Institute for
Regulatory Policy
Studies, Illinois
State University
Cost of Service and
Rate Design Workshop
Sherman Elliott
Manager, State Regulatory Affairs,
Midwest ISO, Inc.
Midwest Independent Transmission System Operator, Inc.
701 City Center Drive
Carmel, Indiana 46032
217.522.6674
217.522.6676 (f)
selliott@midwestiso.org
July 14-15, 2005
Workplan
 Introductions
 Presenter
 Overview of the approach
 Introduction to ratemaking
 Revenue requirements
 Cost of capital
 Cost of Service
 Concepts
 Embedded cost study
 Marginal cost study
 Group Discussion
 Role playing (Utility, consumer advocate, industrial advocate)
 Cost of service alternative scenarios
2
Workplan
 Next Morning’s Session
 Interclass Revenue Allocation
 Review of Cost Concepts
 Marginal
 Embedded
 Turning Costs into Rates using different Scenarios
 Use results of cost studies to price services
 Discuss rate effects of alternative scenarios
 Rate shock and Equity concerns
 Rationale for deviating from cost causation
3
Institute for
Regulatory Policy
Studies, Illinois
State University
Introduction to
Ratemaking
(6 Slides)
The Regulatory Equation (1)
 Revenue Requirement = OC + r(V-D) + T + d + OSS
 OC = Operating Costs
 T = Taxes
 d = Annual depreciation expense
 r = Rate of return
 V = Value of physical and financial capital
 D = Accumulated depreciation
 r(V-D) is called the “return portion” and V-D is called “rate base”
 OSS = Off System Sales
5
Setting the Period of Examination
(2)
 Test Year - Any 12 month period used for
evaluating the revenues, operating expenses,
depreciation, taxes, and rate base for purposes
of setting rates.


Current (or historical) Test Year – A 12 month
period which reflects the actual results of current
operations could be adjusted for known and
measurable changes.
Future or Forecasted Test Year - A future 12
month period which reflect the anticipated results of
normal operations.
6
Adjustments (3)
 Pro-Forma Adjustments – known and
measurable changes
 Non-recurring expenses

One-time basis, irregular intervals

Amortized over the time period between rate cases
7
Determining Rate Base (V-D) (4)
 How to determine rate base?

Net original cost (i.e., book) rate base (net means
V-D)

Fair market value
– Reproduction cost - the cost of duplicating the existing
plant and equipment at current prices
– Replacement cost - the cost of duplicating the old plant
with the modern technology version
8
When to Measure Rate Base? (5)
 End of period rate base - Value of the rate base
at the end of the test year. This concept
typically is used in conjunction with a current or
historical test year.
 Average (normalized) rate base - Average rate
base throughout the test (i.e., typical) year.
This concept typically is used in conjunction
with a future or projected test year.
9
Major Items in Rate Base (6)
 Plant in Service
 Construction Work in Progress (CWIP)
 AFUDC
 Materials and Supplies
 Cash Working Capital
 Prepayments
 Typical Deductions:
»
»
»
Accumulated Depreciation
Deferred Taxes
Contributions in Aid of Construction
10
Institute for
Regulatory Policy
Studies, Illinois
State University
Cost of Service
(21 Slides)
Introduction to Cost of Service (1)
 Cost of service studies (COSS) are used to:





Attribute costs to different customer classes
Determine how costs will be recovered from customers
within classes
Calculate costs of different services
Separate costs between jurisdictions
Determine revenue requirement between competitive and
monopoly services
 General types of cost studies


Embedded (Test year accounting costs)
Marginal (Change in costs related to change in output)
12
Steps in COSS (2)
 Obtain test year utility revenue requirement
(generally an accounting/finance function e.g.,
USOA)

Other revenues (e.g., off-system sales, Hub sales,
etc.)

Jurisdictional revenues/costs
 Determine customer classes
 Allocation of costs to cost-causers
13
Customer Class Determination (3)
 Attempt to group customers together that have
common cost characteristics, for example,

Size (volume and capacity)

Type of customer and meter (residential,
commercial, industrial, electricity generation)

Type of usage (space heat, non-space heat etc.)

