Issues in Cost Allocation Introduction to Efficient...

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♦ Issues in Cost Allocation ♦ Introduction to Efficient

Pricing ♦ Rate Design by Objective

Presented By: Philip Q Hanser

Principal, The Brattle Group

Presented To: EEI Advanced Rates School

University of Wisconsin, Madison

July 25, 2011

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Issues in Cost

Allocation

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Determination of Revenue Requirements/ Overall Cost of Service

Assign costs to Customer/Rate Classes Within a Jurisdiction

Design Cost-Based Rate Elements for Each

Rate Classes’ Tariff

Components of Cost of Service Study

Functionalize Costs Classify Cost

Jurisdictional Separations

Allocation of Revenue Requirements

Across the Jurisdictions in which the

Company Operates

Basic Steps in Rate Making Process

Source: Blank & Gegax

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♦ An analytical approach to the apportionment of the total cost of service (Revenue Requirement)

♦ Supports the process of determining and allocating the cost of providing utility service to each customer rate class and provides a framework for recovering costs through proper rate design

♦ The costs of the utility must be studied by the cost analyst using inputs from various areas of utility operations (e.g., accounting records, engineering analyses, customer billing records, demand forecasts, cost simulation models)

Cost of Service Study

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Types of Cost of Service Studies

♦ The vast majority of jurisdictions use Embedded (i.e., based on actual book data and actual class load characteristics) COS for cost allocation

♦ Marginal COS is used for the development of time-of-use pricing and, in a small minority of jurisdictions, for actual cost allocation

♦ Not an exact science – reasonable people can disagree

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Step 1: Functionalize Step 2: Classify Key Question to be asked at every step in the process: ♦ What caused the costs to be incurred?

(cost causation)

Steps in an Embedded Cost of Service Study

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‘Bulk’ Transmission lines 138-345 kV (ultra-high voltage lines go up to 500 – 765 kV)

Network switchyard

transmission subs (step-down transformers)

Sub-Transmission 69-115 kV lines

distribution substations (step-down transformers) 3-phase primary distribution feeder lines (21 – 36 kV)

Generation (6-14 kV)

step-up transformers

Drop lines to homes 120-240 volts

Demand-Energy

Demand

Demand-Customer Customer

Common Facilities (used by all customers); sized based on system demands -- CP, Average Demand, Average-Excess Demand

Facilities not used by all customers; Sized based on subset of system demands -- NCP

1-phase secondary distribution lateral lines (7-13 kV)

Functionalize and Classify

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♦ Functionalization is the process of dividing the total revenue requirement into functional components as related to the operations of the utility (operating functions) Generation (aka Production) Transmission Distribution Meters and Services General Plant (eventually must be apportioned to the other non-

general functions)

♦ Usually, the rate-base component of revenue requirements is functionalized first; then the expense components are functionalized

Step 1: Functionalization

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Functionalize Rate Base Directly assign, where possible (good examples are the original cost

and accumulated depreciated – facility by facility – for non-general plant in service)

General Plant is problematic – is re-functionalized into other non-general-plant components (with use of functionalization factors – usually some direct labor proportion of O&M)

The argument is that general plant supports indirect labor and that indirect labor supports direct labor

Once rate base is functionalized (with general plant re-functionalized into the non-general plant categories), it is easier to functionalize return dollars on rate base as well as income taxes


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♦ Direct Labor (“Field Crew”) Employees or workers who are directly involved in the production of goods

or services. Direct labor costs are directly assignable to a specific product, cost

center, work order, or provision of service. Direct labor usually keeps track of their time in work orders or time

logs For a utility, direct labor can be directly assigned to an operating

function and direct labor costs are part of O&M

♦ Indirect Labor (“Office Workers”) Support labor that cannot be directly assigned to a specific product, cost

center, work order or provision of service Indirect labor usually does not keep track of their time in work orders

or time logs For a utility, indirect labor cannot be directly assigned to an operating

function and indirect labor costs are part of A&G


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Functionalize Revenue Requirements

Functionalize return dollars on rate base, as well as income taxes, based on how rate base was functionalized

For example, if 50% of rate base is generation related, then 50% of return dollars on rate base is generation related

Directly assign, where possible (good examples are direct O&M expenses, annual depreciation expense, fuel)

A&G is problematic – is re-functionalized into other non-A&G components (with use of functionalization factors; e.g., direct labor proportion of O&M)

For example, if 10% of direct labor (in O&M) is transmission related, then 10% of indirect labor (in A&G) is transmission related


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Electric Functionalization Example ($000)

Efficient Energy Inc.Cost of Service/Revenue Requirements - ($000s)

TOTAL Generation Transmission Distribution General

Operation & Maintenance ExpenseGeneration 576,369 576,369 0 0 0Transmission 15,464 0 15,464 0 0Distribution 47,733 0 0 47,733 0Customer Accounts 37,769 0 0 37,769 0Customer Service & Informational 12,510 0 0 12,510 0Sales 1,846 0 0 1,846 0Administrative & General 123,337 0 0 0 123,337

