Tariff Development II: Developing a Cost of Service Study

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Tariff Development II:
Developing a Cost of
Service Study
Energy Regulatory Partnership Program
Abuja, Nigeria
July 14-18, 2008
Ikechukwu N. Nwabueze, Ph.D.
Director, Regulated Energy Division
Michigan Public Service Commission
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Why Is a Cost of Service Study
Needed?
• Regulators are mandated by statue to establish
just and reasonable rates for utilities under their
jurisdiction.
• Most industry experts agree that proper rates
must be designed and implemented to recover
costs incurred by a utility to provide the service
required by the customers.
• The objective of a cost of service study is to
apportion all costs required to serve customers
among each customer class in a fair and
equitable manner.
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Principles of Rate Regulation
• Fairness to both the regulated utility (its
owners (or stockholders)) and the
ratepayers
• Avoidance of unjust or undue
discrimination between rate classes or
customers
– Cost causation - the concept of the cost
causer pays the costs it imposed on the utility
system
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Principles of Rate Regulation
(Continued)
• Cost allocation calculated through a cost
of service study determines how many
dollars to collect from various classes or
rates allowing the proper total revenue
requirement to be collected through rates
• Rate design determines how to collect
dollars from various customer groups
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Cost of Service
• The purpose of a cost of service analysis:
– Allocation of revenue recovery
• Determining the proper rate level for each group of
customers for which rates are designed
– Identifying variable and fixed costs
• Determining the variable and fixed costs associated
with service provided to each group of customers
– Component pricing
• Cost information for determining the most efficient
design (especially important when designing
unbundled rates)
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Important Definitions to Understand
• Customer Class or Class of Service – A set of customers
with similar characteristics who have been grouped for
the purpose of setting an applicable rate for electric
service
– Common classifications include residential, commercial, primary
service and industrial
• Energy – kilowatt-hours (kWh) supplied to or used by an
individual customer, group of customers or class of
service
• Demand – rate at which electric energy is used at a
given instant or averaged over a designated time
interval.
– Typically demand is expressed in kilowatts (kW) or megawatts
(MW), one megawatt equals 1,000 kilowatts.
– Company uses average hourly demands in the development of
allocation schedules
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Important Definitions (Continued)
• System Peak Demand – The highest total hourly demand (MW) for all
customers served on the utility’s distribution system within a specific
period (day, month, year). Typically referred to as the ‘system peak’.
• Coincident Peak Demand – The demand of any class within a specific
period (day, month, year) that occurs at the same time as the system
peak demand for the same period.
• Coincident MH4CP Demand – The demand value derived by averaging
the actual demand values for hours beginning 12 noon through 8 p.m.
registered on the monthly peak days for June, July, August and
September.
• Coincident 12 CP Demand – The demand value derived by averaging
the actual demand values registered on the monthly peak days for
January through December.
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Important Definitions (Continued)
• Non-Coincident Peak Demand – The maximum demand of any class
within a specific period but not necessarily occurring at the time of the
system peak demand for that period.
• Losses – A term used to define the difference between the electrical
energy delivered to a customer (or a given point on the electrical
distribution system) and the amount of electrical energy that must be
generated at the power plant to serve that customer. In other words,
losses refer to the amount of power lost in transferring power from
the power plant to the point of delivery (often referred to as line loss).
Line losses will vary by rate class based upon the voltage level at
which each class is served.
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Load Factor & Hours Use
Definitions
Load Factor
The ratio, in percent, of the average energy use over a period of
time to the maximum demand in that period.
Load Factor (%) = Total Energy / Number of Hours / Peak Demand
Hours Use
The number of kWh’s used per kW of maximum demand (normally
calculated from an average kWh per month value).