Type of load (firm, interruptible)

Load factor (average usage relative to peak usage)

Competitive alternatives (related to opportunity
cost)
14
Embedded Cost Studies (ECOSS) (4)
 Functionalize (production, distribution, transmission
etc.).


For gas and electric utilities, functionalization is generally an
accounting exercise (i.e., use USOA).
Exception: Electric transmission may need additional
analysis (e.g., FERC seven factor test).
 Classification (demand-related, volume-related,
customer-related, etc.).
 Allocation.
 Direct assignment.
 Allocator (demand, energy, customers, etc.).
15
Functionalization (5)
 Electric and Gas utilities

Generation or gas production

Distribution (low voltage lines, low pressure mains)

Transmission (high voltage lines, high pressure
mains)

Customer Service (costs associated with hooking
up customers, meters, service drops, etc.)

General plant and administrative and general
expenses (management costs, costs of buildings
and offices, etc.)
16
Functionalization-Example Electric
Utility (6)
Plant in Service Accounts
Expense Accounts
17
Classification of Costs (7)
 Costs are assumed to be related to demand, energy,
customer or revenues.




Capacity costs (e.g., gas mains, generation plant, etc.) do
not change as output changes, but do change as the
capacity of the system changes. These are fixed costs that
are generally classified as demand-related (i.e., related to
kW or therm capacity).
Energy-related costs change with output (e.g., fuel). These
are classified as energy-related or volumetric (i.e., related to
kwh or therm throughput).
Customer-related costs (e.g., meters, services) change with
the number of customers added to the system.
Revenue-related costs (e.g., revenue taxes) are related to
the revenue received by the company.
18
Classification of Costs-ExamplesGas (8)
Function
Production & Gas Supply
Gas Supply
Storage
LNG
Propane
Transmission
Compressor Stations
Mains
Regulatory Stations
Distribution
Compressor Stations
Mains
M&R Stations
Services
Meters
House Reg
Imd M&R Stations
Customer Installations
Other
Customer Accounts
Sales Expense
Revenue
Revenue from Sales
Revenue Taxes
Classification with Allocation Methods
Demand
Commodity
Customer
Revenue
Capacity
Capacity
Capacity
Capacity
Volume
Volume
Volume
Volume
Capacity
Capacity
Capacity
Volume
Volume
Volume
Capacity
Capacity
Capacity
Capacity
Specific Assignment
No. Customers
No. Customers
No. Customers
No. Customers
No. Customers
Specific Assignment
Specific Assignment
No. Customers
No. Customers
Revenue
Revenue
Source: Adapted from American Gas Association, Gas Rate Fundamentals, (Arlington, VA, 1987)
19
Classification-Examples (9)
 Generation Plant

Is generation plant entirely related to providing
capacity?
 Gas mains or electric distribution

Are these costs solely demand-related or is there
also a customer cost component (or are they solely
customer-related)?
20
The Logic of Classification: Gas
Distribution Mains (10)
 What are gas distribution mains used for?
 Meeting peak demand?
– Historic and future planning parameters
– Mains are sized to meet the highest peak demand on
the peak day

Meeting average demand?
– What evidence exists concerning the reason for
investment (e.g., maintenance and replacement of
existing mains)

Hooking up customers?
– How does investment cost change with number of
customers?
21
Classification Example: Gas Mains
(11)
 Zero-intercept method

Statistical procedure that relates main costs
and size with number of customers
 Minimum distribution system