Total Operation & Maintenance 815,027 576,369 15,464 99,857 123,337Depreciation Expense

Intangible 5,812 0 0 0 5,812Generation 131,353 131,353 0 0 0Transmission 9,125 0 9,125 0 0Distribution 44,591 0 0 44,591 0General 21,667 0 0 0 21,667

Total Depreciation Expense 212,548 131,353 9,125 44,591 27,478Taxes

Taxes Other Than Income 150,640 84,485 9,804 37,514 18,837Income Taxes 120,437 65,400 8,373 30,663 16,001

ReturnDebt Related 124,389 67,546 8,647 31,669 16,526Equity Related 180,667 98,107 12,560 45,997 24,004

Total Return 305,056 165,652 21,207 77,666 40,530Total Cost of Service 1,603,708 1,023,260 63,973 290,291 226,184Rate of Return 9.54% 9.54% 9.54% 9.54% 9.54%Rate Base 3,197,650 1,736,399 222,296 814,112 424,843

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♦ Classification is the process of further separating the functionalized costs by the primary driver for that cost

In other words, this is the process of separating the functionalized costs into classifications based on what the costs are sensitive to

♦ Primary Cost Classification Categories Demand-Related Costs: (aka Capacity-Related Costs) Those costs

that vary with the kW of instantaneous demand (and therefore peak capacity needs)

Energy-Related Costs: Those costs that vary with kWh of energy generated

Customer-Related Costs: Those costs that vary with the number of customers on the system

Step 2: Classification

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Step 2: Classificatin

Examples of Demand-Related Costs Costs of Generation Capacity

Costs of Transmission Lines

Costs of Distribution Lines and Transformers

These costs show up in Rate Base

The resulting costs that show up in Revenue Requirements

• Return dollars on rate base

• Annual depreciation expense

• Operations and Maintenance


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Examples of Customer-Related Costs ♦ Costs of Metering

Return dollars and depreciation expense on meters themselves Labor costs involved in reading the meters

♦ Costs of billing and account processing Return dollars and depreciation expense on needed information

equipment and software as well as customer service buildings Labor costs associated with billing, account processing and

fielding customer complaints

♦ Costs of attaching customers to the system Costs associated service drops and poles as well as some low-

voltage distribution facilities

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Examples of Energy-Related Costs ♦ Fuel ♦ Costs of energy purchases ♦ Generation variable O&M (e.g., lubricants)

NOTE: With respect to the production of energy (kWh), both Demand-Related and Customer-Related costs are viewed as “Fixed Costs” while Energy-Related costs are viewed as “variable costs.”

NOTE: During the functionalization step, the reason general plant in rate base is re-functionalized into the non-general plant components is because general plant does not directly lend itself to being classified as either a demand- , energy- or customer-related cost


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Transmission TOTAL

DemandRelated

EnergyRelated

DemandRelated

DemandRelated

CustomerRelated

REVENUE REQUIREMENTS

OPERATIONS & MAINTENANCE

Generation 254,500 8,497

Transmission 15,464

Distribution Substations,Lines and Transformers 47,733

Meters and Services 52,124

Administrative & General 20,474 25,894 8,499 68,470 123,337

O&M SUBTOTAL 274,974 34,391 23,963 116,203 52,124 501,655

FUEL 313,372 313,372

NET OPERATING INCOME & TAXES& ANNUAL DEPRECIATION 291,583 13,083 31,597 147,363 483,625

TOTAL 566,557 360,845 55,560 263,566 52,124 1,298,652

Generation Distribution

Electric Classification Example - ($000s)

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Basic Steps in Rate Making Process











Company Operates

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Allocation is the process of assigning the functionalized and classified revenue requirements (cost of service) to the different jurisdictions and the different customer rate classes within a jurisdiction. ♦ A rate class is a relatively homogeneous group of customers that

possess similar characteristics and who face the same set of prices (e.g., residential, small power, irrigation, industrial power)

♦ Characteristics include: energy consumed; load characteristics and end use; delivery voltage; metering characteristics; other conditions of service

In order to conduct a class cost-of-service study, the demand characteristics of the total system, as well as individual rate classes, must be analyzed. ♦ Such analysis is referred to as “load research”

Allocation: Class Cost of Service Study

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Load Curve describes the pattern of instantaneous demand through a particular period of time (i.e., through a cycle) ♦ A daily cycle (for a daily load curve) is 24 hours ♦ An average monthly cycle (for a monthly load curve) is 730 hours ♦ An annual cycle (for an annual load curve) is 8,760 hours (or 8784)

Load Curve

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Average Load is derived by taking the total kWh of energy used through the cycle and dividing by the total number of hours through the cycle.