Hours Use = Monthly kWh / Maximum Demand (kW)
22
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Load Factor & Hours Use
Example
Customer Use Data:
64,459 Annual kWh
16 kW Maximum Demand
Load Factor (%) =
64,459 kWh / 8760 Hours = 7.3583 / 16 kW Maximum Demand x 100 = 46%
Hours Use =
64,459 kWh / 12 = 5371.58 Average kWh per Month / 16 kW = 336
23
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Types of Cost of Service
Approaches
• Embedded Cost Basis - Used by MPSC
– Determine apportionment of accounting-based revenue
requirement using functionalization, classification and allocation
process
– A fully allocated embedded unbundled cost of service study
allocates all items of utility property and cost to determine the
fully allocated embedded cost of service for each customer class
of service and shows each customer class’ share of costs by
major function (Power Supply and Distribution)
• Marginal Cost Basis
– Estimate the additional cost in providing increments of service to
each service function
– Reconcile to embedded Rate of Return if used so that allowed
Revenue Requirement is possible
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Basic Steps to Rate Base
Regulation
• Determine test period Total Revenue
Requirements
• Calculate part of Revenue Requirement to be
recovered by Jurisdictional retail rates (Total
revenue less amounts from other sources)
• Allocate Revenue Requirements to Various
Classes of Service
• Determine Rate Structure (Prices) for Each
Customer Rate Class – Design Rates
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Reminder: Determining Revenue
Requirements
• Revenue Requirement is defined as:
That level of revenues sufficient to cover a
utility’s cost of service including a return on its
investment
• The formula to determine Revenue
Requirement is:
• R = (V-D) r + E
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Reminder: Revenue Requirement
Formula: R = (V-D) r + E
• R = Revenue Requirements
• V = Value of Rate Base
• (Plant in Service plus Working Capital)
• D = Accumulated Depreciation
• r = Rate of Return on investment
• E = Operating Expenses
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Emphasis on Proper Cost Accounting
on Which to Set Regulated Tariffs
• Uniform System of Accounts
• Functional accounting system
comprised of specific accounts in which
all transactions are recorded at cost.
• Rate Case Filing Requirements
• Test Year
• Rate Case Audit
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MPSC Cost of Service Allocation Methods
(Case No. U-4771 dated 5/10/76)
The Order requires exhibits detailing a fully-distributed cost of service
by rate schedules to be submitted. This cost of service data shall be
based upon the following apportionment methods:
• Average twelve month peak demand responsibility.
• Production and transmission plant assigned as 75% demand
related and 25% energy related.
• Specific distribution plant such as meters and service drops used
exclusively for a given customer shall be treated as customer
related. All other distribution plant shall be treated as demand
related.
• The separations studies must correspond to the proposed test year
and consider all of the adjustments made to rate base and net
operating income.
• It should show a breakdown by major functional groupings of the
various apportionments along with a verbal description of the full
procedure used.
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Embedded Cost Studies – Methods of Allocation,
Functionalization, and Classification
• Functionalization assigns all costs to the major functions,
i.e. Power Supply and Distribution.
• Classification divides these costs into customer-related
costs, demand related costs, and energy-related costs.
– The sum of these three types of costs within a given class is the
cost to serve that class.
– In some cases, formally classifying the costs is not necessary
because the allocation methods employed within the cost of
service recognize and properly account for whether the item
being allocated is customer, demand, or energy related.
• Allocation apportions the cost classifications to the
respective classes of service, sometimes comprised of
one or more individual rate schedules, based upon the
class’ responsibility for the incurrence of these costs.
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Cost Study Functions
• The major utility functions used in Michigan cost studies
are Power Supply (Generation and Transmission), and
Distribution.
• Power Supply includes costs associated with a utility’s
generating plant, fuel, purchased power and the expense
associated with transmission services provided to the
utility by its regional transmission operator, MISO and
the International Transmission Company, the
transmission system owner.
• Distribution includes the costs associated with the
utility’s distribution system, that generally operates at
voltages of 40 kV and below and includes customer
service expenses.
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Unbundled Cost of Service Study
• Fully allocated embedded Unbundled Cost of
Service Study is developed for the utility, that is
consistent with the service components (functions),
which are Generation, Transmission, and
Distribution.
• The total jurisdictional revenue requirement of the
cost of service equals the jurisdictional revenue
requirement.
• A fully allocated embedded cost of service study
allocates all items of utility property and cost, taken
from the books and records of the Company, to
determine the fully allocated embedded cost of
service for each customer class of service.
