♦ Issues in Cost Allocation
♦ Introduction to Efficient
Pricing
♦ Rate Design by Objective
Presented To:
EEI Advanced Rates School
University of Wisconsin, Madison
Presented By:
Philip Q Hanser
Principal, The Brattle Group
July 25, 2011
Copyright © 2010 The Brattle Group, Inc.
www.brattle.com
Antitrust/Competition Commercial Damages Environmental Litigation and Regulation Forensic Economics Intellectual Property International Arbitration
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Issues in
Cost
Allocation
2
Basic Steps in Rate Making Process
Components of
Cost of Service Study
Determination of
Revenue Requirements/
Overall Cost of Service
Functionalize Costs
Classify Cost
Assign costs to
Customer/Rate Classes
Within a Jurisdiction
Jurisdictional
Separations
Allocation of
Revenue Requirements
Across the Jurisdictions
in which the
Company Operates
Design Cost-Based
Rate Elements for Each
Rate Classes’ Tariff
Source: Blank & Gegax
3
Cost of Service Study
♦ An analytical approach to the apportionment of the total
cost of service (Revenue Requirement)
♦ Supports the process of determining and allocating the
cost of providing utility service to each customer rate class
and provides a framework for recovering costs through
proper rate design
♦ The costs of the utility must be studied by the cost analyst
using inputs from various areas of utility operations (e.g.,
accounting records, engineering analyses, customer billing
records, demand forecasts, cost simulation models)
4
Types of Cost of Service Studies
♦ The vast majority of jurisdictions use Embedded (i.e.,
based on actual book data and actual class load
characteristics) COS for cost allocation
♦ Marginal COS is used for the development of time-of-use
pricing and, in a small minority of jurisdictions, for actual
cost allocation
♦ Not an exact science – reasonable people can disagree
5
Steps in an Embedded Cost of Service Study
Step 1: Functionalize
Step 2: Classify
Key Question to be asked at every step in the process:
♦ What caused the costs to be incurred?
(cost causation)
6
Functionalize and
Classify
Customer
Demand-Customer
1-phase secondary distribution lateral lines (7-13 kV)
Drop lines to homes
120-240 volts
3-phase primary distribution feeder lines (21 – 36 kV)
distribution substations (step-down transformers)
Sub-Transmission 69-115 kV lines
Demand
transmission subs
(step-down transformers)
‘Bulk’ Transmission lines
138-345 kV
(ultra-high voltage lines
go up to 500 – 765 kV)
Facilities not
used by
all customers;
Sized based
on subset of
system demands
-- NCP
Demand-Energy
Network
switchyard
step-up transformers
Generation (6-14 kV)
7
Common Facilities (used by all customers);
sized based on system demands -CP, Average Demand, Average-Excess
Demand
Step 1: Functionalization
♦ Functionalization is the process of dividing the total
revenue requirement into functional components as
related to the operations of the utility (operating
functions)





Generation (aka Production)
Transmission
Distribution
Meters and Services
General Plant (eventually must be apportioned to the other nongeneral functions)
♦ Usually, the rate-base component of revenue requirements
is functionalized first; then the expense components are
functionalized
8
Step 1: Functionalization
Functionalize Rate Base



Directly assign, where possible (good examples are the original cost
and accumulated depreciated – facility by facility – for non-general
plant in service)
General Plant is problematic – is re-functionalized into other nongeneral-plant components (with use of functionalization factors –
usually some direct labor proportion of O&M)
 The argument is that general plant supports indirect labor and
that indirect labor supports direct labor
Once rate base is functionalized (with general plant re-functionalized
into the non-general plant categories), it is easier to functionalize
return dollars on rate base as well as income taxes
9
Step 1: Functionalization
♦ Direct Labor (“Field Crew”)

Employees or workers who are directly involved in the production of goods
or services.
 Direct labor costs are directly assignable to a specific product, cost
center, work order, or provision of service.
 Direct labor usually keeps track of their time in work orders or time
logs
 For a utility, direct labor can be directly assigned to an operating
function and direct labor costs are part of O&M
♦ Indirect Labor (“Office Workers”)

Support labor that cannot be directly assigned to a specific product, cost
center, work order or provision of service
 Indirect labor usually does not keep track of their time in work orders
or time logs
 For a utility, indirect labor cannot be directly assigned to an operating
function and indirect labor costs are part of A&G
10
Step 1: Functionalization
Functionalize Revenue Requirements
 Functionalize
return dollars on rate base, as well as
income taxes, based on how rate base was functionalized

For example, if 50% of rate base is generation related, then 50%
of return dollars on rate base is generation related
 Directly
assign, where possible (good examples are direct
O&M expenses, annual depreciation expense, fuel)
 A&G is problematic – is re-functionalized into other nonA&G components (with use of functionalization factors;
e.g., direct labor proportion of O&M)

For example, if 10% of direct labor (in O&M) is transmission
related, then 10% of indirect labor (in A&G) is transmission
related
11
Electric Functionalization Example ($000)
Efficient Energy Inc.
Cost of Service/Revenue Requirements - ($000s)
TOTAL
Generation Transmission Distribution
General
Operation & Maintenance Expense
Generation
Transmission
Distribution
Customer Accounts
Customer Service & Informational
Sales
Administrative & General
Total Operation & Maintenance
576,369
15,464
47,733
37,769
12,510
1,846
123,337
815,027
576,369
0
0
0
0
0
0
576,369
0
15,464
0
0
0
0
0
15,464
0
0
47,733
37,769
12,510
1,846
0
99,857
0
0
0
0
0
0
123,337
123,337
Depreciation Expense
Intangible
Generation
Transmission
Distribution
General
Total Depreciation Expense
5,812
131,353
9,125
44,591
21,667
212,548
0
131,353
0
0
0
131,353
0
0
9,125
0
0
9,125
0
0
0
44,591
0
44,591
5,812
0
0
0
21,667
27,478
Taxes
Taxes Other Than Income
Income Taxes
150,640
120,437
84,485
65,400
9,804
8,373
37,514
30,663
18,837
16,001
Return
Debt Related
Equity Related
Total Return
124,389
180,667
305,056
67,546
98,107
165,652
8,647
12,560
21,207
31,669
45,997
77,666
16,526
24,004
40,530
1,603,708
1,023,260
63,973
290,291
226,184
9.54%
9.54%
9.54%
9.54%
9.54%
3,197,650
1,736,399
222,296
814,112
424,843
Total Cost of Service
Rate of Return
Rate Base
12
Step 2: Classification
♦ Classification is the process of further separating the
functionalized costs by the primary driver for that cost