♦ For example, if a customer consumes 7,300 kWh during a month, then that customer’s average load (instantaneous demand) is 10 kW

♦ Average load is analogous to average speed on a trip

Information From Load Curves

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Peak Load is the maximum instantaneous demand (load) during the cycle (measured in kW or MW)

♦ Non-Coincident Peak Load (NCP) is a customer’s (or customer classes’) maximum demand irrespective of when it happens

♦ Coincident Peak Load (CP) is a customer’s (or customer classes) demand at the moment in time that the total system is experiencing its peak load


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0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours

Load

(MW

)

ResidentialSGSLGSMGSTotal System

Peak Day

Total System

Daily Peak

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1-CP ♦ Uses the “system peak” as being the highest single hour’s system

demand during the entire year. Each class’s CP is that class’s demand during that hour the system peak occurred

4-CP ♦ Determines the highest single hour’s system demand during each of

the individual 12 months and then uses the “system peak” as being an average of the four highest of these 12 system demands (the four demands are from four different months’ hours). Each class’s CP is that class’s average demand over those four particular hours

12-CP ♦ Determines the highest single hour’s system demands for each of

the individual 12 months and then takes the “system peak” as being an average of all these 12 system demands (the 12 demands are from 12 different months’ hours). Each class’s CP is that class’s average demand over those 12 particular hours

Alternative CP Measures

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Load Factor (LF) is a measure that captures the degree of variation in a particular pattern of demand ♦ LF is a number between zero and one (i.e., a percentage)

The closer load factor is to 1, the less the variation in the pattern of demand

The closer load factor is to 0, the more the variation in the pattern of demand

♦ LF = (average load) / (peak load)

For example, suppose that a customer uses 7,300 kWh during a month (average load = 10 kW) and that the customer’s NCP during the month is 25 kW.

LF = (average load)/(peak load) = 10/25 = 0.4 (40%)


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System Load Factor

♦ High system load factor translates into high utilization of the capacity built into the system.

♦ High system load factor translates into lower average cost

per kWh. ♦ High system load factor is a result of:

High load factor individual customers or customer class Customer or Rate Class Diversity

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Allocation Allocation is the process of assigning costs to the

different jurisdictions and the different customer rate classes.

Once the various customer class categories have been designated, particular functionalized and classified costs are allocated among the rate classes based on an allocation method which is deemed the most consistent with cost causation

Different cost components require different allocation methods

A particular allocation method (i.e., allocation factor) is a set of percentages that sum to 100%

Demand-Related Allocation Methods Energy-Related Allocation Methods Customer-Related Allocation Methods

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Allocation How should the rent of a two-bedroom house shared by a married couple and a single person be allocated?

♦ What drives rent costs? (i.e., what are the cost drivers?) Married couple argues it’s the number of bedrooms Single person argues it’s the total size of the house and yard required

to accommodate three household members

♦ Cost drivers help in choice of appropriate allocation methods Married couple says use “relative number of bedrooms” method (50% of

rent goes to married couple and 50% of rent goes to single person) Single person says use “relative number of people” method (67% of rent

goes to married couple and 33% of rent goes to single person)

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Allocation ♦ After the Functionalization step is completed, some costs can be

identified as logically incurred to serve only a particular customer (costs of “Dedicated Facilities”) Cost-causation would dictate that these costs are only allocated to that

particular customer

♦ After the Functionalization step is completed, some costs can be identified as not being incurred by particular customers For example, distribution lines are not used to serve customers that

take power at higher voltages (e.g., off the distribution substations) For example, distribution lines and sub-stations are not used to serve

customers that take power at even higher voltages (e.g., off the sub-transmission)

Cost-causation dictates not to allocate the costs of these facilities to the particular customers who do not use these facilities

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Allocation of Revenue Requirement

A particular group of demand-related costs are allocated through the use of one of the demand allocators ♦ The choice of which demand allocator should be used with which

group of demand-related costs, should be based on cost causation

A particular group of energy-related costs are allocated through the use of one of the energy allocators ♦ The choice of which energy allocator should be used with which

group of energy-related costs, should be based on cost causation

A particular group of customer-related costs are allocated through the use of one of the customer allocators ♦ The choice of which customer allocator should be used with which

group of customer-related costs, should be based on cost causation

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Allocation Demand-Related Cost Allocation Methods

System Peak Responsibility (1CP, 4CP, 12CP) – 12CP typically used for the allocation of transmission demand-related costs

Non-Coincident Demand (NCP) – typically used for the allocation of distribution demand-related costs

Average-Excess Demand (AED) – typically used for the allocation of generation demand-related costs

This Method uses a weighted average of the Average-Demand Allocators (weight = system load factor) and the Excess-Demand Allocators (weight = one minus the system load factor)

A Class’s “Excess Demand” is the difference between that class’s NCP and that class’s Average Demand

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0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hours

Load

(MW

)

ResidentialSGSLGSMGSTotal System

Peak Day

Total System

Daily Peak

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MWh

Hours

0 8760 Winter/Spring Spring Summer Fall/Winter

0

500

1,000

1,500

2,000

Average Demand

Excess Demand

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Monthly Peak Loads by Class

0

500

1,000

1,500

2,000

2,500

3,000

3,500

January

Febru

aryMarc

hApril

MayJu

neJu

ly

August

Septem

ber

October

November

Decem

ber

MW

Residential SGS LGS MGS Total System

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Allocation

Energy-Related Cost Allocation Methods kWh of Energy at the customers’ meters – after line and

transformer losses kWh of Energy at the generation plants – before line and

transformer losses Losses are:

