Institute for Regulatory Policy Studies, Illinois State University Cost of Service and Rate Design Workshop Sherman Elliott Manager, State Regulatory Affairs,

Institute for Regulatory Policy Studies, Illinois State University

Cost of Service and Rate Design WorkshopSherman ElliottManager, State Regulatory Affairs, Midwest ISO, Inc.

July 14-15, 2005 Midwest Independent Transmission System Operator, Inc.701 City Center DriveCarmel, Indiana 46032217.522.6674217.522.6676 (f)[email protected]

mailto:[email protected]

2

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

3

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


Introduction to Ratemaking

(6 Slides)

5

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

6

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.

7

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

8

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

9

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.

10

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


Cost of Service

(21 Slides)

12

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)

13

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

14

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)

15

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.).

16

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.)

17

Functionalization-Example Electric Utility (6)

Plant in Service Accounts Expense Accounts

18

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.

19

Classification of Costs-Examples-Gas (8)

Function Demand Commodity Customer Revenue Production & Gas Supply

Gas Supply Capacity VolumeStorage Capacity VolumeLNG Capacity VolumePropane Capacity Volume

TransmissionCompressor Stations Capacity VolumeMains Capacity VolumeRegulatory Stations Capacity Volume Specific Assignment

DistributionCompressor Stations CapacityMains Capacity No. CustomersM&R Stations Capacity No. CustomersServices Capacity No. CustomersMeters No. CustomersHouse Reg No. CustomersImd M&R Stations Specific AssignmentCustomer Installations Specific Assignment

OtherCustomer Accounts No. CustomersSales Expense No. Customers

RevenueRevenue from Sales RevenueRevenue Taxes Revenue

Source: Adapted from American Gas Association, Gas Rate Fundamentals, (Arlington, VA, 1987)

Classification with Allocation Methods

20

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)?

21

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?

22

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

23

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)

24

Zero-intercept method (13)

Size of Main

Avg Cost

Cost of a size 0 main

25

Scatter plot-Cost of Steel Mains (14)

$-

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

$45.00

$50.00

0 2 4 6 8 10 12 14

Size (inches)

Avg

Co

st

26

Regression Results (Steel Mains) (15)

Regression Statistics Coefficients Standard

Error t Stat P-value Multiple R 0.9151026 Intercept 1.90232947 2.863498645 0.66433748 0.5231286 R Square 0.8374127 X Variable 3.32414392 0.488238595 6.80844152 7.831E-05 Adjusted R Square 0.8193474 Standard Error 6.0907642 Observations 11

ANOVA

df SS MS F Significance

F Regression 1 1719.6458 1719.6458 46.3548759 7.8306E-05 Residual 9 333.87668 37.0974091 Total 10 2053.5225

27

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?

28

MDS-Example (17)

Size Feet Total Cost Avg Cost 2" or less 2,543,218 $ 6,413,228 $ 2.52 3" and 4" 972,435 $ 4,755,842 $ 4.89 6" and 8 " 84,480 $ 619,326 $ 7.33 Total 3,600,133 11,788,396 $ 3.27 Total >2 1,056,915 $ 5,375,168 $ 5.09 @ 2" price 1,056,915 $ 2,665,221 $ 2.52 Difference $ 2,709,947 $ 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

29

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

30

Demand Allocation (19)

31

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.

32

Average and Excess (21)

Average demand is Energy/8760Load factor is Average demand/ CP


Marginal Cost

(35 Slides)

34

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

35

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

36

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.

37

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

q

F

Graphically, total cost looks like this:

38

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

39

Average Cost-Graphically (6)

Economies of scale

quantity

COST

F

qmin

Decreasing Average Cost

Increasing Average Cost

Diseconomies of scale

Minimum Efficient Scale

40

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

41

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) = P(q) * q

Where: q is the level of output

p is the price

Marginal revenue is the change in revenue as output changes

42

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)

43

Graphically, what does this say? (10)

Cost

Quantity

Total Cost

q*

Marginal Cost at q*

Marginal Revenue at q*

Total Revenue

Maximum Difference Between Revenue and Cost

44

Economically, what does this say? (11)

Cost

Quantity

Marginal Cost

Marginal Revenue

q1 q2q*

MC < MR MC > MR

45

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

46

Competitive Firm (13)

Price/ Cost

Quantity

ATC

P=MR=D=MC

MC

q*

Economic Profit =0, i.e., TR=TC

Price is set at marginal cost

Maximize Social Welfare

47

Social Welfare Maximization (Under Competition) (14)

Price/ Cost

Quantity

Demand

Supply

P*

Consumer Surplus

Producer Surplus

Q*

48

QM

PM

Economic Profit

Monopoly Output (15)

Price/ Cost

Quantity

DemandMarginal Revenue

Marginal Cost Economic Profit >0, i.e., TR>TC

ATC

Price > Marginal Cost

Output is reduced relative to competitive output

Total Revenue

Total Cost

49

QM

PM

Social Welfare Under Monopoly (16)

Price/ Cost

Quantity

Demand

Supply

P*

Consumer Surplus Transferred to

Producer

Lost Producer Surplus

(gained back from transfer)

Q*

Lost Consumer Surplus

50

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.

