overview and introduction introduction to cost of service concepts & techniques
TRANSCRIPT
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Overview and Introduction
Introduction to Cost of Service Concepts & Techniques
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Objectives
Understanding and appreciation of different cost of service perspectives
Our challenges: Cost of service is not a science, it
is an art derived from processes viewed from differing perspectives
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Steps in the Overall Ratemaking process
STEP 1 Study Preparation
STEP 2 Review Policies, Objectives and Strategies
STEP 3 Determine Utility Revenue Requirement
STEP 4 Functionalize Costs and Services into Business Units
STEP 5 Classification of Costs
STEP 6 Allocate Costs to Rate Classes
STEP 7 Interpret Cost of Service Results and Develop Rate Design
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Steps in the Analytical Ratemaking process
STEP 1
Determine the revenue requirement of the utility
REVENUE REQUIREMENT DETERMINATIO
N
Step 2
Functionalize costs and services (production, transmission, distribution, etc.) COST
ALLOCATIONStep 3
Classify costs (demand,energy, customer costs, etc.)
Step 4
Allocate costs amongcustomer classes
Step 5
Design rates RATE DESIGN
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Overview of Cost of Service Process
Introduction to Cost of ServiceConcepts and Techniques
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Cost of Service Team Policy-Makers Finance Planning and Engineering Customer Service Accounting Others
Legal Marketing Conservation and DSM Economic Development
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Stakeholders – Identification Customers Regulators Economic development interests Environmental community Special interest for social
concerns The utility Bankers, vendors, employees,
unions Mystics
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Study Preparation
Introduction to Cost of ServiceConcepts and Techniques
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Study Preparation
Introduction Successful cost of service
analysis requires preparation and planning to ensure achievable results
Preparation time may be substantial
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Four Important Considerations
1) Understand Study objectives, policies and strategies
What is the desired outcome from: Utility perspective Customer perspective Regulator perspective
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Four Important Considerations (cont’d)
2) The reasonableness and defensibility of a Study is directly proportional to quality of data and thoroughness of analyses
Identify weaknesses or “Flash Points” likely to create controversy in your analysis
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Four Important Considerations (cont’d)
3) In the absence of quality data, it is better to make reasonable assumptions rather than to “walk away” from the issue Avoid getting lost in the
numbers Numbers are not a “crutch” Use “reasonableness” and
“common sense”
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Four Important Considerations (cont’d)
4) Know your system! Corporate/Legal/Jurisdictional Infrastructure Operations
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Revenue Requirement
Introduction to Cost of ServiceConcepts and Techniques
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Steps in the Rate Design Process
STEP 1
Determine the revenue requirement of the utility
REVENUE REQUIREMENT DETERMINATIO
N
Step 2
Functionalize costs and services (production, transmission, distribution, etc.) COST
ALLOCATIONStep 3
Classify costs (demand,energy, customer costs, etc.)
Step 4
Allocate costs amongcustomer classes
Step 5
Design rates RATE DESIGN
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Revenue Requirement
Definition – Revenue Requirement
For a utility system, the revenue requirement equals the total cost of serving customers in various rate classes
For each rate class, properly designed rates will generate sufficient revenues to equal the revenue requirement
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Revenue Requirement
Revenue Requirement includes: Reasonable operating expenses Fair return on investment Consideration of other revenue
sources
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Revenue Requirement
Definition – Test Year A 12-month period that reflects
financial and operating conditions that are expected to occur into the future
Historical Fiscal Year Accounting and Operating InformationAudited Financial Statements
Test Year reflects anticipated conditions
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Revenue Requirement
Definition: Known and Measurable
Adjustments Financial and/or operating
adjustments to actual historical utility performance. Adjustments are based on proven changes that have occurred or are expected to occur in the near future
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Revenue Requirement
Known and Measurable Adjustments Examples include:
Extraordinary capital projects Financing Re-organization, re-structuring Power supply
– Load changes
– Resource changes
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Revenue Requirement
Definition: Used and UsefulAn investment or business activity that provides value to customers
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Revenue Requirement
Revenue Requirement Components Operation and maintenance