■ Due to the transformation of kWh to heat ■ Inversely related to voltage (i.e., higher voltage means lower loss) ■ Directly related to the number of voltage transformations (i.e.,

more voltage transformations from the generator to the customer means more loss)

■ Directly related to distance (i.e., the greater the length of a given circuit, the greater the losses)

■ “Loss factors” will vary by rate class (low-voltage distribution customers – like residential customers – have the highest loss factors)

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Allocation

Customer-Related Cost Allocation Methods ♦ Relative Number of Customers ♦ Relative Weighted Number of Customers -- where weights can be

based on: class-average meter costs class-average billing costs class-average service line costs class-average meter-reading costs

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Allocation Generally, the following criteria should be utilized to

determine the appropriateness of an allocation method: ♦ The method should reflect the actual planning and operating

characteristics of the utility’s system.

♦ The method should reflect cost causation; i.e., should be based on the actual activity that the drives a particular cost and on rate classes’ share of that activity

♦ The method should recognize customer class characteristics such as electric load demands, peak period consumption, number of customers, and directly assignable costs.

♦ The method should produce stable results on a year-to-year basis.

♦ Customers who benefit from the use of the system should also bear some responsibility for the costs of utilizing the system.

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Allocation of Generation Demand-Related Costs

AED is commonly used for allocating generation demand-related costs ♦ There are derivatives of AED – usually based on the “peak” measure

(CP, k-CP, NCP, k-NCP) used in calculating “excess” and based on what MWh values are used for calculation of average demand (at meter or at generation)

♦ AED is one of the oldest and most-widely used demand allocation methods

♦ While AED is an appropriate method for allocating generation demand, there are other demand allocators that could also be argued to be appropriate (see NARUC “Electricity Cost Allocation Manual”)

Could separate base-load generation demand-related costs and use an average-demand allocator

Could separate peak-load generation demand-related costs and use an CP- or excess-demand allocator

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Allocation of Energy-Related Generation

Energy-Related generation cost allocation methods should take into account the fact that different rate classes have different contributions to line losses. ♦ Residential and small commercial customers contribute significantly more

to losses than do large high-voltage customers

Energy-Related generation cost allocation methods could also take into account the fact that different rate classes have different load factors and, therefore, may have different contributions to (expensive) peak-load generation energy costs. ♦ Residential and small commercial customers consume a greater share of

their kWh during peak times and, therefore, consume proportionately more energy from peaker units

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Allocation of Transmission Demand-Related Costs

12-CP is the allocation method the FERC uses for transmission and, therefore for consistency, it is also used by most states. ♦ Transmission-system loads are often significantly high (relative to

transmission capacity) even during low total-system load months because remote base-load generation facilities are still being relied upon (as they are during high total system load months)

♦ It is common for the monthly peak demand on a utility’s transmission to be very similar across all months (basically, there is at least one hour each month where transmission demand is “at transmission capacity”) a 12-CP demand allocation method is appropriate.

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Allocation of Distribution Costs

NCP is the allocation method typically used for distribution demand-related costs ♦ Investment in distribution facilities is generally made to serve class

maximum demands that are not coincident with the system peak, and therefore the NCP allocation methodology provides reasonable results.

♦ This method is consistent with a generally accepted approach to distribution demand allocation.

Methods that allocate customer-related costs associated with metering and customer service should take into account that average meter or service costs (per customer) varies across rate classes ♦ Use a weighted customer method, or directly assign these costs to

rate classes wherever and whenever possible

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(1) (2) (3) (4) (5) (6) (7) (8)

DEMAND ALLOCATION UNITSCOINCIDENT PEAK CLASS NCP AVERAGE AVERAGE AND

1 CP 4 CP 12 CP CLASS NCP

w/INDUS. @50%

DEMAND EXCESS

Line No. RATE CLASS kW kW kW kW kW kW

ALLOCATION UNITS(1) RESIDENTIAL 2,043,367 1,708,526 1,381,058 2,133,650 2,133,650 800,366 1,681,459 (2) SGS 503,942 487,445 347,444 568,985 568,985 229,368 419,510 (3) MGS - Sec 398,784 386,273 296,477 443,015 443,015 208,504 314,699 (4) MGS - Pri 496,530 481,846 404,567 539,695 539,695 312,756 358,991 (5) LGS 555,014 519,611 533,954 625,926 312,963 417,005 378,206 (6) TOTAL 3,997,637 3,583,700 2,963,501 4,311,272 3,998,309 1,967,999 3,152,865