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Costs are separated by all functions:
•
•
•
•
•
Production
Transmission
Distribution
Customer Accounts and Customer Service
Administrative and General
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Functionalized costs are classified:
• Capacity –
• Costs associated with meeting system
throughput and demand requirements.
• Energy –
• Costs that vary with the volume of energy
sold.
• Customer –
• Costs resulting from having a customer
connected to the utility.
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Another way to look at classifying costs:
– Variable costs: costs that vary with output (e.g.,
commodity costs such as fuel, purchased gas for
combustion turbines, etc.)
– Fixed costs: costs that remain constant across a
range of output (e.g., demand and customer costs,
depreciation)
– Common costs: costs incurred jointly for two or more
types of operation or the provision of two or more
services (e.g., capital cost of a power plant serving
residential, commercial, and industrial customers)
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Allocation of Revenue Requirements to
Various Classes of Service
• Group customers into rate classes
• Rate classifications should produce
homogeneous groups based upon
characteristics of each group
–Residential
–Commercial – Secondary and Primary
–Industrial – Secondary and Primary
–Retail Open Access – ROA
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Allocation factors are developed that reflect
the nature of the classified and
functionalized costs.
• Cost allocation determines Revenues, and
Consequently, average price, to be collected from
each class of customers (or each rate)
• Factors applied to the utility’s costs to allocate
them to each rate class.
• Some costs are directly assigned such as lamp
fixture costs for a street lighting rate.
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Four Measurements of Allocation Schedules
Energy – measures Power Plant Production as they are built to produce the
energy required by customers.
Coincident (CP) Demand – the output of Plant Production and the input into
the Distribution System are designed to meet the System Peak Demand
requirements of the electrical system.
Class Maximum Demand (NCP) – Substations, high voltage lines and
transformers are designed to meet the maximum load of the Customer
Classes they serve.
Individual Customer Maximum Demands – Low voltage secondary lines are
designed to serve the absolute maximum demand level for a customer
class.
19
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Cost of Service Process
• The process also includes determining the
“jurisdictional” amount of each base input.
– Jurisdictionalization means separating the costs
associated with providing electric service to retail
customers, which falls under MPSC jurisdiction, from
those costs associated with providing service at
wholesale, which is subject to FERC jurisdiction.
• This is typically accomplished within the cost of
service study by applying allocation schedules
that include the loads associated with FERC
jurisdictional sales to customers in apportioning
total electric utility costs.
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Jurisdictional Separation
• Jurisdictional separation is a product of the allocation
process whereby the revenue and costs associated with
the utility’s wholesale for resale sales to wholesale
requirements customers (regulated by the FERC) are
separated from those associated with sales that fall
under the jurisdiction of the MPSC.
• These wholesale for resale customers are Michigan
municipal and cooperative utilities that purchase their
power supply requirements from the utility for resale to
Michigan retail customers.
• The jurisdictional electric columns within a filing contain
the portion of the utility’s total electric costs that fall
under the MPSC jurisdiction.
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Allocation Schedules
• The allocation schedules are calculated using
established principles and methods, and
industry recognized and accepted load research
principles supported by Edison Electric Institute
and Association of Edison Illuminating
Companies.
• The methods used also conform to nationally
recognized standards for developing allocation
schedules and are consistent with the methods
used in all electric case filings.
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Allocation Schedules
(Continued)
• Allocation Schedules are developed, using customer
class sales, load research samples and quantitative
models, to determine the extent (expressed as a
percentage) that each customer class uses the various
portions of the electrical system.
– System loss studies are updated periodically to establish up-todate loss multipliers to be applied to sales to determine each
class (or rate’s) generation requirements.
• Percentages determined in the Allocation Schedules are
used by the Cost of Service witness to determine rate
class cost responsibility.
• Because all customer classes do not utilize the full
distribution system to take delivery of electrical service,
the Allocation Schedules are developed to assign only
the portions of the system actually used by each
customer class.
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Determination of Allocation Factors
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Determination of Allocation Factors
(Continued)
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Uniform System of Accounts
•
•
•
MPSC Uniform System of Accounts governs utility accounting for
ratemaking purposes and serves as the basis for functionalizing costs, e.g.,
the USA requires utilities to record generating plant costs in accounts 310 359 and the associated O&M expense in accounts 500 - 557. These costs
are directly assigned to the power supply function.