Engineering method that determines the cost
of a system of a certain size and allocates
classifies those costs as customer related
22
Zero-intercept method (12)
 Some level of main costs are required to serve
new customers
 This level can be deduced from regressing unit
costs of various size of mains on the sizes of
mains
 This suggests a level of main costs that is
necessary just to expand system (i.e., just to
hook up customers some level of main
investment is needed)
23
Zero-intercept method (13)
Avg Cost
Cost of a size 0
main
Size of
Main
24
Scatter plot-Cost of Steel Mains (14)
Steel Mains
$50.00
$45.00
$40.00
$35.00
Avg Cost
$30.00
$25.00
$20.00
$15.00
$10.00
$5.00
$0
2
4
6
8
10
12
14
Size (inches)
25
Regression Results (Steel Mains)
(15)
Regression Statistics
Multiple R
0.9151026
R Square
0.8374127
Adjusted R
Square
0.8193474
Standard Error
6.0907642
Observations
11
ANOVA
df
Regression
Residual
Total
1
9
10
Intercept
X Variable
SS
1719.6458
333.87668
2053.5225
Coefficients
1.90232947
3.32414392
MS
1719.6458
37.0974091
Standard
Error
2.863498645
0.488238595
F
46.3548759
t Stat
0.66433748
6.80844152
P-value
0.5231286
7.831E-05
Significance
F
7.8306E-05
26
Minimum Distribution Method (16)
 Applies actual engineering costs of a minimum
size system to determine what costs are related
to customers
 Question becomes what is the appropriate size
of main to use to estimate the minimum size?
27
MDS-Example (17)
Size
2" or less
3" and 4"
6" and 8 "
Feet
2,543,218
972,435
84,480
Total Cost
+ $ 6,413,228
$ 4,755,842
$
619,326
$
$
$
Avg Cost
2.52
4.89
7.33
Total
3,600,133
11,788,396
$
3.27
Total >2
@ 2" price
Difference
1,056,915
1,056,915
5,375,168
2,665,221
2,709,947
$
$
$
5.09
2.52
2.56
+
=
$
$
$
$9,078,448
Total Cost of 2” MDS
 The difference between the 2” main costs and the above 2”
main costs is the demand related costs (i.e. the costs in
excess of a minimum distribution system)
 77% (9m/11m) are customer-related, the remaining costs
(23%) are demand related
28
Allocation to customer classes of
Demand-Related Costs (18)
 Peak responsibility methods

Allocates capacity based on peak hour or some
average of the peak hours

Customers who consume off-peak will not be
allocated these costs
 Peak and average methods

Uses average and peak volumes weighted by the
load factor

Recognizes that some investment is for not peak
day needs
29
Demand Allocation (19)
30
Demand Allocation: Recognizing
Energy (20)
 If part of the production plant is classified as
energy-related (e.g., 25%), then energy portion
would be allocated based on an energy
allocator.
 If portions of capacity are not re-classified as
energy, the energy function may still be
recognized through the allocation process.
31
Average and Excess (21)
Average demand is Energy/8760
Load factor is Average demand/ CP
32
Institute for
Regulatory Policy
Studies, Illinois
State University
Marginal Cost
(35 Slides)
Introduction to Marginal Cost
Pricing (1)
 Overview of micro-economics




Cost curves
Revenue curves
Profit maximization
Why marginal costs?
 Application of marginal cost to the electric industry?