In other words, this is the process of separating the functionalized
costs into classifications based on what the costs are sensitive to
♦ Primary Cost Classification Categories



Demand-Related Costs: (aka Capacity-Related Costs) Those costs
that vary with the kW of instantaneous demand (and therefore
peak capacity needs)
Energy-Related Costs: Those costs that vary with kWh of energy
generated
Customer-Related Costs: Those costs that vary with the number
of customers on the system
13
Step
2: Classification
Classificatin
Step 2:
Examples of Demand-Related Costs

Costs of Generation Capacity

Costs of Transmission Lines

Costs of Distribution Lines and Transformers
 These costs show up in Rate Base
 The resulting costs that show up in Revenue Requirements
• Return dollars on rate base
• Annual depreciation expense
• Operations and Maintenance
14
Step 2: Classification
Examples of Customer-Related Costs
♦ Costs of Metering


Return dollars and depreciation expense on meters themselves
Labor costs involved in reading the meters
♦ Costs of billing and account processing


Return dollars and depreciation expense on needed information
equipment and software as well as customer service buildings
Labor costs associated with billing, account processing and
fielding customer complaints
♦ Costs of attaching customers to the system

Costs associated service drops and poles as well as some lowvoltage distribution facilities
15
Step
2: Classification
Step 2: Classification
Examples of Energy-Related Costs
♦ Fuel
♦ Costs of energy purchases
♦ Generation variable O&M (e.g., lubricants)
NOTE: With respect to the production of energy (kWh), both DemandRelated and Customer-Related costs are viewed as “Fixed Costs” while
Energy-Related costs are viewed as “variable costs.”
NOTE: During the functionalization step, the reason general plant in
rate base is re-functionalized into the non-general plant components is
because general plant does not directly lend itself to being classified as
either a demand- , energy- or customer-related cost
16
Step 2: Classification
Electric Classification Example - ($000s)
Generation
Demand
Related
Energy
Related
Transmission
Distribution
Demand
Related
Demand Customer
Related Related
TOTAL
REVENUE REQUIREMENTS
OPERATIONS & MAINTENANCE
Generation
254,500
8,497
Transmission
15,464
Distribution Substations,
Lines and Transformers
47,733
Meters and Services
Administrative & General
O&M SUBTOTAL
52,124
20,474
25,894
274,974
34,391
FUEL
NET OPERATING INCOME & TAXES
& ANNUAL DEPRECIATION
TOTAL
8,499
68,470
23,963 116,203
123,337
52,124
313,372
291,583
13,083
566,557 360,845
17
501,655
313,372
31,597
147,363
55,560 263,566
483,625
52,124
1,298,652
Basic Steps in Rate Making Process
Components of
Cost of Service Study
Determination of
Revenue Requirements/
Overall Cost of Service
Functionalize Costs
Classify Cost
Assign costs to
Customer/Rate Classes
Within a Jurisdiction
Jurisdictional
Separations
Allocation of
Revenue Requirements
Across the Jurisdictions
in which the
Company Operates
Design Cost-Based
Rate Elements for Each
Rate Classes’ Tariff
Source: Blank & Gegax
18
Allocation: Class Cost of Service Study
Allocation is the process of assigning the functionalized and
classified revenue requirements (cost of service) to the
different jurisdictions and the different customer rate
classes within a jurisdiction.
♦ A rate class is a relatively homogeneous group of customers that
possess similar characteristics and who face the same set of prices
(e.g., residential, small power, irrigation, industrial power)
♦ Characteristics include: energy consumed; load characteristics and
end use; delivery voltage; metering characteristics;
other
conditions of service
In order to conduct a class cost-of-service study, the
demand characteristics of the total system, as well as
individual rate classes, must be analyzed.
♦ Such analysis is referred to as “load research”
19
Load Curve
Load Curve describes the pattern of instantaneous demand
through a particular period of time (i.e., through a cycle)
♦ A daily cycle (for a daily load curve) is 24 hours
♦ An average monthly cycle (for a monthly load curve) is 730 hours
♦ An annual cycle (for an annual load curve) is 8,760 hours (or 8784)
20
Information From Load Curves
Average Load is derived by taking the total kWh of energy
used through the cycle and dividing by the total number of
hours through the cycle.
♦ For example, if a customer consumes 7,300 kWh during a month,
then that customer’s average load (instantaneous demand) is 10 kW
♦ Average load is analogous to average speed on a trip
21
Information From Load Curves
Peak Load is the maximum instantaneous demand (load)
during the cycle (measured in kW or MW)
♦ Non-Coincident Peak Load (NCP) is a customer’s (or customer
classes’) maximum demand irrespective of when it happens
♦ Coincident Peak Load (CP) is a customer’s (or customer classes)
demand at the moment in time that the total system is
experiencing its peak load
22
Peak Day
4,500
Residential
SGS
4,000
LGS
MGS
3,500
Total System
Total
System
Daily Peak
Load (MW)
3,000
2,500
2,000
1,500
1,000
500
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hours
23
Alternative CP Measures
1-CP
♦ Uses the “system peak” as being the highest single hour’s system
demand during the entire year. Each class’s CP is that class’s
demand during that hour the system peak occurred
4-CP
♦ Determines the highest single hour’s system demand during each of
the individual 12 months and then uses the “system peak” as being
an average of the four highest of these 12 system demands (the
four demands are from four different months’ hours). Each class’s
CP is that class’s average demand over those four particular hours
12-CP
♦ Determines the highest single hour’s system demands for each of
the individual 12 months and then takes the “system peak” as being
an average of all these 12 system demands (the 12 demands are
from 12 different months’ hours). Each class’s CP is that class’s
average demand over those 12 24particular hours
Information From Load Curves
Load Factor (LF) is a measure that captures the degree of
variation in a particular pattern of demand
♦ LF is a number between zero and one (i.e., a percentage)