ALLOCATION FACTORS(7) RESIDENTIAL 0.5111 0.4767 0.4660 0.4949 0.5336 0.4067 0.5333 (8) SGS 0.1261 0.1360 0.1172 0.1320 0.1423 0.1165 0.1331 (9) MGS - Sec 0.0998 0.1078 0.1000 0.1028 0.1108 0.1059 0.0998 (10) MGS - Pri 0.1242 0.1345 0.1365 0.1252 0.1350 0.1589 0.1139 (11) LGS 0.1388 0.1450 0.1802 0.1452 0.0783 0.2119 0.1200 (12) TOTAL 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

Cost of new Met WEIGHTEDENERGY AT ENERGY AT NUMBER OF and Service NUMBER OF

METER LOSS FACTORSGENERATION CUSTOMERS per Customer CUSTOMERSmWhrs mWhrs (Current $) (6) x(7)

ALLOCATION UNITS(13) RESIDENTIAL 7,011,202 1.120 7,852,546 716,433 135.0 716,433 (14) SGS 2,009,265 2,210,192 83,177 157.5 97,026 (15) MGS - Sec 1,826,497 1,990,882 6,820 180.0 9,094 (16) MGS - Pri 2,739,745 1.076 2,876,732 454 202.5 681 (17) LGS 3,652,962 1.032 3,762,551 44 4,725.0 1,540 (18) TOTAL 17,239,671 18,692,903 806,928 824,774

ALLOCATION FACTORS(19) RESIDENTIAL 0.4067 0.4201 0.8879 1.0 0.8686 (20) SGS 0.1165 0.1182 0.1031 1.2 0.1176 (21) MGS - Sec 0.1059 0.1065 0.0085 1.3 0.0110 (22) MGS - Pri 0.1589 0.1539 0.0006 1.5 0.0008 (23) LGS 0.2119 0.2013 0.0001 35.0 0.0019 (24) TOTAL 1.0000 1.0000 1.0000 1.0000

EFFICIENT ENERGY INC.ALLOCATION FACTORS

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(1) (2) (3) (4) (5) (6)

CLASS NCP Average Demand Excess DemandAverage Demand

Component of Allocation Factor

Excess Demand Component of Allocation

FactorLine No.

RATE CLASS kW kW kW kW kW

(2) - (3) Ratio of Col. (3) Ratio of Col. (4)

(1) RESIDENTIAL 2,133,650 896,409 1,237,240 0.4201 0.5682(2) SGS 568,985 252,305 316,680 0.1182 0.1454(3) MGS - SEC 443,015 227,270 215,746 0.1065 0.0991(4) MGS - PRI 539,695 328,394 211,301 0.1539 0.0970(5) LGS 625,926 429,515 196,411 0.2013 0.0902(6) TOTAL 4,311,272 2,133,893 2,177,379 1.0000 1.0000

Total 1 CP kW: 4,161,248Load Factor: 51.28% WEIGHTING FACTORS

Average Demand Excess Demand

System Load Factor (1- System LF)(7) 0.4923 0.5077

Average Demand Component of Allocation

Factor

Excess Demand Component of Allocation

Factor

AVERAGE AND EXCESS Allocation

Factor

Alloc Factor times System LF

Alloc Factor times (1- sys LF)

(8) 0.2068 0.2885 0.4953 (9) 0.0582 0.0738 0.1320 (10) 0.0524 0.0503 0.1027 (11) 0.0758 0.0493 0.1250 (12) 0.0991 0.0458 0.1449 (13) 0.4923 0.5077 1.0000

ALLOCATION FACTORS - AVERAGE AND EXCESSEFFICIENT ENERGY INC.

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(1) (2) (3) (4) (5) (6) (7) (8) (9)DISTRIBUTION

PRIMARY / LINE TRANS. /GENERATION TRANSMISSION DIST. SUBS SECONDARY METER & SERV.

Line No.

PARTICULARS TOTAL Demand Energy Demand Demand Demand Customer Customer

REVENUE REQUIREMENT(1) COST EXCLUDING FUEL 1,281,837$ 804,147$ 50,900$ 75,340$ 68,964$ 115,569$ 62,229$ 104,689$ (2) COST OF FUEL 321,869$ -$ 321,869$ -$ -$ -$ -$ -$ (3) TOTAL 1,603,706$ 804,147$ 372,769$ 75,340$ 68,964$ 115,569$ 62,229$ 104,689$

(4) RATE BASE 3,197,601$ 2,040,037$ -$ 239,127$ 237,436$ 361,370$ 194,584$ 125,046$

ALLOCATION FACTORS AED mWhs w/loss 12 CP NCP NCP w/Inds.@50% Customers Weighted Cust(5) RESIDENTIAL 0.4201 0.4953 0.4201 0.4660 0.4949 0.5336 0.8879 0.8686 (6) SGS 0.1182 0.1320 0.1182 0.1172 0.1320 0.1423 0.1031 0.1176 (7) MGS - SEC 0.1065 0.1027 0.1065 0.1000 0.1028 0.1108 0.0085 0.0110 (8) MGS - PRI 0.1539 0.1250 0.1539 0.1365 0.1252 0.1350 0.0006 0.0008 (9) LGS 0.2013 0.1449 0.2013 0.1802 0.1452 0.0783 0.0001 0.0019 (10) TOTAL 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