Marginal Generation Costs
Marginal Distribution Costs

Marginal Transmission Costs

34
Overview of Microeconomics (2)
 Total Cost is defined as follows:
 Total Cost = Fixed Costs of Production
+ Variable Cost of Production
 Fixed Costs are those costs that do not change
with changes in output
 Variable Costs are those costs that do change
with changes in output
35
Total Costs in the Electric Sector (3)
 The total cost of the production of electricity is related
to the capital costs of the delivery and production
system and the costs of operating and maintaining the
system.
 Sunk Costs are those costs that cannot be avoided
and could not be recovered if the firm exits the
business. For example, a power plant that is built for
serving a particular load center may have little value
outside of providing service to those customers.
36
Total Cost (4)
Cost(q) = Fixed Costs + Variable Cost(q)
 The Total Cost Function can be re-written as a
function of quantity, where q is the quantity of
goods produced C
Graphically, total cost
looks like this:
F
q
37
Average Cost (5)
 Average Total Cost is the is the average cost of
production at any point in the production functions. It
is defined mathematically as follows:
Cost/q
= Average Total Cost
= Fixed Costs/q +Variable Costs/q
=Average Fixed Costs + Average Variable
Costs
Where Average Fixed Costs = Fixed Costs/q
Average Variable Costs = Variable Costs/q
38
Average Cost-Graphically (6)
Economies of scale
C
O
S
T
Decreasing Average Cost
Diseconomies of scale
F
Minimum Efficient Scale
Increasing Average Cost
qmin
quantity
39
Marginal Cost (7)
 Marginal Cost is change in the total cost as a
result of the change in the output.
Mathematically, it is defined as follows:
dC(q)/dq = C’(q) = Marginal Costs
40
Total Revenue (8)
 Total Revenue is defined as the total revenues
received for the production and sales a specific
quantity of a commodity. Mathematically it is
defined as follows:
R(q) =
Where:
P(q) * q
q is the level of output
p is the price
Marginal revenue is the change in revenue as
output changes
41
Profit Maximization (9)
 Running assumption is that firms select
quantities to maximize profits.
 Profit is defined as the difference between
Revenues and Total Cost and is defined
mathematically below:
Profit = R(q) - C(q)
 Mathematically, this function is maximized
when R’(q) = C’(q)
42
Graphically, what does this say?
(10)
Marginal Revenue at q*
Total Cost
Cost
Total Revenue
Maximum Difference Between
Revenue and Cost
Marginal Cost at q*
q*
Quantity
43
Economically, what does this say?
(11)
Cost
MC < MR
MC > MR
Marginal
Cost
Marginal
Revenue
q1
q*
q2
Quantity
44
Why use marginal cost? (12)
 Competitive markets price based on marginal
cost

Efficiency in production

Efficiency in consumption

Maximizes social welfare
 More accurately follows utility planning and
investment decisions
 Creates a level playing field for unbundling
45
Competitive Firm (13)
Price/
Cost
MC
ATC
P=MR=D=MC
Economic Profit =0, i.e., TR=TC
Price is set at marginal cost
Maximize Social Welfare
q*
Quantity
46
Social Welfare Maximization (Under
Competition) (14)
Supply
Price/
Cost
Consumer Surplus
P*
Producer Surplus
Demand
Q*
Quantity
47
Monopoly Output (15)
Price/
Cost
Marginal Cost
Economic Profit >0, i.e., TR>TC
Price > Marginal Cost
Output is reduced relative to
competitive output
ATC
PM
Economic
Profit
Total
Revenue
Total Cost
Marginal Revenue
QM
Demand
Quantity
48
Social Welfare Under Monopoly (16)
Consumer Surplus
Transferred to
Producer
Price/
Cost
Supply
PM
Lost Consumer
Surplus
P*
Lost Producer
Surplus
(gained back
from transfer)
Demand
QM
Q*
Quantity
49
Use of Marginal Cost in Price
Setting (17)
 Short-run marginal cost would not include
capital
 Utilities are capital intensive
 How to solve dilemma?

Use of long-run marginal costs for rate making
– Long-run simply means that all inputs are variable and
therefore the fixed costs of capital are variable

Translate capital investment into annual cost using
the carrying charge or fixed rate charge calculation.
50
Carrying Charge Rate Calculation
(18)
Fixed Charge Rate = NPV Revenue Requirements /
Annuity Factor
Where
 NPV Revenue Requirements is the Net Present Value
of the revenue requirements over the life of the
investment
and
 The Annuity Factor is the sum of each year’s discount
rate factor over the life of the investment
51
Carrying Charge Rate Calculation
(19)
Revenue Requirements =  (Plant in Service –
Accumulated Depreciation) * WACC
+ Income Taxes
+ Property Taxes
52
Example (20)
53
Example (21)
54
n
1
DRR

(1  r)
i 1
n
Example (22)
1
(1  r) n
ARR*DF
n
 DRR
i 1
n
 DF
Discount Factor * Inflation
TDRR / RLF
i 1
n
 NLDR
i 1
TDRR/NLF
55
Chart on CCR (23)
56
Functional Marginal Costs (24)
 Marginal cost categories are further estimated by the
cost causality of each function

Generation has a capacity and energy component

Transmission has at a minimum a capacity
component

Distribution has a capacity and customer
component
57
Marginal Generation Capacity Costs
(25)
 Marginal Generation Capacity Cost is the
LRMC of adding new generation to the system
regardless of the price of energy from that
resource.