expense Other cash or non-cash expenses Cost of capital Taxes or in lieu of taxes Return Less: other non-rate income
sources
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Revenue Requirement
Utility Approach – Applicable to IOUs, Cooperatives and Municipal Utilities Industry standard for IOUs and
Cooperatives Occasionally used for Municipal
Utilities
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FERC Uniform System of Accounts
100–199 Assets and other debits
200–299 Liabilities and other credits
300–399 Plant accounts
400–432, Income accounts
434-435
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FERC Uniform System of Accounts (cont’d)
433, Retained earnings accounts436-439
440–459 Revenue accounts
500–599 Production, transmission and distribution expenses
900–949 Customer accounts, customer service and informational, sales, and general and administrative expenses
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Example
Utility Approach (IOU) Revenue Requirement Example COS 5-1
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Revenue Requirement
Definition: Rate Base (IOU) Investment upon which a utility
can earn a rate of return
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Revenue Requirement Rate Base Components
Gross Plant in Service Accumulated Depreciation Accumulated Provision for
DeferredIncome Taxes
Electric Plant Held for Future Use Construction Work in Progress Allowance for Funds Used During
Construction Working Capital
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Revenue Requirement
Return on Rate Base (IOUs) Appropriateness
Cost of debt Cost of equity Business risk
Consistency
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Revenue Requirement
Return on Rate Base (IOUs) Weighted Average Cost of Capital
(WACC) A regulated utility is allowed to earn a
return on its investment. The return included in the revenue requirement is the Rate Base multiplied by a percentage rate of return (ROR)
Example:– Rate Base = $100 million– Allowed ROR = 9.85%– Allowed Return = $9.85 million per year
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Revenue RequirementWeighted Average Cost of Capital (WACC) (cont’d) The overall ROR consists of amounts to cover
the costs of long-term debt and preferred stock, plus a return on stockholder equity comparable to that of other investments of similar risk
Example:Item % of Capital Cost Weighted Cost
Long-Term Debt 40% 7% 2.80%
Preferred Stock 5% 9% 0.45%
Equity 55% 12% 6.60%
TOTAL 100% N/A 9.85%
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Revenue Requirement
Return on Rate Base (IOUs) Cost of Debt
Long Term Debt Short term borrowing Preferred Stock - Equity securities
that pay a fixed dividend regardless of corporate earnings and offer preferential rights in regard to distribution of assets upon liquidation
Straight forward calculation
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Revenue Requirement
Return on Rate Base (IOUs) Cost of Equity
Industry average– Value Line
History Unique circumstances
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Example
Utility Approach (IOU) Rate Base Example COS 5-2
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Cost Allocation Methodologies
Introduction to Cost of ServiceConcepts and Techniques
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Cost Allocation Cost allocation is the process
of taking the total revenue requirements and spreading it over the various classes of customers
The ultimate goal is to allocate costs in a fashion which reflects the cost of providing services to each class (a cause-and-effect relationship)
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Steps in the Ratemaking process
STEP 1
Determine the revenue requirement of the utility
REVENUE REQUIREMENT DETERMINATIO
N
Step 2
Functionalize costs and services (production, transmission, distribution, etc.) COST
ALLOCATIONStep 3
Classify costs (demand,energy, customer costs, etc.)
Step 4
Allocate costs amongcustomer classes
Step 5
Design rates RATE DESIGN
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Functionalize Costs
Typical cost functions include:
Production (and/or purchased power)
Transmission Distribution Customer Care
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Classify Costs Typical cost classifications include: Demand Costs
Costs that vary with the kW demand imposed on the system
Energy Costs Costs that vary with the energy or kWh sold or
purchased Customer Costs
Costs that are related to the number of customers served
Revenue Related Costs Costs that vary with revenue
Direct Assignment Costs specifically assigned to a particular
customer or group of customers
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Allocate Costs Costs are allocated based on a
combination of function, classification, and other attributes
Allocation factors are developed for each cost classification Demand (CP, 12CP, NCP, etc.)
Energy (kWh)
Customers (unweighted, weighted)
Others (revenue, labor, blended/derived allocation factors)
Allocation factors are used to spread costs among customer classes (residential, commercial, industrial, lighting)
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Common Approaches to Cost Allocation
Embedded Marginal
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Definition – Embedded Cost
Average system costs assuming all utility resources spread across all customers
Generally based on historical or known costs
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Definition – Marginal Cost
Costs experienced or avoided when a unit of output is added or forgone.