Similarly, there are accounts in which the USA requires utilities to record
distribution plant and O&M costs that are directly assigned to the distribution
function. The O&M cost in accounts associated with providing customer
service are directly assigned to distribution because they apply whether a
customer receives power supply from the utility or an alternative electric
supplier.
Because Michigan utilities have divested transmission plant, all that remains
in the USA’s accounts designated for transmission are the plant costs
associated with generator step up transformers. These costs are directly
assigned to power supply. In addition, power supply includes the expense
charged to account 565, “Transmission of Electricity by Others” including
MISO charges.
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Production Plant
• MPSC Order in Case U-4771 that established standard filing
requirements which included the traditional method used in
the Cost of Service to allocate production plant costs.
– It is weighted 75 percent based on the average of the 12
coincident peak demands and 25 percent based on energy.
• FERC uses a coincident peak methodology (usually 12 CP or
4 CP) for allocating production costs within cost of service
studies.
– Recently, Michigan began using the ‘Multi-Hour 4 Coincident
Peak (MH4CP) Methodology’ for Detroit Edison and Consumers
Energy.
– It is used in Detroit Edison’s current rate case to develop the
historic 2006 allocation schedules using the hourly rate class
demands for the hours of 12 noon through 8 p.m. were averaged
for the monthly system peak days of June, July, August and
September to determine the peak contribution of each rate class.
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Power Supply Allocators
•
First, production plant and the demand component of purchased power
expense are to be allocated using an allocation schedule consisting of 3
weighted components:
1. Average of the 4 monthly coincident peak multi-hour demand (“4CPMH”)
weighted 25% where the 4 peak months are June, July, August, and September
and the multi-hour peak consists of an 8-hour period (noon – 8 pm) on the peak
day of each month
2. Energy use at point of system output coincident to the MISO's on-peak period (7
am –11 pm) weighted 50%
3. Total energy use at point of system output weighted 25%
•
•
Second, the portion of each production O&M expense account that was
originally allocated using the average of the 12 monthly coincident peak
(“CP”) single hour demands is changed to 33% allocated based on the
average of the 4 monthly CP multi-hour demands and 67% allocated on
energy use at point of system output during MISO’s on-peak period.
Third, 10% of fuel expense is to be allocated using the average of the
4CPMH with the remaining 90% allocated using energy.
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Other Production Costs Allocation
Methods
• Coincident peak methods
– 1 CP
– Average 12 CP
– Seasonal CP or 4CP(4 summer months when load is
highest)
– Multiple CP
• Energy allocators
– Total Energy
– Seasonal Energy
– Time of Day Energy (on-peak or off-peak)
• Average and excess
– Essentially allocates based on load factor
– Measures of demand may vary
– Seasonal application
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Transmission Plant
• Transmission plant is a group of highly integrated bulk
power supply facilities consisting of high voltage power
lines and substations
– Principle differences between utility systems include voltage
levels and system configurations.
• Transmission plant is sometimes broken down into:
–
–
–
–
–
Backbone and Inter-tie Transmission Facilities
Generation Step-up Facilities
Subtransmission – 25 KV to 115 KV
Radial Facilities
Plant reclassifications
• Recently the sales of transmission plant have been
made by Michigan utilities to regional owners, who
provide transmission service to all under FERC
approved charges
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Allocation of Transmission Plant
• Allocation of Transmission plant is related to the
production plant that it is connected to.
– Because of this, Michigan allocates transmission plant generally
on a similar demand related basis as its traditional production
plant allocation of 75% on a12 coincident peak demand and 25%
energy basis.
• Other allocation methods recommended by the NARUC
Cost Allocation Manual include:
–
–
–
–
–
–
–
1 Coincident Peak Demand using single highest peak
Average Seasonal System Coincident Peak
12 Coincident Peak Demand
1 Non- coincident Peak
Monthly Average Non- coincident Peak
Average and Excess
Or direct assignment
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Distribution Plant
• Distribution plant includes facilities that provide
service at primary and secondary voltages.