ALLOCATED REVENUE REQUIREMENT(11) RESIDENTIAL 831,983$ 398,290$ 156,593$ 35,110$ 34,130$ 61,672$ 55,250$ 90,937$ (12) SGS 203,372$ 106,187$ 44,075$ 8,833$ 9,102$ 16,446$ 6,415$ 12,316$ (13) MGS - SEC 151,427$ 82,616$ 39,702$ 7,537$ 7,087$ 12,805$ 526$ 1,154$ (14) MGS - PRI 192,549$ 100,543$ 57,367$ 10,285$ 8,633$ 15,600$ 35$ 86$ (15) LGS 224,374$ 116,511$ 75,032$ 13,574$ 10,012$ 9,046$ 3$ 195$ (16) TOTAL 1,603,706$ 804,147$ 372,769$ 75,340$ 68,964$ 115,569$ 62,229$ 104,689$

ALLOCATED RATE BASE(17) RESIDENTIAL 1,713,590$ 1,010,421$ -$ 111,439$ 117,507$ 192,841$ 172,762$ 108,620$ (18) SGS 414,949$ 269,384$ -$ 28,036$ 31,336$ 51,425$ 20,057$ 14,710$ (19) MGS - SEC 300,973$ 209,589$ -$ 23,923$ 24,398$ 40,040$ 1,645$ 1,379$ (20) MGS - PRI 366,426$ 255,068$ -$ 32,645$ 29,723$ 48,778$ 109$ 103$ (21) LGS 401,663$ 295,576$ -$ 43,085$ 34,472$ 28,286$ 11$ 233$ (22) TOTAL 3,197,601$ 2,040,037$ -$ 239,127$ 237,436$ 361,370$ 194,584$ 125,046$

EFFICIENT ENERGY INC.ALLOCATION OF REVENUE & REVENUE REQUIREMENT (000's)

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AED = [(Average Demand Allocation Factor)A (system-load-factor) + (Excess Demand Allocation Factor)A (1 – system -load-factor)]

AED = [(42.01%) (49.23%) + (56.82%) (1 – 49.23%)]

= [(42.01%) (49.23%) + (56.82%) (50.77%)]

= 20.68% + 28.85% = 49.53%

In general, Class A’s Average-Excess Demand Allocation Factor is:

Consider the previous slide example. Residential Class AED Allocation Factor is:

Note that the closer the system load factor is to one (which would mean a larger share of generation units should be of the base-load technology type), the closer AED is to the average demand allocator (average demand drives the need for base-load generation)

Note that the closer the system load factor is to zero (which would mean a larger share of generation units should be of the peak-load technology type), the closer AED is to the excess demand allocator (excess demand drives the need for peak-load generation)

46

Basic Steps in Ratemaking Process











Company Operates

47

A tariff is a document, approved by the responsible regulatory agency, listing the terms and conditions under which utility services will be provided to customers within a particular class. Tariff sheets typically include: ♦ a schedule of all the rate elements (individual prices) plus the

provisions necessary for billing

♦ the service characteristics (e.g., voltage, single or three phase) and metering methods

♦ rules and regulations, i.e., a statement of the general practices the utility follows in carrying out its business with its customers

Rate Design

48

Billing Determinants ♦ Any element of the customer’s account that will be used in the

computation of a customer’s bill. These include the applicable rates and riders and the components of consumption, such as energy, peak demand, power factor, etc.

Base Rates ♦ Base Rates are rates that are fixed in the tariffs (until the next

rate case comes along)

Rate Design

49

Riders ♦ A rider is a mechanism that follows or "tracks" some

unpredictable costs that a utility incurs in providing service to consumers and allows the prices customers pay in order to recover these unpredictable costs to vary (without the need for a new rate case)

♦ The rider is an additional charge for each kilowatt-hour and is increased or decreased based on variable costs such as fuel and market power. The rider is adjusted monthly or quarterly.

♦ A Fuel and Purchased Power Adjustment Clause is an example of a rider

♦ Other costs may be tracked

Rate Design

50

Role of Rates ♦ Rates serve as the means by which the utility collects revenues

and covers its allowed cost of service (including that which is required under the “fair-return standard”)

♦ Rates induce particular behaviors on the part of customers Principles of Public Utility Rates by James C. Bonbright

Rate attributes: simplicity, understandability, public acceptability, and feasibility of application and interpretation

Effectiveness of yielding total revenue requirements

Revenue (and cash flow) stability from year to year

Stability of rates themselves, minimal unexpected changes that are seriously adverse to existing customers

Fairness in apportioning cost of service among different consumers

Avoidance of “undue discrimination”

Efficiency, promoting efficient use of energy and competing products and services

Rate Design

51

Demand Charge ♦ Measured in dollars per kW of monthly metered customer billing demand

Energy Charge ♦ Measured in dollars per kWh of monthly customer energy use

Customer Charge ♦ Measured in dollars per customer per month

Fundamental Rate Elements

52

Energy charges are derived by taking the class energy-related costs and dividing these costs by class energy use

Customer Charges are derived by taking the class customer-related costs and dividing by the class “customer months” ♦ A class’s customer-months is calculated by multiplying the total

number of customers in the class by 12

Fundamental Rate Elements: Energy and Customer Charges

53

Demand Charge ♦ Derived by taking the demand-related costs and dividing these

costs by class “billing demand” ♦ The manner in which the demand charge is calculated must be

consistent with the manner in which individual customers are metered; otherwise, the utility will over- or under-collect.