MC =
∆ Total Cost∆ Quantity
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Common Approaches to Cost Allocation (cont’d)
Bundled Approach
Unbundled Approach
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Bundled Approach Cost Allocation
Mirrors utility accounting practices
Cost of service results are bundled and presented from the utility’s perspective
Limits rate design
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Bundled Approach
RevenueReqs.
Ops. &Maintenance
Expense
Depreciation
Taxes
Return onRatebase
Other
COST OF SERVICECOST OF SERVICEBY RATE CLASSBY RATE CLASS
Resid
entia
l
Smal
l
Comm
ercial
Larg
e
Comm
ercial
Ligh
ting
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Unbundled Approach Cost Allocation
Mirrors utility products, services and activities
Cost of service results are unbundled and presented from the customer’s perspective
Flexible rate design
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Unbundled Approach
RevenueReqs.
Ops. &Maintenance
Expense
Depreciation
Taxes
Return onRatebase
Other
COST OF SERVICECOST OF SERVICEBY RATE CLASSBY RATE CLASS
Res
iden
tial
Smal
l
Com
mer
cial
Larg
e
Com
mer
cial
Ligh
ting
RevenueReqs.
Prod.
Trans.
Distrib.
Customer
Prod
uction
Cust
omer
Tran
smis
sion
Dis
trib
utio
n
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Functionalization of Costs
Introduction to Cost of ServiceConcepts and Techniques
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Steps in the Rate Design Process
STEP 1
Determine the revenue requirement of the utility
REVENUE REQUIREMENT DETERMINATIO
N
Step 2
Functionalize costs and services (production, transmission, distribution, etc.) COST
ALLOCATIONStep 3
Classify costs (demand,energy, customer costs, etc.)
Step 4
Allocate costs amongcustomer classes
Step 5
Design rates RATE DESIGN
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What Business Are You In?
GeneratingStation
ResidentialCustomer
CommercialCustomer
DistributionSubstation
IndustrialCustomer
High VoltageTransmission
TransmissionSubstation
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Four Common Business Units
Production Transmission Distribution Customer Care
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Allocating Costs to Business Units
Unbundle Test Year Revenue Requirement into Business Units Direct Assignments Derived Allocation
Allocation representing the sum, average or weighted effect of differing underlying allocation methods
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Example: Direct Assignment – Distribution
FERCAcct.
Description
AllocMetho
d
Amount
ProdTran
sDist Cust
582 Station Exp. Direct1,000,00
00 0 1,000,000 0
Allocation % 100% 0% 0% 100% 0%
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Example: Derived Allocation – Administration and General Salary Expense
What are the underlying activities impacting the level of Administration and General Salary Expense in your organization?
Support and Management of the Labor Force
Strategic Planning Regulatory
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Example: Derived Allocation – Administration and General Salary Expense
Cost Drivers associated with management of the Labor Force
Employee Salaries Number of Employees
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Example: Derived Allocation – Administration and General Salary Expense
Cost Drivers associated with Strategic Planning Rate Base Capital Improvement Plan
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Example: Derived Allocation – Administration and General Salary Expense
Cost Drivers associated with Regulatory Activities Rate Base Outside Services Employed
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Example: Derived Allocation – Administration and General Salary Expense
A&G Salary Allocation Based on Labor Salaries
Labor SalariesBusiness
Unit Total Prod Trans Dist Cust
Production 3,000,000 3,000,000 0 0 0
Transmission 1,000,000 0 1,000,000 0 0
Distribution 5,000,000 0 0 5,000,000 0
Customer 500,000 0 0 0 500,000
Total 9,500,000 3,000,000 1,000,000 5,000,000 500,000
% Allocation 100% 32% 11% 52% 5%
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Example: Derived Allocation – Administration and General Salary Expense
FERCAcct.
Description
AllocMetho
dAmount Prod Trans Dist Cust
920A&G Salaries
Derived1,000,00
0320,00
0110,000 520,000
50,000
Allocation %
100% 32% 11% 52% 5%
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Classification of Costs
Introduction to Cost of ServiceConcepts and Techniques
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Development of Allocation Factors
STEP 1
Determine the revenue requirement of the utility
REVENUE REQUIREMENT DETERMINATIO
N
Step 2
Functionalize costs and services (production, transmission, distribution, etc.) COST
ALLOCATIONStep 3
Classify costs (demand,energy, customer costs, etc.)