• Distribution line, transformers, substations,
metering, service drops and poles are all
considered components of a utility’s distribution
system.
• Distribution plant is classified as either demand
or customer related after functionalization as
overhead or underground, and primary or
secondary voltage related.
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Distribution Plant (Continued)
• Distribution plant is classified depending on what facility
it is by the following methods:
– Minimum-Size Method - assumes minimum system sizing for the
minimum service requirements of customers
– Minimum-Intercept Method – identifies plant related to
hypothetical no-load situation
– Distribution plant classified as demand related is allocated on
customer class non-coincident demands and individual customer
maximum demands
– Distribution plant classified as customer related is allocated
based on the number of customers sometimes weighted for
differing characteristics such as differences in metering.
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One Time Costs: Connection Tariffs
• At times customers require significant amounts of plant
investment be added to the utility system in order to
provide adequate service to them.
• A large industrial manufacturing customer may need to
have a line, substation or transformation equipment
specifically design and operated exclusively for their use
(dedicated service).
• A hospital may need to have a redundant service to
provide adequate backup during emergencies.
• Costs such as these may be directly assigned in a cost
of service study to a particular class or rate.
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Customer Related Costs
• Customer related costs include billing, collections,
information, customer service, and advertising and
promotion.
– Uncollectible accounts are included and are sometimes directly
assigned to specific classes.
• These costs may be functionalized and classified as part
of the distribution function related to customers.
– Sometimes these are functionalized on a plant/labor based
method.
• Customer account costs, sales costs and customer
service costs are generally considered customer related,
while load management and conservation efforts maybe
allocated based on program goals.
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Common and General Plant and
Administrative Costs
• Administrative and General costs are costs not included
elsewhere such as general salaries, insurance, general
office building and expenses or transportation
equipment.
• These costs are allocated either on the sum of the other
operating and maintenance costs or based on whether
they are labor related, plant related or can be directly
assigned.
• The property tax associated with production plant is
directly assigned to power supply based on tax
information provided by the Property Tax Department.
– A share of the property tax associated with general and software
plant is allocated to power supply in proportion to the power
supply-related general and software plant and the remaining
balance is assigned to distribution.
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Plant and Administrative Costs
(Continued)
• Indirect costs are comprised of general and intangible
(software) plant costs recorded in accounts 303 and 389 399, O&M expense in accounts 920 - 935, taxes, and
working capital.
• The cost study also includes a credit for miscellaneous
revenue, which is applied to the appropriate functional
component based on a combination of direct assignment
and allocation.
• Indirect costs are functionalized using various methods
depending on the type of cost.
– General and software plant costs are functionalized using a
combination of direct assignment and allocation.
– Direct assignment of general and software plant costs is based on
the “business unit” field found in the Company’s property records.
– General and software plant for which there is no assigned business
unit is functionalized in proportion to direct labor cost.
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Plant and Administrative Costs
(Continued)
• Administrative and general (“A&G”) expense is
functionalized using the same method as
General plant and software.
– A&G expense includes costs associated with
corporate support.
– Working capital is functionalized using allocators
appropriate to each of the current asset and liability
line items, e.g., fuel inventory is directly assigned to
power supply and accounts receivable is
functionalized based on net plant.
• Miscellaneous revenue is functionalized using a
combination of direct assignment and allocation.
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Plant and Administrative Costs
(Continued)
• The National Association of Regulatory Utility
Commissioners’ 1992 Electric Utility Cost Allocation Manual
offers some alternative methods for allocating general
plant:
– “One approach to the functionalization, classification, and allocation
of general plant is to assign the total dollar investment on the same
basis as the sum of the allocated investments in production,
transmission and distribution plant. This type of allocation rests on
the theory that general plant supports the other plant functions…
Another suggested basis is the use of operating labor ratios.”
(National Association of Regulatory Utility Commissioners, January,
1992, page 105.)
• Another method sometimes employed directly assigns
general and software plant based on property records and
uses labor ratios to assign the balance.
• A&G costs are functionalized by use of the allocator
developed for general plant and software functionalization.
