Issues in Cost Allocation. Introduction to Efficient Pricing. Rate Design by Objective

Transcription

1 Issues in Cost Allocation Introduction to Efficient Pricing Rate Design by Objective Presented To: EEI Advanced Rates School University of Wisconsin, Madison Presented By: Philip Q Hanser Principal, The Brattle Group July 25, 2011 Copyright 2010 The Brattle Group, Inc. Antitrust/Competition Commercial Damages Environmental Litigation and Regulation Forensic Economics Intellectual Property International Arbitration International Trade Product Liability Regulatory Finance and Accounting Risk Management Securities Tax Utility Regulatory Policy and Ratemaking Valuation Electric Power Financial Institutions Natural Gas Petroleum Pharmaceuticals, Medical Devices, and Biotechnology Telecommunications and Media Transportation

2 Issues in Cost Allocation 2

3 Basic Steps in Rate Making Process 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 Source: Blank & Gegax 3

4 Cost of Service Study 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) 4

5 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 5

6 Steps in an Embedded Cost of Service Study 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) 6

7 Functionalize and Classify Demand Bulk Transmission lines kv (ultra-high voltage lines go up to kv) Demand-Customer 3-phase primary distribution feeder lines (21 36 kv) distribution substations (step-down transformers) Sub-Transmission kv lines Customer 1-phase secondary distribution lateral lines (7-13 kv) transmission subs (step-down transformers) Drop lines to homes volts Facilities not used by all customers; Sized based on subset of system demands -- NCP Demand-Energy Generation (6-14 kv) Network switchyard step-up transformers 7 Common Facilities (used by all customers); sized based on system demands -- CP, Average Demand, Average-Excess Demand

8 Step 1: Functionalization 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 nongeneral functions) Usually, the rate-base component of revenue requirements is functionalized first; then the expense components are functionalized 8

9 Step 1: Functionalization 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 nongeneral-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 9

10 Step 1: Functionalization 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 10

11 Step 1: Functionalization 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 11

12 Electric Functionalization Example ($000) Efficient Energy Inc. Cost of Service/Revenue Requirements - ($000s) TOTAL Generation Transmission Distribution General Operation & Maintenance Expense Generation 576, , Transmission 15, , Distribution 47, ,733 0 Customer Accounts 37, ,769 0 Customer Service & Informational 12, ,510 0 Sales 1, ,846 0 Administrative & General 123, ,337 Total Operation & Maintenance 815, ,369 15,464 99, ,337 Depreciation Expense Intangible 5, ,812 Generation 131, , Transmission 9, , Distribution 44, ,591 0 General 21, ,667 Total Depreciation Expense 212, ,353 9,125 44,591 27,478 Taxes Taxes Other Than Income 150,640 84,485 9,804 37,514 18,837 Income Taxes 120,437 65,400 8,373 30,663 16,001 Return Debt Related 124,389 67,546 8,647 31,669 16,526 Equity Related 180,667 98,107 12,560 45,997 24,004 Total Return 305, ,652 21,207 77,666 40,530 Total Cost of Service 1,603,708 1,023,260 63, , ,184 Rate of Return 9.54% 9.54% 9.54% 9.54% 9.54% Rate Base 3,197,650 1,736, , , ,843 12

13 Step 2: Classification 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 13

14 Step 2: Classificatin Step 2: Classification 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 14

15 Step 2: Classification 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 lowvoltage distribution facilities 15

16 Step 2: Classification Step 2: Classification 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 16

17 Step 2: Classification Electric Classification Example - ($000s) Generation Transmission Distribution TOTAL Demand Related Energy Related Demand Related Demand Related Customer Related 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, ,337 O&M SUBTOTAL 274,974 34,391 23, ,203 52, ,655 FUEL 313, ,372 NET OPERATING INCOME & TAXES & ANNUAL DEPRECIATION 291,583 13,083 31, , ,625 TOTAL 566, ,845 55, ,566 52,124 1,298,652 17

18 Basic Steps in Rate Making Process Determination of Revenue Requirements/ Overall Cost of Service Components of Cost of Service Study Functionalize Costs Classify Cost Assign costs to Customer/Rate Classes Within a Jurisdiction Design Cost-Based Rate Elements for Each Rate Classes Tariff Jurisdictional Separations Allocation of Revenue Requirements Across the Jurisdictions in which the Company Operates Source: Blank & Gegax 18