From a system planning point of view a resource
with lower energy costs (e.g., a coal plant or a
hydro unit) will only be constructed if the increased
value of the energy output outweighs the additional
capital and fixed O&M costs over the expected life
of the unit
58
Marginal Generation Costs-Capacity
(26)
 Definition: Marginal Generation Capacity Cost is the
lowest cost alternative to provide capacity in the longrun regardless of energy price.
 “Peaker Methodology”
 What is the levelized cost of a simple-cycle (open-
cycle) combustion turbine over its life?
 The Carrying Charge Rate (CCR) calculation is then
performed in order to convert the one-time installed
cost and fixed O&M of the marginal generation
capacity technology to an annual value
59
Marginal Generation Costs-Energy
(27)
 Definition: Marginal Energy Cost is the cost to provide
an additional increment of energy
 Methods to estimate Marginal Energy Costs include the
following:

Simulation: A model is used to predict the dispatch in the
region of all loads, transmission interconnections and
generation resources.

Historical Data: Dispatch records of the region are analyzed
in order to determine the highest cost resource in every hour
for an historical period of time (e.g., a year).
Market Data: Market data from a reliable source is analyzed
for an historical period of time. Future time periods
(“Forward Curves”) are generally not appropriate because
these include risk premiums

60
Marginal Generation Costs-Energy
(28)
 Since it is common for Marginal Energy Costs to vary
significantly from hour to hour, typically groups of
similar hours are combined in order to capture major
differences in costs. These time periods are called
“Costing Periods.”

Examples of costing periods are Summer and Non-Summer
and On-Peak versus Off-Peak Costs.
 When estimating Marginal Energy costs the effects of
the wholesale markets and opportunity costs from lost
transactions are taken into account.
61
Marginal Transmission CostsCapacity (29)
 Definition: The incremental cost to provide
transmission service ignoring other transmission
infrastructure investments such as generator
interconnections
 In determining marginal transmission costs, only a
capacity component exists.

Other components may be added in the future to capture
ancillary services pricing.
 Transmission assets are constructed for a number of
reasons for example:



Load Growth
Generation Interconnection
Replacement of Existing Infrastructure.
62
Marginal Transmission CostsCapacity (30)
 Transmission investments are often made infrequently
and therefore require an analysis of an extended
period of time (e.g., 5-10-15 years) in order to properly
estimate marginal costs.
 A common way of identifying marginal transmission
investments is to analyze the transmission investment
budget and determine what investments are related to
load growth.
 Next, each investment must be restated in a constant
year value matching the test year period (e.g. 2005).
63
Marginal Transmission CostsCapacity (31)
 The marginal transmission capacity costs are
then calculated to determine the relationship
between load growth for the period of the
investments and the total load-related
investments.
 Methods commonly used in order to determine
this relationship include:

Simple arithmetic averages

Regression analysis
64
Marginal Distribution Costs-Capacity
(31)
 Definition: What is the marginal cost to provide distribution
service to meet incremental demand (not customer issues).

What is the incremental capital cost of serving these customers?
–
Minimum System Study

Using a hypothetical distribution circuit based upon incremental levels of load,
the change in costs are estimated for each load level thus providing the
relationship between investment and load. Regression analysis or simple
arithmetic means are calculated to determine the slope (marginal costs).

The problem with the minimum system approach is that it might be too
labor intensive.