The closer load factor is to 1, the less the variation in the pattern of
demand
The closer load factor is to 0, the more the variation in the pattern of
demand
♦ LF = (average load) / (peak load)


For example, suppose that a customer uses 7,300 kWh during a month
(average load = 10 kW) and that the customer’s NCP during the month
is 25 kW.
LF = (average load)/(peak load) = 10/25 = 0.4 (40%)
25
System Load Factor
♦ High system load factor translates into high utilization of
the capacity built into the system.
♦ High system load factor translates into lower average cost
per kWh.
♦ High system load factor is a result of:


High load factor individual customers or customer class
Customer or Rate Class Diversity
26
Allocation


Allocation is the process of assigning costs to the
different jurisdictions and the different customer rate
classes.
Once the various customer class categories have been
designated, particular functionalized and classified costs
are allocated among the rate classes based on an
allocation method which is deemed the most consistent
with cost causation


Different
methods
cost
components
require
different
allocation
A particular allocation method (i.e., allocation factor) is a
set of percentages that sum to 100%



Demand-Related Allocation Methods
Energy-Related Allocation Methods
Customer-Related Allocation27 Methods
Allocation
How should the rent of a two-bedroom house shared by a
married couple and a single person be allocated?
♦ What drives rent costs? (i.e., what are the cost drivers?)
 Married couple argues it’s the number of bedrooms
 Single person argues it’s the total size of the house and yard required
to accommodate three household members
♦ Cost drivers help in choice of appropriate allocation methods
 Married couple says use “relative number of bedrooms” method (50% of
rent goes to married couple and 50% of rent goes to single person)
 Single person says use “relative number of people” method (67% of rent
goes to married couple and 33% of rent goes to single person)
28
Allocation
♦ After the Functionalization step is completed, some costs can be
identified as logically incurred to serve only a particular customer
(costs of “Dedicated Facilities”)

Cost-causation would dictate that these costs are only allocated to that
particular customer
♦ After the Functionalization step is completed, some costs can be
identified as not being incurred by particular customers



For example, distribution lines are not used to serve customers that
take power at higher voltages (e.g., off the distribution substations)
For example, distribution lines and sub-stations are not used to serve
customers that take power at even higher voltages (e.g., off the subtransmission)
Cost-causation dictates not to allocate the costs of these facilities to
the particular customers who do not use these facilities
29
Allocation of Revenue Requirement
A
particular group of demand-related costs are allocated
through the use of one of the demand allocators
♦ The choice of which demand allocator should be used with which
group of demand-related costs, should be based on cost causation
A
particular group of energy-related costs are allocated
through the use of one of the energy allocators
♦ The choice of which energy allocator should be used with which
group of energy-related costs, should be based on cost causation
A
particular group of customer-related costs are allocated
through the use of one of the customer allocators
♦ The choice of which customer allocator should be used with which
group of customer-related costs, should be based on cost causation
30
Allocation
Demand-Related Cost Allocation Methods
 System
Peak Responsibility (1CP, 4CP, 12CP) – 12CP
typically used for the allocation of transmission demandrelated costs
 Non-Coincident Demand (NCP) – typically used for the
allocation of distribution demand-related costs
 Average-Excess Demand (AED) – typically used for the
allocation of generation demand-related costs


This Method uses a weighted average of the Average-Demand
Allocators (weight = system load factor) and the ExcessDemand Allocators (weight = one minus the system load factor)
A Class’s “Excess Demand” is the difference between that
class’s NCP and that class’s Average Demand
31
Peak Day
4,500
Residential
SGS
4,000
LGS
MGS
3,500
Total System
Total
System
Daily Peak
Load (MW)
3,000
2,500
2,000
1,500
1,000
500
0
0
1
2
3
4
5
6
7
8
9
10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Hours
32
MWh
2,000
1,500
Excess
Demand
1,000
Average Demand
500
0
Hours
0
Winter/Spring
Spring
33
Summer
8760
Fall/Winter
Monthly Peak Loads by Class
3,500
Residential
SGS
LGS
MGS
Total System
3,000
2,500
MW
2,000
1,500
1,000
500
34
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0
Allocation
Energy-Related Cost Allocation Methods



kWh of Energy at the customers’ meters – after line and
transformer losses
kWh of Energy at the generation plants – before line and
transformer losses
Losses are:
■
■
■
■
■
Due to the transformation of kWh to heat
Inversely related to voltage (i.e., higher voltage means lower loss)
Directly related to the number of voltage transformations (i.e.,
more voltage transformations from the generator to the customer
means more loss)
Directly related to distance (i.e., the greater the length of a given
circuit, the greater the losses)
“Loss factors” will vary by rate class (low-voltage distribution
customers – like residential customers – have the highest loss
factors)
35
Allocation
Customer-Related Cost Allocation Methods
♦ Relative Number of Customers
♦ Relative Weighted Number of Customers -- where weights can be
based on:




class-average
class-average
class-average
class-average
meter costs
billing costs
service line costs
meter-reading costs
36
Allocation
 Generally,
the following criteria should be utilized to
determine the appropriateness of an allocation method:
♦ The
method should reflect the
characteristics of the utility’s system.
actual
planning
and
operating
♦ The method should reflect cost causation; i.e., should be based on the
actual activity that the drives a particular cost and on rate classes’ share of
that activity
♦ The method should recognize customer class characteristics such as electric
load demands, peak period consumption, number of customers, and
directly assignable costs.
♦ The method should produce stable results on a year-to-year basis.
♦ Customers who benefit from the use of the system should also bear some
responsibility for the costs of utilizing the system.
37
Allocation of Generation Demand-Related Costs
 AED
is commonly used for allocating generation demandrelated costs
♦ There are derivatives of AED – usually based on the “peak” measure
(CP, k-CP, NCP, k-NCP) used in calculating “excess” and based on
what MWh values are used for calculation of average demand (at
meter or at generation)
♦ AED is one of the oldest and most-widely used demand allocation
methods
♦ While AED is an appropriate method for allocating generation
demand, there are other demand allocators that could also be
argued to be appropriate (see NARUC “Electricity Cost Allocation
Manual”)