19 Allocation: Class Cost of Service Study 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 19

20 Load Curve 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) 20

21 Information From Load Curves 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 21

22 Information From Load Curves 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 22

23 Load (MW) 4,500 4,000 3,500 3,000 2,500 2,000 Residential SGS LGS MGS Total System Peak Day Total System Daily Peak 1,500 1, Hours 23

24 Alternative CP Measures 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 24

25 Information From Load Curves 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%) 25

26 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 26

27 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 27 Customer-Related Allocation Methods

28 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) 28

29 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 subtransmission) Cost-causation dictates not to allocate the costs of these facilities to the particular customers who do not use these facilities 29

30 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 30

31 Allocation Demand-Related Cost Allocation Methods System Peak Responsibility (1CP, 4CP, 12CP) 12CP typically used for the allocation of transmission demandrelated 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 31

32 Load (MW) 4,500 4,000 3,500 3,000 2,500 2,000 Residential SGS LGS MGS Total System Peak Day Total System Daily Peak 1,500 1, Hours 32

33 MWh 2,000 1,500 Excess Demand 1,000 Average Demand Hours Winter/Spring Spring Summer Fall/Winter 33

34 Monthly Peak Loads by Class 3,500 3,000 Residential SGS LGS MGS Total System 2,500 2,000 MW 1,500 1, January February March April May June July August September October November December 34

35 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) 35

36 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 36

37 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. 37

38 Allocation of Generation Demand-Related Costs AED is commonly used for allocating generation demandrelated 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 38

39 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 39

40 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. 40

41 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 41

42 EFFICIENT ENERGY INC. ALLOCATION FACTORS (1) (2) (3) (4) (5) (6) (7) (8) DEMAND ALLOCATION UNITS COINCIDENT PEAK CLASS NCP AVERAGE AVERAGE AND 1 CP 4 CP 12 CP CLASS w/indus. 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, ,366 1,681,459 (2) SGS 503, , , , , , ,510 (3) MGS - Sec 398, , , , , , ,699 (4) MGS - Pri 496, , , , , , ,991 (5) LGS 555, , , , , , ,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 (8) SGS (9) MGS - Sec (10) MGS - Pri (11) LGS (12) TOTAL Cost of new Met WEIGHTED ENERGY AT ENERGY AT NUMBER OF and Service NUMBER OF METER LOSS FACTORSGENERATION CUSTOMERS per Customer CUSTOMERS mwhrs mwhrs (Current $) (6) x(7) ALLOCATION UNITS (13) RESIDENTIAL 7,011, ,852, , ,433 (14) SGS 2,009,265 2,210,192 83, ,026 (15) MGS - Sec 1,826,497 1,990,882 6, ,094 (16) MGS - Pri 2,739, ,876, (17) LGS 3,652, ,762, , ,540 (18) TOTAL 17,239,671 18,692, , ,774 ALLOCATION FACTORS (19) RESIDENTIAL (20) SGS (21) MGS - Sec (22) MGS - Pri (23) LGS (24) TOTAL

43 EFFICIENT ENERGY INC. ALLOCATION FACTORS - AVERAGE AND EXCESS (1) (2) (3) (4) (5) (6) Line No. CLASS NCP Average Demand Excess Demand Average Demand Component of Allocation Factor Excess Demand Component of Allocation Factor RATE CLASS kw kw kw kw kw (2) - (3) Ratio of Col. (3) Ratio of Col. (4) (1) RESIDENTIAL 2,133, ,409 1,237, (2) SGS 568, , , (3) MGS - SEC 443, , , (4) MGS - PRI 539, , , (5) LGS 625, , , (6) TOTAL 4,311,272 2,133,893 2,177, Total 1 CP kw: 4,161,248 Load Factor: 51.28% WEIGHTING FACTORS Average Demand Excess Demand System Load Factor (1- System LF) (7) Average Demand Component of Allocation Factor Alloc Factor times System LF Excess Demand Component of Allocation Factor Alloc Factor times (1- sys LF) AVERAGE AND EXCESS Allocation Factor (8) (9) (10) (11) (12) (13)

44 EFFICIENT ENERGY INC. ALLOCATION OF REVENUE & REVENUE REQUIREMENT (000's) Line No. (1) (2) (3) (4) (5) (6) (7) (8) (9) DISTRIBUTION PRIMARY / LINE TRANS. / GENERATION TRANSMISSION DIST. SUBS SECONDARY METER & SERV. 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 (6) SGS (7) MGS - SEC (8) MGS - PRI (9) LGS (10) TOTAL 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 44