Step 4
Allocate costs amongcustomer classes
Step 5
Design rates RATE DESIGN
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Basic Cost Categories
Fixed Cost Variable Cost
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Fixed Costs
Do not vary materially with electricity use or number of customers Examples:
Labor Insurance Depreciation Interest
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Variable Costs
Vary with production or electricity use Examples:
Fuel Variable production costs
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Typical Cost Classifications
Demand Energy Customer Revenue Direct Assignments
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Demand-Related Costs
Costs that vary with the kilowatt demand imposed on the System Examples:
Demand portion of production Transmission Demand component of distribution
plant
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Energy-Related Costs
Costs that vary with the energy or kilowatt-hours provided by the utility Examples:
Fuel Variable production costs
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Customer-Related Costs
Costs that are related to the number of customer services Examples:
Customer billing Meter reading Customer service Capital cost of meters and services O&M costs of meters and services
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Revenue-Related Costs
Costs that vary with revenue Examples:
Taxes Public benefit charges
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Direct Assignments
Costs assigned directly to a particular customer or Class of customers Examples:
Line extensions to specific customer Street and security lighting
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Summary of Cost Functions and Classifications
Production: Demand RelatedEnergy Related
Transmission: Demand RelatedDirect Assignments
Distribution: Demand RelatedCustomer RelatedDirect Assignments
Customer Service: Customer Related
Typical Cost Classifications
Typical CostFunctions
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Rate Class Determination
Introduction to Cost of ServiceConcepts and Techniques
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Issues
Are Rate Classes needed? Why do we have them? What are they? Changes in approach
Number of classes Type of classes Classes within classes Cost of service support
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Why Have Rate Classes?
Different load characteristics Different service voltages Different costs to serve
Load density Reliability requirements Other (discussion)
Desire for different returns
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Typical Classes Residential Small Commercial Large Commercial Industrial Agricultural Municipal Streetlighting Security Lighting Net Metering? Off-System Sales (Market Driven)
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Changes in Approach – Industry Restructuring
Rate Design’s impact on rate class determination
Time-of-Use rates can compensate for different load characteristics
Real-Time pricing even better Need for different ROIs Need for Non-Demand vs. Demand
Rates Use service voltage discounts to
reduce number Small number of classes is preferable Other
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Development of Allocation Factors
Introduction to Cost of ServiceConcepts and Techniques
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Steps in Ratemaking Process
STEP 1
Determine the revenue requirement of the utility
REVENUE REQUIREMENT DETERMINATIO
N
Step 2
Functionalize costs and services (production, transmission, distribution, etc.) COST
ALLOCATIONStep 3
Classify costs (demand,energy, customer costs, etc.)
Step 4
Allocate costs amongcustomer classes
Step 5
Design rates RATE DESIGN
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Development of Allocation Factors
How do you develop allocation factors? Which allocation factors are
needed? What are allocation factors based
on? Information and data needs? Who has the information?
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Development of Allocation Factors
Allocation Methodology must align with Cost Classification
Demand-Related Coincident Peak Non-Coincident Peak Sum of Max Demands
Energy-Related kWh Sales Net Energy for Load
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Development of Allocation Factors
Demand/Energy Hybrids Average and Excess Demand Other
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Development of Allocation Factors
Customer-Related Number of customers Weighted number of customers
Revenue-Related Direct Assignment
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Coincident Peak
Definition: Class demand at the time of the System Peak Annual Monthly Hourly
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Class Contribution to Coincident Peak
Class Contribution to Peak Demand – Annual Peak
0
200
400
600
800
1,000
1,200
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Dem
and
(MW
)
Class A Class B Class C
Class A PeakNon-Coincident Peak
Class B PeakNon-Coincident PeakClass C Peak
Non-Coincident Peak
Annual Coincident Peak
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Non-Coincident Peak
Definition: Maximum demand of a customer class, regardless of when it occurs.