Could separate base-load generation demand-related costs and use an
average-demand allocator
Could separate peak-load generation demand-related costs and use an
CP- or excess-demand allocator
38
Allocation of Energy-Related Generation
 Energy-Related
generation cost allocation methods should
take into account the fact that different rate classes have
different contributions to line losses.
♦ Residential and small commercial customers contribute significantly more
to losses than do large high-voltage customers
 Energy-Related
generation cost allocation methods could
also take into account the fact that different rate classes
have different load factors and, therefore, may have
different
contributions
to
(expensive)
peak-load
generation energy costs.
♦ Residential and small commercial customers consume a greater share of
their kWh during peak times and, therefore, consume proportionately more
energy from peaker units
39
Allocation of Transmission Demand-Related Costs
 12-CP
is the allocation method the FERC uses for
transmission and, therefore for consistency, it is also used
by most states.
♦ Transmission-system loads are often significantly high (relative to
transmission capacity) even during low total-system load months
because remote base-load generation facilities are still being relied
upon (as they are during high total system load months)
♦ It is common for the monthly peak demand on a utility’s
transmission to be very similar across all months (basically, there is
at least one hour each month where transmission demand is “at
transmission capacity”) a 12-CP demand allocation method is
appropriate.
40
Allocation of Distribution Costs

NCP is the allocation method
distribution demand-related costs
typically
used
for
♦ Investment in distribution facilities is generally made to serve class
maximum demands that are not coincident with the system peak,
and therefore the NCP allocation methodology provides reasonable
results.
♦ This method is consistent with a generally accepted approach to
distribution demand allocation.