45 In general, Class A s Average-Excess Demand Allocation Factor is: AED = [(Average Demand Allocation Factor) A (system-load-factor) + (Excess Demand Allocation Factor) A (1 system -load-factor)] Consider the previous slide example. Residential Class AED Allocation Factor is: AED = [(42.01%) (49.23%) + (56.82%) ( %)] = [(42.01%) (49.23%) + (56.82%) (50.77%)] = 20.68% % = 49.53% 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 baseload 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 peakload generation) 45

46 Basic Steps in Ratemaking Process Determination of Revenue Requirements/ Overall Cost of Service Components of Cost of Service Study Functionalize Costs Classify Cost Assign costs to Customer/Rate Classes Within a Jurisdiction Design Cost-Based Rate Elements for Each Rate Classes Tariff Jurisdictional Separations Allocation of Revenue Requirements Across the Jurisdictions in which the Company Operates Source: Blank & Gegax 46

47 Rate Design 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 47

48 Rate Design 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) 48

49 Rate Design 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 49

50 Rate Design 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 50

51 Fundamental Rate Elements 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 51

52 Fundamental Rate Elements: Energy and Customer Charges Energy charges are derived by taking the class energyrelated 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 52

53 Fundamental Rate Elements: Demand Charges 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 53

54 Fundamental Rate Elements: Demand Charges EFFICIENT ENERGY INC. PHYSICAL UNITS (1) (2) (3) Demand kw BILLING UNITS Energy MWh Customers No. Bills (1) RESIDENTIAL 20,574,480 7,011, ,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, (5) LGS 6,563,111 3,652, (6) TOTAL 42,664,652 17,239, ,928 Here, energy units are the figures measured at the meter. 54

55 EFFICIENT ENERGY INC. RESIDENTIAL CLASS CHARACTERISTICS PHYSICAL CHARACTERISTICS (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 REVENUE REQUIREMENTS ($000s ) (5) Demand-Related Costs 529,202 (6) Energy-Related Costs 156,593 (7) Customer-Related Costs 146,187 (8) Total Revenue Requirements 831,983 55

56 EFFICIENT ENERGY INC. Residential Pricing Strategy I Collect all energy-related costs through a per kwh charge Collect all other costs through a fixed monthly customer charge CALCULATION OF ENERGY CHARGE (1) Energy-Related Costs (000s $) 156,593 (2) Divide by MWh (000s of kwh) 7,011,202 (3) Energy Charge ($/kwh) (4) Energy Charge ( /kwh) 2.23 CALCULATION OF CUSTOMER CHARGE (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.)

57 EFFICIENT ENERGY INC. Residential Pricing Strategy II Collect all energy-related & demand-related costs through a per kwh charge Collect only customer-related costs through a fixed month customer charge CALCULATION OF ENERGY CHARGE (1) Energy-Related Costs (000s $) 156,593 (2) Add Demand-Related Costs (000s $) 529,202 (3) Costs to be Recovered 685,796 (4) Divide by MWh (000s kwh) 7,011,202 (5) Energy Charge ($/kwh) (6) Energy Charge ( /kwh) 9.78 CALCULATION OF CUSTOMER CHARGE (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.)

58 EFFICIENT ENERGY INC. Residential Pricing Strategy III Collect all energy-related & demand-related costs & half of customer-related costs through a per kwh charge Collect only half of customer-related costs through a fixed month customer charge Calculation of Energy Charge (1) Energy-Related Costs (000s $) 156,593 (2) Add Demand-Related Costs (000s $) 529,202 (3) Add Half of Customer-Related Costs (000s $) 73,094 (4) Costs to be Recovered 758,890 (5) Divided by MWh (000s kwh) 7,011,202 (6) Energy Charge ($/kwh) (7) Energy Charge ( /kwh) Calculation of Customer Charge (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)

59 EFFICIENT ENERGY INC. Residential Bill Impacts Strategy I Energy charge = ($/kwh) Customer charge = ($/month) Energy Component Fixed Component Total Bill Below-Average User(600 kwh/month) $ $ $ Average User (913 kwh/month) $ $ $ Above-Average User (1500 kwh/month) $ $ $ Strategy II Energy charge = ($/kwh) Customer charge = ($/month) Energy Component Fixed Component Total Bill Below-Average User (600 KWh/month) $ $ $ Average User (913 KWh/month) $ $ $ Above-Average User (1500 KWh/month) $ $ $ Strategy III Energy charge = ($/kwh) Customer charge = 8.50 ($/month) Energy Component Fixed Component Total Bill Below-Average User (600 kwh/month) $ $ 8.50 $ Average User (913 kwh/month) $ $ 8.50 $ Above-Average User (1500 kwh/month) $ $ 8.50 $