♦ For a class in which individual customers do not have demand meters, demand-related costs must be recovered either through the energy charge or the customer charge

Note: Use of the energy charge to recovery of fixed demand- and customer-related costs can increase risk of fixed-cost recovery

Fundamental Rate Elements: Demand Charges

54

Fundamental Rate Elements: Demand Charges

Here, energy units are the figures measured “at the meter.”

(1) (2) (3)

DemandkW

EnergyMWh

CustomersNo. Bills

(1) RESIDENTIAL 20,574,480 7,011,202 716,433(2) SGS 5,586,401 2,009,265 83,177(3) MGS - SEC 4,389,507 1,826,497 6,820(4) MGS - PRI 5,551,152 2,739,745 454(5) LGS 6,563,111 3,652,962 44(6) TOTAL 42,664,652 17,239,671 806,928

EFFICIENT ENERGY INC.PHYSICAL UNITS

BILLING UNITS

55

(1)Total Energy Use(MWh) 7,011,202

(2) Total Customers 716,433

(3) Total Customer-Months 8,597,196

(4)Avg. Monthly Use(kWh/customer) 816

(5) Demand-Related Costs 529,202

(6) Energy-Related Costs 156,593

(7) Customer-Related Costs 146,187

(8)Total RevenueRequirements 831,983

EFFICIENT ENERGY INC.RESIDENTIAL CLASS CHARACTERISTICS

PHYSICAL CHARACTERISTICS

REVENUE REQUIREMENTS ($000s)

56

(1) Energy-Related Costs (000s $) 156,593

(2) Divide by MWh (000s of kWh) 7,011,202

(3) Energy Charge ($/kWh) 0.0223

(4)Energy Charge(¢/kWh) 2.23

(5) Demand-Related Costs ($000s) 529,202

(6) Add Customer-Related Costs ($000s) 146,187

(7) Remaining Revenue Requirements ($000s) 675,390

(8) Remaining Revenue Requirements ($) 675,389,775

(9) Divide by Customer Months 8,597,196

(10)Monthly Customer Charge($/customer/mo.) 78.56

EFFICIENT ENERGY INC.Residential Pricing Strategy I

Collect all energy-related costs through a per kWh chargeCollect all other costs through a fixed monthly customer charge

CALCULATION OF ENERGY CHARGE

CALCULATION OF CUSTOMER CHARGE

57


(2) Add Demand-Related Costs (000s $) 529,202

(3) Costs to be Recovered 685,796

(4) Divide by MWh (000s kWh) 7,011,202



(7) Customer-Related Costs ($000s) 146,187

(8) Customer-Related Costs ($) 146,187,407

(9) Divide by Customer-Months 8,597,196

(10)Monthly Customer Charge($/customer/mo.) 17.00

EFFICIENT ENERGY INC.Residential Pricing Strategy II

Collect all energy-related & demand-related costs through a per kWh chargeCollect only customer-related costs through a fixed month customer charge

CALCULATION OF ENERGY CHARGE

CALCULATION OF CUSTOMER CHARGE

58


(2) Add Demand-Related Costs (000s $) 529,202

(3) Add Half of Customer-Related Costs (000s $) 73,094

(4) Costs to be Recovered 758,890

(5) Divided by MWh (000s kWh) 7,011,202


(7) Energy Charge (¢/kWh) 10.82

(8) Half of Customer-Related Costs (000s $) 73,094

(9) Half of Customer-Related Costs ($) 73,093,703

(10) Divide by Customer-Months 8,597,196

(11)Monthly Customer Charge($/customer/month) 8.50

EFFICIENT ENERGY INC.Residential Pricing Strategy III

Collect all energy-related & demand-related costs & half of customer-related costs through a per kWh chargeCollect only half of customer-related costs through a fixed month customer charge

Calculation of Energy Charge

Calculation of Customer Charge

59

Energy charge = 0.0223 ($/kWh)

Customer charge = 78.56 ($/month)

EnergyComponent

FixedComponent Total Bill

Below-Average User(600 kWh/month) 13.40$ 78.56$ 91.96$

Average User (913 kWh/month) 20.39$ 78.56$ 98.95$

Above-Average User (1500 kWh/month) 33.50$ 78.56$ 112.06$



Energy Component

Fixed Component Total Bill

Below-Average User (600 KWh/month) 58.69$ 17.00$ 75.69$

Average User (913 KWh/month) 89.30$ 17.00$ 106.31$

Above-Average User (1500 KWh/month) 146.72$ 17.00$ 163.73$



Energy Component

Fixed Component Total Bill

Below-Average User (600 kWh/month) 64.94$ 8.50$ 73.45$

Average User (913 kWh/month) 98.82$ 8.50$ 107.32$

Above-Average User (1500 kWh/month) 162.36$ 8.50$ 170.86$

EFFICIENT ENERGY INC.Residential Bill Impacts

Strategy I

Strategy II

Strategy III

60

Simple Two-Part Tariff

Total Bill = (customer charge) + (energy charge)*(kWh consumed)