Methods that allocate customer-related costs associated
with metering and customer service should take into
account that average meter or service costs (per
customer) varies across rate classes
♦ Use a weighted customer method, or directly assign these costs to
rate classes wherever and whenever possible
41
EFFICIENT ENERGY INC.
ALLOCATION FACTORS
(1)
(2)
(3)
(4)
COINCIDENT PEAK
Line No.
RATE CLASS
1 CP
4 CP
12 CP
kW
kW
kW
(1)
(2)
(3)
(4)
(5)
(6)
ALLOCATION UNITS
RESIDENTIAL
SGS
MGS - Sec
MGS - Pri
LGS
TOTAL
(7)
(8)
(9)
(10)
(11)
(12)
ALLOCATION FACTORS
RESIDENTIAL
SGS
MGS - Sec
MGS - Pri
LGS
TOTAL
(13)
(14)
(15)
(16)
(17)
(18)
ENERGY AT
ENERGY AT
LOSS FACTORSGENERATION
METER
mWhrs
mWhrs
ALLOCATION UNITS
RESIDENTIAL
7,011,202
1.120
7,852,546
SGS
2,009,265
2,210,192
MGS - Sec
1,826,497
1,990,882
MGS - Pri
2,739,745
1.076
2,876,732
LGS
3,652,962
1.032
3,762,551
TOTAL
17,239,671
18,692,903
(19)
(20)
(21)
(22)
(23)
ALLOCATION FACTORS
RESIDENTIAL
SGS
MGS - Sec
MGS - Pri
LGS
(24)
TOTAL
2,043,367
503,942
398,784
496,530
555,014
3,997,637
0.5111
0.1261
0.0998
0.1242
0.1388
1.0000
1,708,526
487,445
386,273
481,846
519,611
3,583,700
0.4767
0.1360
0.1078
0.1345
0.1450
1.0000
(5)
(6)
DEMAND ALLOCATION UNITS
CLASS NCP
w/INDUS.
CLASS
@50%
NCP
kW
kW
1,381,058
347,444
296,477
404,567
533,954
2,963,501
2,133,650
568,985
443,015
539,695
625,926
4,311,272
0.4660
0.1172
0.1000
0.1365
0.1802
1.0000
0.4949
0.1320
0.1028
0.1252
0.1452
1.0000
2,133,650
568,985
443,015
539,695
312,963
3,998,309
0.5336
0.1423
0.1108
0.1350
0.0783
1.0000
NUMBER OF
CUSTOMERS
(8)
AVERAGE AVERAGE AND
DEMAND
EXCESS
kW
800,366
229,368
208,504
312,756
417,005
1,967,999
0.4067
0.1165
0.1059
0.1589
0.2119
1.0000
1,681,459
419,510
314,699
358,991
378,206
3,152,865
0.5333
0.1331
0.0998
0.1139
0.1200
1.0000
Cost of new Met WEIGHTED
and Service NUMBER OF
per Customer CUSTOMERS
(Current $)
(6) x(7)
716,433
83,177
6,820
454
44
806,928
135.0
157.5
180.0
202.5
4,725.0
716,433
97,026
9,094
681
1,540
824,774
1.0
1.2
1.3
1.5
35.0
0.8686
0.1176
0.0110
0.0008
0.0019
0.4067
0.1165
0.1059
0.1589
0.2119
0.4201
0.1182
0.1065
0.1539
0.2013
0.8879
0.1031
0.0085
0.0006
0.0001
1.0000
1.0000
1.0000
42
(7)
1.0000
EFFICIENT ENERGY INC.
ALLOCATION FACTORS - AVERAGE AND EXCESS
(1)
Line
No.
(1)
(2)
(3)
(4)
(5)
(6)
RATE CLASS
RESIDENTIAL
SGS
MGS - SEC
MGS - PRI
LGS
TOTAL
(2)
(3)
(4)
(5)
(6)
CLASS NCP
Average Demand
Excess Demand
Average Demand
Component of Allocation
Factor
Excess Demand
Component of Allocation
Factor
kW
kW
kW
kW
kW
(2) - (3)
Ratio of Col. (3)
Ratio of Col. (4)
2,133,650
568,985
443,015
539,695
625,926
4,311,272
Total 1 CP kW:
Load Factor:
896,409
252,305
227,270
328,394
429,515
2,133,893
1,237,240
316,680
215,746
211,301
196,411
2,177,379
4,161,248
51.28%
0.4201
0.1182
0.1065
0.1539
0.2013
1.0000
0.5682
0.1454
0.0991
0.0970
0.0902
1.0000
WEIGHTING FACTORS
Average Demand
Excess Demand
System Load Factor
0.4923
(7)
(8)
(9)
(10)
(11)
(12)
(13)
Average Demand
Component of Allocation
Factor
Excess Demand
Component of Allocation
Factor
Alloc Factor times
System LF
Alloc Factor times (1sys LF)
0.2068
0.0582
0.0524
0.0758
0.0991
0.4923
43
(1- System LF)
0.5077
0.2885
0.0738
0.0503
0.0493
0.0458
0.5077
AVERAGE AND
EXCESS Allocation
Factor
0.4953
0.1320
0.1027
0.1250
0.1449
1.0000
EFFICIENT ENERGY INC.
ALLOCATION OF REVENUE & REVENUE REQUIREMENT (000's)
(1)
(2)
(3)
(4)
GENERATION
Line
No.
PARTICULARS
TOTAL
Demand
Energy
(1)
(2)
(3)
REVENUE REQUIREMENT
COST EXCLUDING FUEL
COST OF FUEL
TOTAL
$
$
$
1,281,837 $
321,869 $
1,603,706 $
(4)
RATE BASE
$
3,197,601
(5)
(6)
(7)
(8)
(9)
(10)
ALLOCATION FACTORS
RESIDENTIAL
SGS
MGS - SEC
MGS - PRI
LGS
TOTAL
(11)
(12)
(13)
(14)
(15)
(16)
ALLOCATED REVENUE REQUIREMENT
RESIDENTIAL
SGS
MGS - SEC
MGS - PRI
LGS
TOTAL
$
$
$
$
$
$
831,983
203,372
151,427
192,549
224,374
1,603,706
$
$
$
$
$
$
398,290
106,187
82,616
100,543
116,511
804,147
$
$
$
$
$
$
(17)
(18)
(19)
(20)
(21)
(22)
ALLOCATED RATE BASE
RESIDENTIAL
SGS
MGS - SEC
MGS - PRI
LGS
TOTAL
$
$
$
$
$
$
1,713,590
414,949
300,973
366,426
401,663
3,197,601
$
$
$
$
$
$
1,010,421
269,384
209,589
255,068
295,576
2,040,037
$
$
$
$
$
$
$
804,147 $
$
804,147 $
2,040,037
$
AED
0.4201
0.1182
0.1065
0.1539
0.2013
1.0000
50,900
321,869
372,769
-
156,593
44,075
39,702
57,367
75,032
372,769
-
44
(6)
(7)
TRANSMISSION
DIST. SUBS
Demand
Demand
(8)
DISTRIBUTION
PRIMARY / LINE TRANS. /
SECONDARY
Demand
75,340
75,340
$
$
$
68,964
68,964
$
$
$
115,569 $
$
115,569 $
$
239,127
$
237,436
$
361,370
12 CP
NCP
0.4660
0.1172
0.1000
0.1365
0.1802
1.0000
0.4949
0.1320
0.1028
0.1252
0.1452
1.0000
(9)
METER & SERV.
Customer
$
$
$
mWhs w/loss
0.4201
0.1182
0.1065
0.1539
0.2013
1.0000
0.4953
0.1320
0.1027
0.1250
0.1449
1.0000
(5)
$
NCP w/Inds.@50%
0.5336
0.1423
0.1108
0.1350
0.0783
1.0000
Customer
62,229
62,229
$
$
$
104,689
104,689
194,584
$
125,046
Customers
0.8879
0.1031
0.0085
0.0006
0.0001
1.0000
Weighted Cust
0.8686
0.1176
0.0110
0.0008
0.0019
1.0000
$
$
$
$
$
$
35,110
8,833
7,537
10,285
13,574
75,340
$
$
$
$
$
$
34,130
9,102
7,087
8,633
10,012
68,964
$
$
$
$
$
$
61,672
16,446
12,805
15,600
9,046
115,569
$
$
$
$
$
$
55,250
6,415
526
35
3
62,229
$
$
$
$
$
$
90,937
12,316
1,154
86
195
104,689
$
$
$
$
$
$
111,439
28,036
23,923
32,645
43,085
239,127
$
$
$
$
$
$
117,507
31,336
24,398
29,723
34,472
237,436
$
$
$
$
$
$
192,841
51,425
40,040
48,778
28,286
361,370
$
$
$
$
$
$
172,762
20,057
1,645
109
11
194,584
$
$
$
$
$
$
108,620
14,710
1,379
103
233
125,046
In general, Class A’s Average-Excess Demand Allocation Factor is:
AED
= [(Average Demand Allocation Factor)A (system-load-factor)
+ (Excess Demand Allocation Factor)A (1 – system -load-factor)]
Consider the previous slide example.
Residential Class AED Allocation Factor is:
AED= [(42.01%) (49.23%) + (56.82%) (1 – 49.23%)]
= [(42.01%) (49.23%) + (56.82%) (50.77%)]
= 20.68% + 28.85% = 49.53%
Note that the closer the system load factor is to one (which would mean a larger
share of generation units should be of the base-load technology type), the closer
AED is to the average demand allocator (average demand drives the need for baseload generation)
Note that the closer the system load factor is to zero (which would mean a larger
share of generation units should be of the peak-load technology type), the closer
AED is to the excess demand allocator (excess demand drives the need for peakload generation)
45
Basic Steps in Ratemaking Process
Components of
Cost of Service Study
Determination of
Revenue Requirements/
Overall Cost of Service
Functionalize Costs
Classify Cost
Assign costs to
Customer/Rate Classes
Within a Jurisdiction
Jurisdictional
Separations
Allocation of
Revenue Requirements
Across the Jurisdictions
in which the
Company Operates
Design Cost-Based
Rate Elements for Each
Rate Classes’ Tariff
Source: Blank & Gegax
46
Rate Design
A
tariff is a document, approved by the responsible
regulatory agency, listing the terms and conditions
under which utility services will be provided to
customers within a particular class. Tariff sheets
typically include:
♦ a schedule of all the rate elements (individual prices) plus the
provisions necessary for billing
♦ the service characteristics (e.g., voltage, single or three phase)
and metering methods
♦ rules and regulations, i.e., a statement of the general practices
the utility follows in carrying out its business with its customers
47
Rate Design
Billing Determinants
♦ Any element of the customer’s account that will be used in the
computation of a customer’s bill. These include the applicable
rates and riders and the components of consumption, such as
energy, peak demand, power factor, etc.
Base Rates
♦ Base Rates are rates that are fixed in the tariffs (until the next
rate case comes along)
48
Rate Design
Riders
♦ A
rider is a mechanism that follows or "tracks" some
unpredictable costs that a utility incurs in providing service to
consumers and allows the prices customers pay in order to
recover these unpredictable costs to vary (without the need for a
new rate case)
♦ The rider is an additional charge for each kilowatt-hour and is
increased or decreased based on variable costs such as fuel and
market power. The rider is adjusted monthly or quarterly.
♦ A Fuel and Purchased Power Adjustment Clause is an example of
a rider
♦ Other costs may be tracked
49
Rate Design
Role of Rates
♦ Rates serve as the means by which the utility collects revenues
and covers its allowed cost of service (including that which is
required under the “fair-return standard”)
♦ Rates induce particular behaviors on the part of customers