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Class Non-Coincident Peak Compared to Contribution to System Coincident Peak
Class Contribution to Peak Demand – Monthly
0
200
400
600
800
1,000
1,200
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Dem
and
(M
W)
Class A Class B Class C
Class A PeakNon-Coincident Peak
Class B PeakNon-Coincident Peak
Class C PeakNon-Coincident Peak
Annual Coincident Peak
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Sum of Maximum Demands
Definition: Sum of demands measured at the meter
Load profile meter Billed Demand
Beware of ratchets! Estimated Demands
Load factors Load research study results
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Concept of Coincidence and Diversity
Sum of Maximum Demands
Totalized Class Peak Demands (Class NCP)
System Coincident(Class CP) Peak Demands
Residential
Commercial
Industrial
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Demand Cost Allocation – Typical Methods
Coincident Peak (CP) Method Based on the theory that the
demand costs are most strongly influenced by class demands imposed on the system at the time of the system peak
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Variations of the Coincident Peak (CP) Method
1 CP – Based on class CP demands for the month in which the annual system peak occurs.
2 CP, 3 CP, 4 CP, etc. – Based on class CP demands for each of the months of highest system demands.
Examples: A summer peaking system might allocate demand
costs on the basis of class CP demands in each of the 4 months June through September.
A winter peaking system might allocate demand costs on the basis of class CP demands in each of the 3 or 4 winter months.
A system with significant summer and winter peaks might allocate demand costs on the basis of class CP demands in each of 1 to 4 summer months and 1 to 4 winter months.
12 CP – Based on class CP demands for each of the 12 months of the year.
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Examples of Demand Cost Allocation Methods Data Sheet
Monthly Coincidental Peaks (kW)
Class A Class B Class C Total
Jan 300 250 280 830 Feb 310 240 250 800 Mar 320 200 250 770 Apr 300 200 250 750 May 300 220 250 770 Jun 430 230 240 900 Jul 460 240 240 940 Aug 470 290 240 1,000 Sep 430 240 250 920 Oct 310 200 250 760 Nov 310 200 250 760 Dec 320 230 250 800 Total
4,260 2,740 3,000 10,000
Annual Non-CoincidentalPeaks (kW)
480 310 285 1,075
Annual Energy (kWh)
1,270,000
1,051,000
1,752,000
4,073,000
Demand Costs ($)
$100,000
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Monthly CoincidentalPeaks (kW)
Class A Class B Class C Total
Jan 300 250 280 830Feb 310 240 250 800Mar 320 200 250 770Apr 300 200 250 750May 300 220 250 770Jun 430 230 240 900Jul 460 240 240 940Aug 470 290 240 1,000Sep 430 240 250 920Oct 310 200 250 760Nov 310 200 250 760Dec 320 230 250 800Total 4,260 2,740 3,000 10,000
Annual Non-Coincidental Peaks (kW)
480 310 285 1,075
Annual Energy (kWh) 1,270,000 1,051,000 1,752,000 4,073,000
Demand Costs ($) $100,000
Allocation Based on 1 CPMethod Demand Used for Alloc. 470 290 240 1,000 Allocation Percentage 47.00% 29.00% 24.00% 100.00% Allocated Demand Cost $47,000 $29,000 $24,000 $100,000
Examples of Demand Cost Allocation Methods (1 CP Method)
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Monthly CoincidentalPeaks (kW)
Class A Class B Class C Total
Jan 300 250 280 830Feb 310 240 250 800Mar 320 200 250 770Apr 300 200 250 750May 300 220 250 770Jun 430 230 240 900Jul 460 240 240 940Aug 470 290 240 1,000Sep 430 240 250 920Oct 310 200 250 760Nov 310 200 250 760Dec 320 230 250 800Total 4,260 2,740 3,000 10,000
Annual Non-Coincidental Peaks (kW)
480 310 285 1,075
Annual Energy (kWh) 1,270,000 1,051,000 1,752,000 4,073,000
Demand Costs ($) $100,000
Allocation Based on 4 CPMethod Demand Used for Alloc. 1,790 1,000 970 3,760 Allocation Percentage 47.60% 26.60% 25.80% 100.00% Allocated Demand Cost $47,600 $26,600 $25,800 $100,000
Examples of Demand Cost Allocation Methods (4 CP Method)
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Monthly CoincidentalPeaks (kW)
Class A Class B Class C Total
Jan 300 250 280 830Feb 310 240 250 800Mar 320 200 250 770Apr 300 200 250 750May 300 220 250 770Jun 430 230 240 900Jul 460 240 240 940Aug 470 290 240 1,000Sep 430 240 250 920Oct 310 200 250 760Nov 310 200 250 760Dec 320 230 250 800Total 4,260 2,740 3,000 10,000