An alternative is to perform a replacement cost analysis of the system
and then to apply depreciation rates. This will provide an average
depreciated cost of the distribution system.
–
Marginal Investments (analogous to transmission)
65
Marginal Distribution Costs-Capacity
(32)


Determine levelized cost of investments
Costs will differ by voltage level based
 Costs that would be included in Distribution
Capacity Costs would include:
•
Demand-related (distribution substations and
trunkline feeders) - like transmission, but possibly
computed by district
•
Local facilities (primary, transformers and
secondary) - annualized investment per kW of
design demand
66
Marginal Distribution CostsCustomer (33)
 Marginal Customer Costs are the minimum costs
incurred by the utility to hook-up the customer to the
distribution system but deliver only minimal service.
This is sometimes called the The Minimum
Distribution System Methodology.
 These costs would be the annualized costs of the
meter, the service-drop, monthly meter reading and
billing expenses.
 These cost estimates would have to be prepared for
all voltage levels serving the customer.
67
Marginal Cost and Tariff Elements
(35)
Non-Demand Metered Classes
Marginal Cost Elements
Tariff Elements
Marginal Customer Cost
Customer Charge per Customer
per month
Marginal Distribution Substation and
Transmission Costs
Seasonal Energy Charge per kWh
Marginal Energy and Generation Capacity
Cost
Facilities Charge per kW
of Design Demand
Marginal Distribution Facilities Cost
(secondary, transformer, primary)
Access Charge
Based on Historic Usage
Revenue Gap
Demand Metered and TOU-Metered Classes
Marginal Cost Elements
Tariff Elements
Marginal Customer Cost
Customer Charge per Customer
per month
Marginal Distribution Substation and
Transmission Costs
Demand Charge per kW of
Metered Demand
Marginal Energy and Generation Capacity
Cost
Time-Differentiated Energy Charges
Marginal Distribution Facilities Cost
(secondary, transformer, primary)
Facilities Charge per kW
of Design Demand
Access Charge
Based on Historic Usage
Revenue Gap
68
Institute for
Regulatory Policy
Studies, Illinois
State University
Allocation of Revenue
Requirement
(4 Slides)
Allocation of the Revenue
Requirement Using Marginal Cost
Revenue Analysis (1)

The results of the components of the marginal cost study can be used to
allocate the revenue requirement to various tariff classes. This is called the
Marginal Cost Revenue Study.

The results of each marginal cost analysis is multiplied by the billing
determinant that applies to that cost. For Example:




Coincident Demand is applied to Marginal Generation Capacity and Marginal
Transmission Capacity Cost.
Energy at generation level is multiplied by marginal energy cost.
Noncoincident demand is multiplied by Marginal Distribution Capacity Costs.
The number of customer-months is multiplied by the Marginal Customer Costs
for each voltage level.

The product of each marginal cost component and the billing determinant
will not equal the revenue requirement (unlike the allocated cost of service
analysis).