60 Simple Two-Part Tariff Total Bill = (customer charge) + (energy charge)*(kwh consumed) Y = a + b*x Strategy III (small a, large b) Strategy II $ (Y) Strategy I (large a, small b) $78.56 $17.00 $8.50 Average Use = kwh/month (X)

61 EFFICIENT ENERGY INC. SGS CLASS CHARACTERISTICS PHYSICAL CHARACTERISTICS (1) Total Energy Use (MWh) 2,009,265 (2) Total Customers 83,177 (3) Total Customer-Months 998,124 (4) Avg. Monthly kwh/customer 2,013 (5) Class NCP (MW) 517 (6) Billing Demand (MW) 5,586 (7) (8) Average Monthly MW/Customer Average Monthly kw/customer 5.60 REVENUE REQUIREMENTS ($000s ) (9) Demand-Related Costs $140,567 (10) Energy-Related Costs $44,075 (11) Customer-Related Costs $18,730 (12) Total Revenue Requirements $203,372 61

62 EFFICIENT ENERGY INC. SGS Rate Elements Calculation of Energy Charge (1) Energy-Related Costs (000s $) 44,075 (2) Divide by MWh (000s kwh) 2,009,265 (3) Energy Charge ($/kwh) (4) Energy Charge ( /kwh) 2.19 Calculation of Customer Charge (5) Customer-Related Costs (000s $) 18,730 (6) Customer-Related Costs ($) 18,730,032 (7) Divide by Customer Months 998,124 (8) Monthly Customer Charge ($/customer/mo.) $ Calculation of Demand Charge (9) Demand-Related Costs (000s $) 140,567 (10) Divide by Billing Demand (MW = 000s kw) 5,586 (11) Annual Demand Charge ($/kw/year) $

63 EFFICIENT ENERGY INC. Average SGS Customer's Monthly Bill Energy Component (1) Energy Charge ($/kwh) $ (2) Multiply by Avg. Cust. Monthly kwh 2,013 (3) Energy Component of Bill ($/month) $ Demand Component (4) Demand Charge ($/kw/month) $ (5) Multiply by Avg. Cust. Monthly kw 5.60 (6) Demand Component of Monthly Bill ($/month) $ Customer Component (7) Customer Component of Monthly Bill ($/month) $ Total Bill (8) Monthly Bill ($/month) $

64 EFFICIENT ENERGY INC. MGS (Secondary) CLASS CHARACTERISTICS PHYSICAL CHARACTERISTICS (1) Total Energy Use (MWh) 1,826,497 (2) Total Customers 6,820 (3) Total Customer-Months 81,840 (4) Avg. Monthly kwh/customer 22,318 (5) Class NCP (MW) 406 (6) Billing Demand (MW) 4,390 (7) (8) Average Monthly MW/Customer Average Monthly kw/customer 54 REVENUE REQUIREMENTS ($000s ) (9) Demand-Related Costs $110,045 (10) Energy-Related Costs $39,702 (11) Customer-Related Costs $1,680 (12) Total Revenue Requirements $151,427 64

65 EFFICIENT ENERGY INC. MGS (Secondary) Rate Elements Calculation of Energy Charge (1) Energy-Related Costs (000s $) 39,702 (2) Divide by MWh (000s kwh) 1,826,497 (3) Energy Charge ($/kwh) (4) Energy Charge ( /kwh) 2.17 Calculation of Customer Charge (5) Customer-Related Costs (000s $) 1,680 (6) Customer-Related Costs ($) 1,680,313 (7) Divide by Customer Months 81,840 (8) Monthly Customer Charge ($/customer/mo.) $ Calculation of Demand Charge (9) Demand-Related Costs (000s $) 110,045 (10) Divide by Billing Demand (MW = 000s kw) 4,390 (11) Annual Demand Charge ($/kw/year) $