Annual Non-Coincidental Peaks (kW)
480 310 285 1,075
Annual Energy (kWh) 1,270,000 1,051,000 1,752,000 4,073,000
Demand Costs ($) $100,000
Allocation Based on 12CP Method Demand Used for Alloc. 4,260 2,740 3,000 10,000 Allocation Percentage 42.60% 27.40% 30.00% 100.00% Allocated Demand Cost $42,600 $27,400 $30,000 $100,000
Examples of Demand Cost Allocation Methods (12 CP Method)
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Demand Cost Allocation – Typical Methods
Non-Coincident Peak (NCP) Methods Based on the theory that
demand costs are most strongly influenced by the highest demand of each class, whenever it occurs
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Variations of the Non-Coincident Peak (NCP) Method
NCP – Based on the greatest demand of each customer class at any time during the year
12 NCP – Based on the non-coincident peak demands of each customer class for each of the 12 months of the year
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NCP MethodMonthly Non-Coincident Peaks (kW) Class A Class B Class C Total
Jan 316 263 285 Feb 326 253 254Mar 337 211 254Apr 309 250 263May 309 275 263Jun 443 288 253Jul 469 257 244 Aug 480 310 244Sep 439 257 254Oct 320 214 254Nov 320 214 250Dec 330 246 258 Total of 12 NCP 4,398 3,038 3,076
Annual Non-Coincident Peaks (kW) 480 310 285
Annual Energy (kWh) 1,270,000 1,051,000 1,752,000 4,073,000
Demand Costs ($) 100,000$
Allocation Based on 1 NCP METHODDemand Used for Allocation 480 310 285 1,075 Allocation Percentage 44.6% 28.9% 26.5% 100.0%Allocated Demand Cost 44,651$ 28,837$ 26,512$ 100,000$
Allocation Based on 12 NCP METHODDemand Used for Allocation 4,398 3,038 3,076 10,512 Allocation Percentage 41.8% 28.9% 29.3% 100.0%Allocated Demand Cost 41,838$ 28,900$ 29,262$ 100,000$
864833802822847984970
1,034950788784834
10,512
1,075
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Demand Cost Allocation – Typical Methods
Average and Excess Demand (AED) Method Based on the theory that
demand costs are influenced both by the non-coincident peak of each customer class and by the energy usage - or average demand - of each customer class
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Monthly CoincidentalPeaks (kW)
Class A Class B Class C Total
Jan 300 250 280 830Feb 310 240 250 800Mar 320 200 250 770Apr 300 200 250 750May 300 220 250 770Jun 430 230 240 900Jul 460 240 240 940Aug 470 290 240 1,000Sep 430 240 250 920Oct 310 200 250 760Nov 310 200 250 760Dec 320 230 250 800Total 4,260 2,740 3,000 10,000
Annual Non-Coincidental Peaks (kW)
480 310 285 1,075
Annual Energy (kWh) 1,270,000 1,051,000 1,752,000 4,073,000
Demand Costs ($) $100,000
Allocation Based on AEDMethod Demand Used for Alloc. 438.8 286.6 274.6 1,000 Allocation Percentage 43.88% 28.66% 27.46% 100.00% Allocated Demand Cost $43,880 $28,660 $27,460 $100,000
Examples of Demand Cost Allocation Methods (AED Method)
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Examples of Demand Cost Allocation Methods (AED Method cont’d)
Average and Excess Demand Method
Class A Class B Class C Total Calculation
Annual Energy (kWh) 1,270,000 1,051,000 1,752,000 4,073,000 A
Hours in Year 8,760 8,760 8,760 8,760 B
Average Demand 145 120 200 465 C = A / B
Non-Coincident Peak Demand (kW)
480 310 285 D
Average Demand (kW) 145 120 200 C
Class Excess Demand (kW) 335 190 85 610 E = D - C
System Coincidental Peak (kW) 1,000 F
System Average Demand (kW) 465 C
System Excess Demand (kW) 535 G = F - C
Excess Allocation Factors 335/ 610 190/ 610 85/ 610 H = E / E total
Allocated Excess Demand (kW) 293.8 166.6 74.6 535.0 I = G X H
Summary
Average Demand (kW) 145 120 200 465 C
Allocated Excess Demand (kW) 293.8 166.6 74.6 535 I
Total (kW) 438.8 286.6 274.6 1,000
Allocation Percentage 43.88% 28.66% 27.46% 100.00%
Allocated Demand Cost $43.880 $28.660 $27.460 $100.000
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Examples of Demand Cost Allocation Methods (Summary of Results)
Demand Cost
Allocation Percentage
sClass A Class B Class C Total
1 CP Method 47.00% 29.00% 24.00% 100.0%
4 CP Method 47.60% 26.60% 25.80% 100.0%
12 CP Method 42.60% 27.40% 30.00% 100.0%
1 NCP Method 44.65% 28.84% 26.51% 100.0%
