17.4
(Cust Data 4)
CustData 5
PacifiCorp
Oregon Marginal Cost Study
Allocation of Uncollectible Expense between Members of Class
12 Months Ended December 2014
(A)
Line
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
Del.
Volt
Description
Res - Schedule 4
(C)
Revenues
December 2014
Industrial
Commercial
(B)
(sec)
(E)
Percent of
Total Revenues
Commercial
Industrial
(D)
0.00%
0.00%
(F)
(G)
(H)
Allocated Net Uncollectible
Commercial
Industrial
Total
5,322,978
GS - Schedule 23
(sec)
(pri)
111,580,331
87,942
$111,668,273
2,282,796
22,422
$2,305,218
25.39%
0.02%
25.41%
1.61%
0.02%
1.63%
145,265
114
145,380
552
5
557
145,817
120
145,937
(sec)
(pri)
160,691 ,885
1,108,427
$161,800,312
8,297,935
443,089
$8,741,024
36.56%
0.25%
36.81%
5.86%
0.31%
6.17%
209,203
1,443
210,646
2,007
107
2,114
211,210
1,550
212,760
(sec)
(pri)
7S,702,779
5,748,192
$84,450,971
15,724,276
1,076,582
$16,800,858
17.91%
1.31%
19.22%
11.10%
0.76%
11.87%
102,462
7,484
109,946
3,803
260
4,063
106,265
7,744
114,009
(sec)
(pri)
(trn)
25,582,615
29,532,712
26,468,477
$81,583,804
17,278,450
73,545,828
22,928,332
$113,752,610
5.82%
6.72%
6.02%
18.56%
12.20%
51.94%
16.19%
80.33%
33,306
38,448
34,459
106,213
4,178
17,786
5,545
27,509
37,484
56,234
40,004
133,722
$25,360,982
$25,360,982
0.00%
0.00%
100.00%
100.00%
7,103
7,103
7,103
7,103
41,346
5,936,510
Total
GS - Schedule 28
Total
GS - Schedule 30
Total
LPS - Schedule 48T
Total
Irrigation - Schedule 41
Total
(sec)
$439,503,360
$166,960,692
Tab: 17.5
572,186
(Gust Data 5)