51

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

52

Carrying Charge Rate Calculation (19)

Revenue Requirements = (Plant in Service – Accumulated Depreciation) * WACC

+ Income Taxes

+ Property Taxes

53

Example (20)

54

Example (21)

55

Example (22)nr)1(

1

nr)1(

1

ARR*DF

n

i

DRR1

n

i

DRR1

n

i

DF1Discount Factor * Inflation

n

i

NLDR1

TDRR / RLF

TDRR/NLF

56

Chart on CCR (23)

57

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

58

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

59

Marginal Generation Costs-Capacity (26)

Definition: Marginal Generation Capacity Cost is the lowest cost alternative to provide capacity in the long-run 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

60

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

61

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.

62

Marginal Transmission Costs-Capacity (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.

63


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).

64


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

65

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)

66

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

67

Marginal Distribution Costs-Customer (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.

68

Marginal Cost and Tariff Elements (35)

Tariff Elements

Marginal Customer Cost

Marginal Distribution Substation and Transmission Costs

Marginal Energy and Generation Capacity Cost

Marginal Distribution Facilities Cost (secondary, transformer, primary)

Customer Charge per Customerper month

Seasonal Energy Charge per kWh

Revenue Gap

Marginal Customer Cost

Marginal Distribution Substation and Transmission Costs

Marginal Energy and Generation Capacity Cost

Marginal Distribution Facilities Cost (secondary, transformer, primary)

Tariff Elements

Customer Charge per Customerper month

Demand Charge per kW of Metered Demand

Time-Differentiated Energy Charges

Access ChargeBased on Historic Usage

Facilities Charge per kW of Design Demand

Revenue GapAccess Charge

Based on Historic Usage

Facilities Charge per kW of Design Demand

Marginal Cost Elements

Demand Metered and TOU-Metered Classes

Marginal Cost Elements

Non-Demand Metered Classes


Allocation of Revenue Requirement

(4 Slides)

70

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.

71


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.

72


Revenues at Present

Rates

The Product of Marginal

Costs and Billing

Determinants

Ratio of Marginal Costs to

Revenues at Present Rates

Distribution of Revenues

Based Upon Marginal

Costs

Revenue Allocation

Based upon Equal

Percentage of Marginal Costs

Percent Increase / (Decrease)

Tariff 1 10,000 12,000 83% 41% 12,203 22%

Tariff 2 15,000 14,500 103% 49% 14,746 -2%

Tariff 3 5,000 3,000 167% 10% 3,051 -39%

Total 30,000 29,500 102% 100% 30,000 0%

73

Using Marginal Cost to Set Rates (4)

DevelopBilling

Determinants

DefineRate

Classes

DetermineMarginal

Costs

IdentifyRatemakingObjectives

CalculateMarginalRevenue

EquityConsiderations

AdjustRates, Elasticities

or Rev.Req.

IdentifyRevenue

Constraints

EvaluateAlternative

Rate Designs

CompareMR to Rev.

Requirements

PresentRates

Choose Revenue Reconciliation

Method

Check Customer Impacts & Reactions

DetermineRevenue

Requirements

FINALRATES

SpecialRates &

Contracts

ElasticityData

or

or

Yes

DesignRates

NoAdjust


Setting Prices

(26 Slides)

75

What is the Question? (1)

Price/ Cost

Quantity

Marginal Cost

Demand

Average Cost

QMC

PMC

Revenue at MC

QAC

PAC

Losses at MC

P1

Q1 - Q1

Revenues at P1

Revenues at MC

76

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.

77

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.

78

Graph of Sample Watthour Rate Charges (4)

0

10

20

30

40

50

60

70

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520

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KWH

Tot

al B

ill

79

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.

80

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.

81

Graph of Declining Block Tariff (7)

0

10

20

30

40

50

60

0 20 40 60 80 100

120

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KWH

Tot

al B

ill

82

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.

83

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.

84

Graph of Increasing Block Tariff (10)

0

10

20

30

40

50

60

70

80

0 20 40 60 80 100

120

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KWH

Tot

al B

ill

85

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.

86

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.

87

Graph of Hopkinson Tariff (13)

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

10,0

00

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00

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00

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00

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00

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00

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000

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000

310,

000

KWH

Tot

al B

ill 70% Load Factor

50% Load Factor

30% Load FActor

88

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.

89

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.

90

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.

91

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.

92

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.

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Cost Study Results – Scenario 1 CP

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S.C.1 S.C.2 S.C.3 S.C.4 Total

95


96


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Cost Study Results – Scenario 2 AENCP

98


S.C.1 S.C.2 S.C.3 S.C.4 Total

99


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Institute for Regulatory Policy Studies, Illinois State University Cost of Service and Rate Design Workshop Sherman Elliott Manager, State Regulatory Affairs,

Documents

cost causation slide

rate base vd

rate base oss

rate cases

results of cost studies

rate of return v

slides slide

net original cost