Principles of Public Utility Rates by James C. Bonbright

Rate attributes: simplicity, understandability, public acceptability, and
feasibility of application and interpretation

Effectiveness of yielding total revenue requirements

Revenue (and cash flow) stability from year to year

Stability of rates themselves, minimal unexpected changes that are
seriously adverse to existing customers

Fairness in apportioning cost of service among different consumers

Avoidance of “undue discrimination”

Efficiency, promoting efficient use of energy and competing products
and services
50
Fundamental Rate Elements
 Demand
Charge
♦ Measured in dollars per kW of monthly metered customer billing demand
 Energy
Charge
♦ Measured in dollars per kWh of monthly customer energy use
 Customer
Charge
♦ Measured in dollars per customer per month
51
Fundamental Rate Elements: Energy and Customer
Charges
 Energy
charges are derived by taking the class energyrelated costs and dividing these costs by class energy
use
 Customer Charges are derived by taking the class
customer-related costs and dividing by the class
“customer months”
♦ A class’s customer-months is calculated by multiplying the total
number of customers in the class by 12
52
Fundamental Rate Elements: Demand Charges
 Demand
Charge
♦ Derived by taking the demand-related costs and dividing these
costs by class “billing demand”
♦ The manner in which the demand charge is calculated must be
consistent with the manner in which individual customers are
metered; otherwise, the utility will over- or under-collect.
♦ For a class in which individual customers do not have demand
meters, demand-related costs must be recovered either through
the energy charge or the customer charge