12 NCP Method
41.80% 28.90% 29.30% 100.0%
AED Method 43.88% 28.66% 27.46% 100.0%
Range41.80 – 47.60%
26.60 – 29.00%
24.00 – 30.00%
Ratio, High/Low
1.14 1.09 1.25
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Energy-Related Allocation Factors
Energy Allocation Factors kWh Sales adjusted for losses
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Energy-Related Allocation Factors
Annual Energy (kWh) Class A Class B Class C Total
Voltage Class Served at: Secondary Secondary Primary
At the Generator 1,270,000 1,051,000 1,752,000 4,073,000 Transmission Loss 1.5% 19,050 15,765 26,280 61,095
Sales 1,250,950 1,035,235 1,725,720 4,011,905 Primary Loss 1.5% 18,764 15,529 25,886 60,179
Sales 1,232,186 1,019,706 1,699,834 3,951,726 Distribution Loss 2.0% 24,644 20,394 NA 45,038
Allocation Percentage by Delivery Voltage At the Generator 31.2% 25.8% 43.0% 100.0%
Transmission 31.2% 25.8% 43.0% 100.0%
Distribution Primary 31.2% 25.8% 43.0% 100.0% Distribution Secondary 54.7% 45.3%
0.0%
100.0%
Sales 1,207,542 999,312 2,206,854 NA
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Customer-Related Allocation Factors
Customer Allocation Factors Weighting Factors Special Studies
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Customer-Related Allocation Factors
Total System Class A Class B Class C
No. of Customers 90,000 72,000 12,000 6,000
Allocation % 80.0% 13.3% 6.7%
Billing & Collection Weighting Factors
1.0 2.0 10.0
Weighted Numbers of Customers
156,000 72,000 24,000 60,000
Allocation % after Weighting 46.2% 15.4% 38.4%
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Other Methods to Allocate Costs
Revenue Related Allocation Factors
Direct Assignments Note: Some costs are specifically
assigned to a particular customer or class of customers if it can be determined that those costs related only to that customer or customer class
Primary/ Transmission level customers should not be allocated distribution level costs
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Interpreting Cost of Service Results
Introduction to Cost of ServiceConcepts and Techniques
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Subsidization
The act of financially supporting service to one group of customers through excess collection of revenues from another group of customers.
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Overview
Subsidization Interclass Intraclass
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Interclass Subsidization
One class of customers subsidizing another class of customers.
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Interclass Subsidization
Revenues CollectedClass RevenuesResidential 50%Small Commercial 20%Large Commercial 10%General Service 20%
100%
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Interclass Subsidization
Cost of Service ResultsRevenue
Class RequirementsResidential 55%Small Commercial 18%Large Commercial 8%General Service 19%
100%
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Interclass Subsidization
Revenues vs. Revenue Requirements
0%
10%
20%
30%
40%
50%
60%
Residential Small Commercial Large Commercial General Service
Customer Class
Revenue Requirements Revenues
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Intraclass Subsidization
Customers within a specific class subsidizing other customers in the same class based on design of the rate and differing consumption.
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Intraclass Subsidization Examples
Assume for the following two examples that the Cost of Service study indicated that the respective classes (residential and general service) are contributing an adequate amount of total class revenues (no interclass subsidy exists).
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Intraclass SubsidizationResidential Class
Existing Rate COS Rate
Customer Charge $5/mo. $12/mo.
Energy Charge $0.07/kWh $0.06/kWh
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Intraclass SubsidizationResidential Class
$0
$10
$20
$30
$40
$50
$60
$70
$80
0 100 200 300 400 500 600 700 800 900 1000
kWh
Mon
thly
Bill
Existing Rate COS Rate
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Intraclass SubsidizationGeneral Service Class
Existing Rate COS Rate
Demand Charge $6/kW-mo. $10/kW-mo.