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Plant and Administrative Costs
(Continued)
• Indirect costs are comprised of general and software plant costs
recorded in accounts 303 and 389 - 399, O&M expense in accounts
920 - 935 (A&G), taxes, and working capital.
• The functionalized general and software plant costs are allocated
based on the corresponding functional plant in service.
– The general and software plant costs associated with power supply are
allocated based on production plant in service and the general and
software costs associated with distribution are allocated based on
distribution plant in service.
– The functionalized A&G is allocated based on the corresponding
functional labor ratios.
• Property taxes are allocated based on the corresponding functional
plant in service.
– Payroll taxes are allocated based on the corresponding functional labor
ratios.
• The working capital allocations are driven by the numerous
allocators associated with each of the line items that comprise
working capital, many of which are the sum of several other lines.
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Reduction and Elimination of
Cross-Subsidies
Deskewing or Rate Realignment
(Rationalization of Tariffs)
• Historically in Michigan, residential customers’ rates have been
subsidized by commercial and industrial customers.
– This is maintaining residential rates at levels too low to achieve
required rates of return.
• Recent Commission Order in Consumers Energy rate case
U-15245 initiated the rate alignment process to bring all customers
to cost of service.
– Current legislation proposes to eliminate subsidization through
rate design over a period of years.
– This will allow reduced rate shock to customers currently paying
rates less than their cost to serve.
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Rate Realignment
• Detroit Edison is proposing in its current rate processing
to reduce inter-class rate subsidies included in existing
rates by 20%.
• Edison believes that all subsidies should eventually be
eliminated.
• It is not practical to remove the entire subsidy at one
time because of the impact on customers.
• The current rate subsidy was implemented over a long
period of time.
• To minimize rate shock, it would be more prudent to
phase-out the subsidy over a period of time.
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Cost of Service Summary Example
The Detroit Edison Company
Unbundled Cost of Service Excluding Securitization Bond
Year Ending Dec 31, 2005 Adjusted for K&M Changes Thru Dec. 31, 2007 4 CP multi-hour Staff Method
(thousands of dollars)
(1)
Total
Electric
8,072,679
(2)
Alloc
Juris
Electric
7,900,026
Revenue excl Securitization Bond
4,212,939
Expenses:
Fuel
Purchased Power
O & M Expense
Depreciation
Other (Net Reg Assets, etc)
Gain on Sale of Allowances
Other Taxes
Income Taxes
Total Expenses
956,118
569,998
1,346,535
492,529
36,182
(2,933)
239,232
141,882
3,779,542
-
Rate Base
(3)
Total
Residential
3,444,619
(4)
Total
Commercial
Secondary
1,964,348
(5)
(6)
(7)
Total
Primary
2,061,683
Total
Government
429,376
Total
Wholesale
172,653
4,138,993
1,686,014
956,509
1,298,357
198,113
58,658
922,107
544,091
1,318,482
484,208
36,182
(2,803)
233,934
153,033
3,689,236
339,402
181,301
697,463
225,026
13,062
(1,016)
106,763
16,365
1,578,367
187,737
102,212
284,125
120,814
7,513
(568)
55,895
54,174
811,903
346,546
233,127
289,340
114,469
13,850
(1,069)
59,728
72,623
1,128,613
48,422
27,451
47,554
23,899
1,758
(150)
11,548
9,870
170,352
34,011
25,907
28,053
8,320
(130)
5,297
(16,502)
84,956
Net Oper Income
433,397
449,757
107,647
144,605
169,744
27,760
(26,298)
AFUDC
Net Adjustments
Known & Measurable NOI Adjustments
Adj Net Oper Income
6,107
42,284
80,680
562,468
5,862
41,891
63,852
561,362
2,128
80,362
(51,519)
138,618
1,227
(16,346)
51,190
180,676
2,225
(20,210)
62,923
214,682
283
(1,915)
1,259
27,386
245
394
23,843
(1,816)
4.02%
9.20%
10.41%
6.38%
-1.05%
Rate of Return
6.97%
Index of Return (Jurisdictional)
7.11%
100
57
594,149
31,681
581,442
20,080
253,524
114,906
144,576
(36,100)
151,740
(62,942)
31,602
4,216
Base Revenue Def / (Sufficiency)
Additional Rev Req
Total Revenue Def/ (Sufficiency)
49,815
49,815
31,573
24,921
56,494
180,678
9,045
189,723
(56,763)
5,216
(51,548)
(98,970)
9,458
(89,512)
6,629
1,202
7,831
Incr Rev & Tax from 2005 adjustments
Tax effects of K&M Revenue Changes
Base Year Deficiency
17,655
39,974
64,186
17,655
39,973
29,119
6,638
19,295
102,334
3,810
10,959
(57,402)
6,329
7,404
(26,351)
878
2,316
10,538
50,647
4,384,569
4,282,234
2,004,003
219,675
107,220
Return @ 7.36 %
Income Deficiency
Revenue Requirement
129
862,328
147
1,196,228
90
12,707
14,523
22,836
(24,921)
(2,085)
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Rate Realignment (Continued)
• A rate subsidy exists when there is a difference between a
tariff’s current rate level and what the tariff’s rate level would
be if that tariff’s rate level were based only on full cost of
service.