Note: Use of the energy charge to recovery of fixed demand- and
customer-related costs can increase risk of fixed-cost recovery
53
Fundamental Rate Elements: Demand Charges
EFFICIENT ENERGY INC.
PHYSICAL UNITS
(1)
(2)
(3)
BILLING UNITS
Demand
kW
(1) RESIDENTIAL
Energy
MWh
Customers
No. Bills
20,574,480
7,011,202
716,433
(2) SGS
5,586,401
2,009,265
83,177
(3) MGS - SEC
4,389,507
1,826,497
6,820
(4) MGS - PRI
5,551,152
2,739,745
454
(5) LGS
6,563,111
3,652,962
44
42,664,652
17,239,671
806,928
(6) TOTAL
Here, energy units are the figures measured “at the meter.”
54
EFFICIENT ENERGY INC.
RESIDENTIAL CLASS CHARACTERISTICS
PHYSICAL CHARACTERISTICS
(1)
Total Energy Use
(MWh)
(2)
Total Customers
(3)
Total Customer-Months
(4)
Avg. Monthly Use
(kWh/customer)
7,011,202
716,433
8,597,196
816
REVENUE REQUIREMENTS ($000s)
(5)
Demand-Related Costs
529,202
(6)
Energy-Related Costs
156,593
(7)
Customer-Related Costs
146,187
(8)
Total Revenue
Requirements
831,983
55
EFFICIENT ENERGY INC.
Residential Pricing Strategy I
Collect all energy-related costs through a per kWh charge
Collect all other costs through a fixed monthly customer charge
CALCULATION OF ENERGY CHARGE
(1) Energy-Related Costs (000s $)
(2)
Divide by MWh (000s of kWh)
(3) Energy Charge ($/kWh)
156,593
7,011,202
0.0223
Energy Charge
(4) (¢/kWh)
2.23
CALCULATION OF CUSTOMER CHARGE
(5) Demand-Related Costs ($000s)
529,202
(6)
146,187
Add Customer-Related Costs ($000s)
(7) Remaining Revenue Requirements ($000s)
(8) Remaining Revenue Requirements ($)
(9)
Divide by Customer Months
Monthly Customer Charge
(10) ($/customer/mo.)
675,390
675,389,775
8,597,196
78.56
56
EFFICIENT ENERGY INC.
Residential Pricing Strategy II
Collect all energy-related & demand-related costs through a per kWh charge
Collect only customer-related costs through a fixed month customer charge
CALCULATION OF ENERGY CHARGE
(1) Energy-Related Costs (000s $)
156,593
(2)
529,202
Add Demand-Related Costs (000s $)
(3) Costs to be Recovered
(4)
685,796
Divide by MWh (000s kWh)
7,011,202
(5) Energy Charge ($/kWh)
0.0978
Energy Charge
(6) (¢/kWh)
9.78
CALCULATION OF CUSTOMER CHARGE
(7) Customer-Related Costs ($000s)
146,187
(8) Customer-Related Costs ($)
(9)
146,187,407
Divide by Customer-Months
8,597,196
Monthly Customer Charge
(10) ($/customer/mo.)
17.00
57
EFFICIENT ENERGY INC.
Residential Pricing Strategy III
Collect all energy-related & demand-related costs & half of customer-related costs through a per kWh charge
Collect only half of customer-related costs through a fixed month customer charge
Calculation of Energy Charge
(1) Energy-Related Costs (000s $)
156,593
(2)
Add Demand-Related Costs (000s $)
529,202
(3)
Add Half of Customer-Related Costs (000s $)
(4) Costs to be Recovered
(5)
73,094
758,890
Divided by MWh (000s kWh)
7,011,202
(6) Energy Charge ($/kWh)
0.1082
(7) Energy Charge (¢/kWh)
10.82
Calculation of Customer Charge
(8) Half of Customer-Related Costs (000s $)
73,094
(9) Half of Customer-Related Costs ($)
(10)
(11)
73,093,703
Divide by Customer-Months
8,597,196
Monthly Customer Charge
($/customer/month)
8.50
58
EFFICIENT ENERGY INC.
Residential Bill Impacts
Strategy I
Energy charge =
Customer charge =
0.0223
($/kWh)
78.56
($/month)
Below-Average User(600 kWh/month)
Energy
Fixed
Component Component Total Bill
$ 13.40 $ 78.56 $ 91.96
Average User (913 kWh/month)
$
20.39
$
78.56 $ 98.95
Above-Average User (1500 kWh/month)
$
33.50
$
78.56 $ 112.06
Strategy II
Energy charge =
Customer charge =
0.0978
($/kWh)
17.00
($/month)
Below-Average User (600 KWh/month)
Energy
Fixed
Component Component Total Bill
$ 58.69 $ 17.00 $ 75.69
Average User (913 KWh/month)
$
89.30
$
17.00 $ 106.31
Above-Average User (1500 KWh/month)
$
146.72
$
17.00 $ 163.73
Strategy III
Energy charge =
Customer charge =
0.1082
($/kWh)
8.50
($/month)
Below-Average User (600 kWh/month)
Energy
Fixed
Component Component Total Bill
$ 64.94 $
8.50 $ 73.45
Average User (913 kWh/month)
$
98.82
$
8.50 $ 107.32
Above-Average User (1500 kWh/month)
$
162.36
$
8.50 $ 170.86
59
Simple Two-Part Tariff
Total Bill = (customer charge) + (energy charge)*(kWh consumed)
Y = a + b*X
Strategy III
(small a, large b)
Strategy II
$
(Y)
Strategy I
(large a, small b)
$78.56
$17.00
$8.50
Average Use = 913
60
kWh/month
(X)
EFFICIENT ENERGY INC.
SGS CLASS CHARACTERISTICS
PHYSICAL CHARACTERISTICS
(1)
Total Energy Use
(MWh)
2,009,265
(2) Total Customers
83,177
(3) Total Customer-Months
998,124
Avg. Monthly
(4) kWh/Customer
2,013
(5) Class NCP (MW)
517
(6) Billing Demand (MW)
5,586
Average Monthly
MW/Customer
0.0056
Average Monthly
(8) kW/Customer
5.60
(7)
REVENUE REQUIREMENTS ($000s)
(9) Demand-Related Costs
$140,567
(10) Energy-Related Costs
$44,075
(11) Customer-Related Costs
$18,730
(12) Total Revenue Requirements
$203,372
61
EFFICIENT ENERGY INC.
SGS Rate Elements
Calculation of Energy Charge
(1) Energy-Related Costs (000s $)
(2)
44,075
Divide by MWh (000s kWh)
2,009,265
(3) Energy Charge ($/kWh)
0.0219
Energy Charge
(4) (¢/kWh)
2.19
Calculation of Customer Charge
(5) Customer-Related Costs (000s $)
18,730
(6) Customer-Related Costs ($)
(7)
18,730,032
Divide by Customer Months
998,124
Monthly Customer Charge
(8) ($/customer/mo.)
$
18.77
Calculation of Demand Charge
(9) Demand-Related Costs (000s $)
(10)
140,567
Divide by Billing Demand
(MW = 000s kW)
5,586
(11) Annual Demand Charge ($/kW/year)