Y = a + b*X

$

kWh/month

Strategy III (small a, large b)

Strategy I (large a, small b)

(X)

(Y)

Average Use = 913

Strategy II

$8.50

$17.00

$78.56

61



(3) Total Customer-Months 998,124

(4)Avg. MonthlykWh/Customer 2,013

(5) Class NCP (MW) 517

(6) Billing Demand (MW) 5,586

(7)Average MonthlyMW/Customer 0.0056

(8)Average MonthlykW/Customer 5.60

(9) Demand-Related Costs $140,567

(10) Energy-Related Costs $44,075

(11) Customer-Related Costs $18,730

(12) Total Revenue Requirements $203,372

EFFICIENT ENERGY INC.SGS CLASS CHARACTERISTICS



62





(5) Customer-Related Costs (000s $) 18,730


(7) Divide by Customer Months 998,124

(8)Monthly Customer Charge($/customer/mo.) 18.77$

(9) Demand-Related Costs (000s $) 140,567

(10)Divide by Billing Demand(MW = 000s kW) 5,586

(11) Annual Demand Charge ($/kW/year) 25.16$

EFFICIENT ENERGY INC.SGS Rate Elements



Calculation of Demand Charge

63

(1) Energy Charge ($/kWh) 0.0219$

(2) Multiply by Avg. Cust. Monthly kWh 2,013

(3) Energy Component of Bill ($/month) 44.16$

(4) Demand Charge ($/kW/month) 25.16$

(5) Multiply by Avg. Cust. Monthly kW 5.60

(6)Demand Component of Monthly Bill($/month) 140.83$

(7)Customer Component of Monthly Bill($/month) 18.77$

(8) Monthly Bill ($/month) 203.75$

EFFICIENT ENERGY INC.Average SGS Customer's Monthly Bill

Energy Component

Demand Component

Customer Component

Total Bill

64








(8)Average MonthlykW/Customer 54



(11) Customer-Related Costs $1,680


EFFICIENT ENERGY INC.MGS (Secondary) CLASS CHARACTERISTICS



65





(5) Customer-Related Costs (000s $) 1,680






(11) Annual Demand Charge ($/kW/year) 25.07$

EFFICIENT ENERGY INC.MGS (Secondary) Rate Elements




66



(3) Energy Component of Bill ($/month) 485.11$


(5) Multiply by Avg. Cust. Monthly kW 54

(6)Demand Component of Monthly Bill($/month) 1,344.64$


(8) Monthly Bill ($/month) 1,850.28$

EFFICIENT ENERGY INC.Average MGS (Secondary) Customer's Monthly Bill

Energy Component

Demand Component

Customer Component

Total Bill

67


(2) Total Customers 454






(8)Average MonthlykW/Customer 1,019



(11) Customer-Related Costs $121


EFFICIENT ENERGY INC.MGS (Primary) CLASS CHARACTERISTICS



68





(5) Customer-Related Costs (000s $) 121

(6) Customer-Related Costs ($) 121,451





(11) Demand Charge ($/kW) 24.33$

EFFICIENT ENERGY INC.MGS (Primary) Rate Elements




69



(3) Energy Component of Bill ($/month) 10,529.93$


(5) Multiply by Avg. Cust. Monthly kW 1,019

(6)Demand Component of Monthly Bill($/month) 24,790.92$


(8) Monthly Bill ($/month) 35,343.14$

EFFICIENT ENERGY INC.Average MGS (Primary) Customer's Monthly Bill

Energy Component

Demand Component

Customer Component

Total Bill

70


(2) Total Customers 44

(3) Total Customer-Months 528

(4)Avg. MonthlykWh/Customer 6,918,489




(8)Average MonthlykW/Customer 12,430



(11) Customer-Related Costs $199


EFFICIENT ENERGY INC.LGS CLASS CHARACTERISTICS



71





(5) Customer-Related Costs (000s $) 199

(6) Customer-Related Costs ($) 198,866

(7) Divide by Customer Months 528





EFFICIENT ENERGY INC.LGS Rate Elements




72


(2) Multiply by Avg. Cust. Monthly kWh 6,918,489

(3) Energy Component of Bill ($/month) 142,106$


(5) Multiply by Avg. Cust. Monthly kW 12,430

(6)Demand Component of Monthly Bill($/month) 282,469$

(7)Customer Component of Monthly Bill($/month) 377$

(8) Monthly Bill ($/month) 424,952$

EFFICIENT ENERGY INC.Average LGS Customer's Monthly Bill

Energy Component

Demand Component

Customer Component

Total Bill

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