In order to determine the portion of the revenue requirement associated with
each tariff class a ratio must be calculated between the revenue requirement
and marginal costs.
70
Allocation of the Revenue
Requirement Using Marginal Cost
Revenue Analysis (2)
 Equal Percentage of Marginal Costs: The ratio
of the total revenue requirement and the sum of
marginal cost revenues is calculated and
applied to each tariff class. By definition the
sum of each tariff’s marginal cost responsibility
will equal the revenue requirement.
71
Allocation of the Revenue
Requirement Using Marginal Cost
Revenue Analysis (3)
The Product of
Marginal
Costs and
Billing
Determinants
12,000
Ratio of
Marginal
Costs to
Revenues at
Present Rates
83%
Distribution of
Revenues
Based Upon
Marginal
Costs
41%
Revenue
Allocation
Based upon
Equal
Percentage of
Marginal
Costs
12,203
Tariff 1
Revenues
at Present
Rates
10,000
Tariff 2
15,000
14,500
103%
49%
14,746
-2%
Tariff 3
5,000
3,000
167%
10%
3,051
-39%
30,000
29,500
102%
100%
30,000
0%
Total
Percent
Increase /
(Decrease)
22%
72
Using Marginal Cost to Set Rates (4)
Identify
Ratemaking
Objectives
Present
Rates
Determine
Revenue
Requirements
Elasticity
Data
or
or
Yes
Calculate
Marginal
Revenue
Determine
Marginal
Costs
Define
Rate
Classes
Compare
MR to Rev.
Requirements
Identify
Revenue
Constraints
Adjust
Choose Revenue
Reconciliation
Method
Design
Rates
Evaluate
Alternative
Rate Designs
Check
Customer
Impacts &
Reactions
Equity
Considerations
No
Adjust
Rates, Elasticities
or Rev.
Req.
FINAL
RATES
Special
Rates &
Contracts
Develop
Billing
Determinants
73
Institute for
Regulatory Policy
Studies, Illinois
State University
Setting Prices
(26 Slides)
What is the Question? (1)
Price/
Cost
Revenues at P1
Revenues at MC
Losses at MC
P1
Average Cost
PAC
PMC
Marginal Cost
Revenue at MC
Q1
Demand
QAC
QMC - Q1
Quantity
75
Types of Utility Tariffs (2)
 Flat Watthour Tariffs.
 Declining Watthour Tariffs.
 Inverted Black Watthour Tariffs.
 Hopkinson (Two-part) Tariffs.
 Wright Tariffs (Load Factor Blocks).
 Time of Use.
76
Flat Watthour Tariffs (3)
 The Flat Watthour Tariff contains a energy
charge that is unchanged with volume and a
customer charge.

All components of electric supply (with the
exception of the customer charge) are recovered
through a watthour charge.

Implicit in this rate design is the assumption that the
tariff class contains customers with relatively small
variation in load factor, time of use and other
important cost attributes.
77
0
80
10
0
12
0
14
0
16
0
18
0
20
0
22
0
24
0
26
0
28
0
30
0
32
0
34
0
36
0
38
0
40
0
42
0
44
0
46
0
48
0
50
0
52
0
54
0
56
0
58
0
60
0
60
40
20
Total Bill
Graph of Sample Watthour Rate
Charges (4)
70
60
50
40
30
20
10
0
KWH
78
Advantages and Disadvantages of
Watthour Tariffs (5)
 Advantages

Easy to bill.

Easy for customers to understand.

Requires simple metering technology.
 Disadvantages

Fails to capture differences in demand.

Fails to capture difference in time-of-use.

Requires that customers must be homogeneous.
79
Declining Watthour Tariffs (6)
 The Declining Watthour Tariff has two blocks
with the a reduced watthour charge for the
second block.
 These tariffs are employed when the marginal
cost to serve a customer is less than the
average revenue requirement of the tariff.
80
80
10
0
12
0
14
0
16
0
18
0
20
0
22
0
24
0
26
0
28
0
30
0
32
0
34
0
36
0
38
0
40
0
42
0
44
0
46
0
48
0
50
0
52
0
54
0
56
0
58
0
60
0
60
40
20
0
Total Bill
Graph of Declining Block Tariff (7)
60
50
40
30
20
10
0
KWH
81
Advantages and Disadvantages of
Declining Block Rates (8)
 Advantages
 Simple for the utility to bill.
 Simple for the utility to meter.
 Fairly simple for customers to understand.
 Appropriate when the average revenue requirement
exceeds the marginal cost to supply customers.
 Disadvantages
 Fails to capture differences in demand.
 Fails to capture difference in time-of-use.
 Requires that customers must be homogeneous.
 Not appropriate unless average revenue requirement is less
than marginal costs.
 Can shift costs to smaller users.
82
Increasing Block Watthour Tariffs
(9)
 The Increasing Block Tariff is the opposite of
the Declining Block Tariff – the last block of
usage is billed at a higher charge.
 This type of rate design is appropriate when the
average revenue requirement is less than the
marginal cost to serve customers.
83
60
0
58
0
56
0
54
0
52
0
50
0
48
0
46
0
44
0
42
0
40
0
38
0
36
0
34
0
32
0
30
0
28
0
26
0
24
0
22
0
20
0
18
0
16
0
14
0
12
0
10
0
80
60
40
20
0
Total Bill
Graph of Increasing Block Tariff (10)
80
70
60
50
40
30
20
10
0
KWH
84
Increasing Block Tariffs –
Advantages and Disadvantages (11)
 Advantages
 Simple for the utility to bill.
 Simple for the utility to meter.
 Fairly simple for customers to understand.
 Appropriate when the average revenue requirement is less
than the marginal cost to supply customers
 Disadvantages
 Fails to capture differences in demand.
 Fails to capture difference in time-of-use.
 Requires that customers must be homogeneous.
 Not appropriate unless average revenue requirement is
greater than marginal costs.
 Can shift costs to larger users.
85
Hopkinson (Two-part) Tariff (12)
 The Hopkinson Two-Part Tariff contains explicit
charges for energy and capacity (a Demand
Charge)