$
62
25.16
EFFICIENT ENERGY INC.
Average SGS Customer's Monthly Bill
Energy Component
(1) Energy Charge ($/kWh)
(2)
$
Multiply by Avg. Cust. Monthly kWh
(3) Energy Component of Bill ($/month)
0.0219
2,013
$
44.16
$
25.16
Demand Component
(4) Demand Charge ($/kW/month)
(5)
(6)
Multiply by Avg. Cust. Monthly kW
Demand Component of Monthly Bill
($/month)
5.60
$
140.83
$
18.77
$
203.75
Customer Component
(7)
Customer Component of Monthly Bill
($/month)
Total Bill
(8) Monthly Bill ($/month)
63
EFFICIENT ENERGY INC.
MGS (Secondary) CLASS CHARACTERISTICS
PHYSICAL CHARACTERISTICS
(1)
Total Energy Use
(MWh)
1,826,497
(2) Total Customers
6,820
(3) Total Customer-Months
81,840
Avg. Monthly
(4) kWh/Customer
22,318
(5) Class NCP (MW)
406
(6) Billing Demand (MW)
4,390
Average Monthly
MW/Customer
0.054
Average Monthly
(8) kW/Customer
54
(7)
REVENUE REQUIREMENTS ($000s)
(9) Demand-Related Costs
$110,045
(10) Energy-Related Costs
$39,702
(11) Customer-Related Costs
$1,680
(12) Total Revenue Requirements
64
$151,427
EFFICIENT ENERGY INC.
MGS (Secondary) Rate Elements
Calculation of Energy Charge
(1) Energy-Related Costs (000s $)
(2)
39,702
Divide by MWh (000s kWh)
1,826,497
(3) Energy Charge ($/kWh)
0.0217
Energy Charge
(4) (¢/kWh)
2.17
Calculation of Customer Charge
(5) Customer-Related Costs (000s $)
1,680
(6) Customer-Related Costs ($)
(7)
1,680,313
Divide by Customer Months
81,840
Monthly Customer Charge
(8) ($/customer/mo.)
$
20.53
Calculation of Demand Charge
(9) Demand-Related Costs (000s $)
(10)
110,045
Divide by Billing Demand
(MW = 000s kW)
4,390
(11) Annual Demand Charge ($/kW/year)
65
$
25.07
EFFICIENT ENERGY INC.
Average MGS (Secondary) Customer's Monthly Bill
Energy Component
(1) Energy Charge ($/kWh)
(2)
$
Multiply by Avg. Cust. Monthly kWh
(3) Energy Component of Bill ($/month)
0.0217
22,318
$
485.11
$
25.07
Demand Component
(4) Demand Charge ($/kW/month)
(5)
(6)
Multiply by Avg. Cust. Monthly kW
Demand Component of Monthly Bill
($/month)
54
$ 1,344.64
Customer Component
(7)
Customer Component of Monthly Bill
($/month)
$
20.53
Total Bill
(8) Monthly Bill ($/month)
$ 1,850.28
66
EFFICIENT ENERGY INC.
MGS (Primary) CLASS CHARACTERISTICS
PHYSICAL CHARACTERISTICS
(1)
Total Energy Use
(MWh)
2,739,745
(2) Total Customers
454
(3) Total Customer-Months
5,448
Avg. Monthly
(4) kWh/Customer
502,890
(5) Class NCP (MW)
514
(6) Billing Demand (MW)
5,551
Average Monthly
MW/Customer
1.019
Average Monthly
(8) kW/Customer
1,019
(7)
REVENUE REQUIREMENTS ($000s)
(9) Demand-Related Costs
$135,061
(10) Energy-Related Costs
$57,367
(11) Customer-Related Costs
$121
(12) Total Revenue Requirements
67
$192,549
EFFICIENT ENERGY INC.
MGS (Primary) Rate Elements
Calculation of Energy Charge
(1) Energy-Related Costs (000s $)
(2)
57,367
Divide by MWh (000s kWh)
2,739,745
(3) Energy Charge ($/kWh)
0.0209
Energy Charge
(4) (¢/kWh)
2.09
Calculation of Customer Charge
(5) Customer-Related Costs (000s $)
121
(6) Customer-Related Costs ($)
(7)
121,451
Divide by Customer Months
5,448
Monthly Customer Charge
(8) ($/customer/mo.)
$
22.29
Calculation of Demand Charge
(9) Demand-Related Costs (000s $)
(10)
135,061
Divide by Billing Demand
(MW = 000s kW)
5,551
(11) Demand Charge ($/kW)
$
68
24.33
EFFICIENT ENERGY INC.
Average MGS (Primary) Customer's Monthly Bill
Energy Component
(1) Energy Charge ($/kWh)
(2)
$
Multiply by Avg. Cust. Monthly kWh
(3) Energy Component of Bill ($/month)
0.0209
502,890
$ 10,529.93
Demand Component
(4) Demand Charge ($/kW/month)
(5)
(6)
$
Multiply by Avg. Cust. Monthly kW
Demand Component of Monthly Bill
($/month)
24.33
1,019
$ 24,790.92
Customer Component
(7)
Customer Component of Monthly Bill
($/month)
$
22.29
Total Bill
(8) Monthly Bill ($/month)
$ 35,343.14
69
EFFICIENT ENERGY INC.
LGS CLASS CHARACTERISTICS
PHYSICAL CHARACTERISTICS
(1)
Total Energy Use
(MWh)
3,652,962
(2) Total Customers
44
(3) Total Customer-Months
528
Avg. Monthly
(4) kWh/Customer
6,918,489
(5) Class NCP (MW)
608
(6) Billing Demand (MW)
6,563
Average Monthly
MW/Customer
12.4
Average Monthly
(8) kW/Customer
12,430
(7)
REVENUE REQUIREMENTS ($000s)
(9) Demand-Related Costs
$149,144
(10) Energy-Related Costs
$75,032
(11) Customer-Related Costs
$199
(12) Total Revenue Requirements
$224,374
70
EFFICIENT ENERGY INC.
LGS Rate Elements
Calculation of Energy Charge
(1) Energy-Related Costs (000s $)
(2)
75,032
Divide by MWh (000s kWh)
3,652,962
(3) Energy Charge ($/kWh)
0.0205
Energy Charge
(4) (¢/kWh)
2.05
Calculation of Customer Charge
(5) Customer-Related Costs (000s $)
199
(6) Customer-Related Costs ($)
(7)
198,866
Divide by Customer Months
528
Monthly Customer Charge
(8) ($/customer/mo.)
$
376.64
Calculation of Demand Charge
(9) Demand-Related Costs (000s $)
(10)
149,144
Divide by Billing Demand
(MW = 000s kW)
6,563
(11) Demand Charge ($/kW)
$
71
22.72
EFFICIENT ENERGY INC.
Average LGS Customer's Monthly Bill
Energy Component
(1) Energy Charge ($/kWh)
(2)
$
Multiply by Avg. Cust. Monthly kWh
(3) Energy Component of Bill ($/month)
0.0205
6,918,489
$ 142,106
Demand Component
(4) Demand Charge ($/kW)
(5)
(6)
$
Multiply by Avg. Cust. Monthly kW
Demand Component of Monthly Bill
($/month)
22.72
12,430
$ 282,469
Customer Component
(7)
Customer Component of Monthly Bill
($/month)
$
377
Total Bill
(8) Monthly Bill ($/month)
$ 424,952
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