Energy Charge $0.04/kWh $0.03/kWh
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Intraclass SubsidizationGeneral Service Class
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Mon
thly
Bill (1
0,0
00
kW
h)
Load Factor
Existing Rate COS Rate
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General Ratemaking and Regulatory Principles
Introduction to Rate Design
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Introduction
Bonbright — Common Reference
Industry Changes — Competition
Social Pricing Objectives The Art of Balance
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Bonbright Principles Practical Uncontroversial as to
interpretation Meet revenue requirements Revenue stability Rate stability Fairness among customer classes Avoidance of undue discrimination Economic efficiency
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Factors Affecting Electric Utilities and Their Customers Inflation rates Fuel costs Uncertainty of fuel availability Uncertainty of the future of nuclear power Environmental concerns Uncertainty in predicting load growth Construction delays Increasing capital requirements Regulatory requirements Conservation of electricity and natural
resources New technologies
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Objectives of Utility Ratemaking Cost of service What the public wants Fairness to all consumers Marginal costs Price as a resource-control measure Competition, market forces and elasticity Need for a cushion above costs Simplicity vs. complexity Price as a taxing measure Price as a welfare measure Quality of service Differences among communities'
concerns
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Factors Which Can Influence theRate-Making Objectives of an Electric Utility
Overall cost of service Types of generation and fuel Self-generation vs. purchased power The size of the utility The age of its physical plant and rate of growth
of the system Sources of capital or other funding arrangements Competition in the form of alternate fuels and/or
the rates of neighboring utilities Customer mix Time-of-Use service Weather Legislation and regulation
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Four Major Reasons for Rate Adjustments
Revenue adjustment Up or Down
Cost of service realignment Competitive factors Legislative and regulatory
mandate EPAct 2005
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Competing Objectives
Meet revenue requirements
Low rates
Equity and fairness
Behavior modification
Social issueresponsiveness
Ability to compete
Legislative mandates
Simplicity and understandability
Unbundling TOU and Real
Time Rate Complexity
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Simplicity
Time-of-Use and Real-Time rates frustrate simplicity
Critical Peak Pricing and Load Curtailment add complexity
Unbundled rates frustrate (but also enhance) understandability
Adjustments for costs (e.g., ECAC) add to complexity
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Electric Utility PricingTrends That Matter
Introduction to Rate Design
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What are the Top Issues by Utilities?* (2009)
* Based on programs from 2009 NRECA, APPA and EEI conferences
ISSUE (UNRANKED)COOP
sIOUs
MUNIs
Renewables - requirements, power supply, pricing
■ ■ ■
Energy Efficiency - program design, rates ■ ■ ■
Carbon - capture/sequestration/storage, pricing
■ ■ ■
Emerging Technology - smart grid/metering, data centers, broadband over power lines
■ ■ ■
Electric vehicles - infrastructure, pricing, load impact
■ ■ ■
Finance/credit issues - stimulus money, tight credit markets
■ ■ ■
Advanced Rates - TOU, net metering ■ ■ ■
Distributed Energy - feed-in tariffs, backup ■ ■
Nuclear Power ■ ■ ■
Transmission ■
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What are the Top Issues by Utilities?* (2006-07)
* Based on programs from 2006-07 NRECA, APPA and EEI conferences
ISSUE (UNRANKED)COOP
s IOUsMUN
Is
Global Climate Change/Carbon Emissions ■ ■ ■
Challenges of Building New Generation ■ ■ ■
Finances/Credit Issues ■ ■ ■
Developing the Workforce of the Future/Partnering/Recruiting/Succession Planning
■ ■ ■
Emergency Preparedness ■ ■
Efficiency of Customer Relationships Through Technology
■ ■ ■
Industry Reliability ■ ■
Hurricane Damage Response ■ ■
Rate Impact of Rising Costs ■ ■ ■
Transmission Expansion ■ ■
Growth Strategies ■ ■ ■
Renewables in the Generation Portfolio ■ ■ ■
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Utility Costs Continue to Rise
Load growth (new supply) Infrastructure catch-up New infrastructure Economic environment,
increased inflation, capital costs Emissions Security Fuel
Source: Sieben Energy Associates, a Chicago-based energy consulting firm.
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Pricing: The Interface of Utility Realities and Customer Expectations
Utility Realities Demand Regulations Cost of Money Technology Green Power Infrastructure
Replacement/Renewal
Workforce
Customer Expectations Low Cost
Choice
Flexibility
Responsive
Technologically Savvy
Socially Responsible
PR
ICIN
G
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Rate Design Discussion