66 EFFICIENT ENERGY INC. Average MGS (Secondary) Customer's Monthly Bill Energy Component (1) Energy Charge ($/kwh) $ (2) Multiply by Avg. Cust. Monthly kwh 22,318 (3) Energy Component of Bill ($/month) $ Demand Component (4) Demand Charge ($/kw/month) $ (5) Multiply by Avg. Cust. Monthly kw 54 (6) Demand Component of Monthly Bill ($/month) $ 1, Customer Component (7) Customer Component of Monthly Bill ($/month) $ Total Bill (8) Monthly Bill ($/month) $ 1,

67 EFFICIENT ENERGY INC. MGS (Primary) CLASS CHARACTERISTICS PHYSICAL CHARACTERISTICS (1) Total Energy Use (MWh) 2,739,745 (2) Total Customers 454 (3) Total Customer-Months 5,448 (4) Avg. Monthly kwh/customer 502,890 (5) Class NCP (MW) 514 (6) Billing Demand (MW) 5,551 (7) (8) Average Monthly MW/Customer Average Monthly kw/customer 1,019 REVENUE REQUIREMENTS ($000s ) (9) Demand-Related Costs $135,061 (10) Energy-Related Costs $57,367 (11) Customer-Related Costs $121 (12) Total Revenue Requirements $192,549 67

68 EFFICIENT ENERGY INC. MGS (Primary) Rate Elements Calculation of Energy Charge (1) Energy-Related Costs (000s $) 57,367 (2) Divide by MWh (000s kwh) 2,739,745 (3) Energy Charge ($/kwh) (4) Energy Charge ( /kwh) 2.09 Calculation of Customer Charge (5) Customer-Related Costs (000s $) 121 (6) Customer-Related Costs ($) 121,451 (7) Divide by Customer Months 5,448 (8) Monthly Customer Charge ($/customer/mo.) $ Calculation of Demand Charge (9) Demand-Related Costs (000s $) 135,061 (10) Divide by Billing Demand (MW = 000s kw) 5,551 (11) Demand Charge ($/kw) $

69 EFFICIENT ENERGY INC. Average MGS (Primary) Customer's Monthly Bill Energy Component (1) Energy Charge ($/kwh) $ (2) Multiply by Avg. Cust. Monthly kwh 502,890 (3) Energy Component of Bill ($/month) $ 10, Demand Component (4) Demand Charge ($/kw/month) $ (5) Multiply by Avg. Cust. Monthly kw 1,019 (6) Demand Component of Monthly Bill ($/month) $ 24, Customer Component (7) Customer Component of Monthly Bill ($/month) $ Total Bill (8) Monthly Bill ($/month) $ 35,

70 EFFICIENT ENERGY INC. LGS CLASS CHARACTERISTICS PHYSICAL CHARACTERISTICS (1) Total Energy Use (MWh) 3,652,962 (2) Total Customers 44 (3) Total Customer-Months 528 (4) Avg. Monthly kwh/customer 6,918,489 (5) Class NCP (MW) 608 (6) Billing Demand (MW) 6,563 (7) (8) Average Monthly MW/Customer 12.4 Average Monthly kw/customer 12,430 REVENUE REQUIREMENTS ($000s ) (9) Demand-Related Costs $149,144 (10) Energy-Related Costs $75,032 (11) Customer-Related Costs $199 (12) Total Revenue Requirements $224,374 70

71 EFFICIENT ENERGY INC. LGS Rate Elements Calculation of Energy Charge (1) Energy-Related Costs (000s $) 75,032 (2) Divide by MWh (000s kwh) 3,652,962 (3) Energy Charge ($/kwh) (4) Energy Charge ( /kwh) 2.05 Calculation of Customer Charge (5) Customer-Related Costs (000s $) 199 (6) Customer-Related Costs ($) 198,866 (7) Divide by Customer Months 528 (8) Monthly Customer Charge ($/customer/mo.) $ Calculation of Demand Charge (9) Demand-Related Costs (000s $) 149,144 (10) Divide by Billing Demand (MW = 000s kw) 6,563 (11) Demand Charge ($/kw) $

72 EFFICIENT ENERGY INC. Average LGS Customer's Monthly Bill Energy Component (1) Energy Charge ($/kwh) $ (2) Multiply by Avg. Cust. Monthly kwh 6,918,489 (3) Energy Component of Bill ($/month) $ 142,106 Demand Component (4) Demand Charge ($/kw) $ (5) Multiply by Avg. Cust. Monthly kw 12,430 (6) Demand Component of Monthly Bill ($/month) $ 282,469 Customer Component (7) Customer Component of Monthly Bill ($/month) $ 377 Total Bill (8) Monthly Bill ($/month) $ 424,952 72