• Subsidies can be either positive or negative and an inter-class
rate subsidy is created when tariff rate levels are set at a level
above or below cost to serve.
• A tariff whose average rate is less than the cost to serve
would include a negative subsidy indicating that other tariffs
are subsidizing this tariff by having rates set at a level higher
than cost to serve.
• For example, Detroit Edison’s current rates are such that fullservice commercial and industrial customers pay rates that
are in excess of the cost of service while residential
customers pay rates that are less than cost of service. In
short, full-service commercial and industrial customers are
subsidizing residential customers.
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Why would a utility be concerned about inter-class
subsidies as long as it’s allowed to collect its total
revenue requirement?
• Even with rates designed to collect the utility’s full revenue
requirement, subsidies in any form send the wrong economic
signal to customers.
• Residential rates set below cost send incorrect price signals to the
residential customer where, arguably, the residential customer is
not aware of the true cost of electric service.
• All other things being equal, commercial and industrial rates set
above cost to serve have a negative effect on those customers’
abilities to compete.
• While utility rates are only one factor that affect business
development decisions, electric rates set above the actual cost-toserve negatively affects Michigan’s competitive position as
measured against other states and may discourage commercial
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and industrial customers from investing in Michigan.
MPSC 21st Century Energy Plan
• The 21st CEP recognizes the current inter-class rate
subsidy issue and recommends that the Commission
move towards rates based on the actual cost of serving
customers.
• Supporting its recommendation, the 21st CEP states:
– “Residential service is heavily subsidized by commercial
customers and may be subsidized by industrial customers. In
order to subsidize residential service, regulated utilities must
maintain non-competitive rates for commercial and industrial
customers’ rates, giving those customers an incentive to leave
the regulated market for the competitive market. Thus,
customers are denied an accurate cost comparison, and the
utilities may be denied their most valuable customers for reasons
not based on cost.” (21st CEP, page 21)
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MPSC 21st Century Energy Plan
(Continued)
• The 21st CEP also recommends that Power
Supply rates should be based on cost stating:
– “If utility generation rates are not based on cost,
migration of high margin customers occurs for
reasons having nothing to do with the parties’
competitive advantages in providing service.
• The Commission is then faced with a continuing
need to consider raising rates for customers who
remain with the incumbent utility due to
diminished revenues caused by departing
customers.” (21st CEP Page 22)
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Changes in Cost of Service
•
•
•
•
Generation
– Quality of information regarding marginal costs and hourly loads
with better metering (AMI) have led to increased use of this
measure for allocation and pricing purposes
Transmission
– Many utilities have joined an ISO / RTO and filed FERC rates based
on embedded costs
– Marginal cost measurement used to determine short-run congestion
costs
Distribution
– Marginal cost methods have been developed and are most useful
for utilities with significant cost differences by location
– Embedded cost allocation methods still most prevalent
Customer Services
– Marginal cost methods have become more well developed and
provide useful pricing signals
– Difficult to bring fixed charges up to full marginal costs particularly
for mass markets
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Questions?
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