Variants on this design may split the demand
charge into a generation, transmission and
distribution component).
 Components of cost that do not vary with
electric power usage but rather electric demand
usage is captured in the demand charge or
charges.
86
10
,0
0
20 0
,0
0
30 0
,0
0
40 0
,0
0
50 0
,0
0
60 0
,0
0
70 0
,0
0
80 0
,0
0
90 0
,0
10 00
0,
0
11 00
0,
0
12 00
0,
0
13 00
0,
0
14 00
0,
0
15 00
0,
0
16 00
0,
0
17 00
0,
0
18 00
0,
0
19 00
0,
0
20 00
0,
0
21 00
0,
0
22 00
0,
0
23 00
0,
0
24 00
0,
0
25 00
0,
0
26 00
0,
0
27 00
0,
0
28 00
0,
0
29 00
0,
0
30 00
0,
0
31 00
0,
00
0
Total Bill
Graph of Hopkinson Tariff (13)
20,000
18,000
16,000
14,000
12,000
10,000
70% Load Factor
8,000
4,000
50% Load Factor
6,000
30% Load FActor
2,000
-
KWH
87
Advantages and Disadvantages of
Hopkinson Tariffs (14)
 Advantages



Captures the differences in load factor form customer to
customer.
Is generally understood by larger customers.
Provides explicit price signal to customers for both energy
and capacity.
 Disadvantages


Requires more costly meters. The metering investment
must be balanced with the benefits of implementing the
tariff.
Requires more effort to bill.
88
Demand Charge Ratchet
Mechanisms (15)
 Demand Charge Ratchets are implemented on
Hopkinson Tariffs for cost components which
are established by the customer’s highest
demand in a series of billing periods (e.g., each
year).
 Distribution charges often are good candidates
for a demand ratchet.

The cost of the radial portion of the distribution
system is established by the highest demand for an
annual period even if the customer does not use
that demand each month.
89
Advantages and Disadvantages of
Demand Ratchets (16)
 Advantages

Provides the customers with a better price signal
regarding component costs.

Provides an additional mechanism for the
unbundling of tariffs.
 Disadvantages.

More difficult for the customer to understand.

More difficult to bill.
90
Time of Use Tariffs (17)
 The Time of Use tariff differentiates between
the cost of the energy charge component of the
tariff between high costs and lower cost period.
 Time of Use tariffs can either be watthour tariffs
or Hopkinson tariffs.
91
Advantages and Disadvantages of
Time of Use Tariffs (18)
 Advantages.

Provides a better price signal to the customer.

Moves the tariff to better matching of costs and
revenues.
 Disadvantages.

Requires more costly metering equipment.

If more difficult to understand.
92
Cost Study Results – Scenario 1 CP

93
Cost Study Results – Scenario 1 CP
S.C.1
S.C.2
S.C.3
S.C.4
Total
94
Cost Study Results – Scenario 1 CP
95
Cost Study Results – Scenario 1 CP
96
Cost Study Results – Scenario 2
AENCP
97
Cost Study Results – Scenario 2
AENCP
S.C.1
S.C.2
S.C.3
S.C.4
Total
98
Cost Study Results – Scenario 2
AENCP
99
Cost Study Results – Scenario 2
AENCP
100