ELECTRIC COST OF SERVICE AND RATE DESIGN STUDY

DRAFT Report ELECTRIC COST OF SERVICE AND RATE DESIGN STUDY Navajo Tribal Utility Authority August 2007

DRAFT NAVAJO TRIBAL UTILITY AUTHORITY ELECTRIC COST OF SERVICE AND RATE DESIGN STUDY Table of Contents Table of Contents List of Tables List of Figures Section 1 INTRODUCTION Phase I: Test Year Revenue Requirement... 1-1 Phase II: Cost of Service Model... 1-2 Step 1: Functionalization of Test Year Revenue Requirement... 1-2 Step 2: Classification of Test Year Revenue Requirement... 1-3 Step 3: Allocation of Test Year Revenue Requirement... 1-3 Phase III: Rate Design... 1-4 Section 2 REVENUE REQUIREMENT NTUA Policy... 2-1 Subsidization among Utilities... 2-1 Subsidization among Customer Classes... 2-2 Operations & Maintenance Expense... 2-2 2006 Audited O&M Expense Accounting Data... 2-2 Combined System... 2-2 O&M Adjustments... 2-2 Capital Expenditures... 2-3 Common Plant Budget Capital Expenditures... 2-3 Electric Utility Capital Expenditures... 2-3 Electric Utility Capital Improvement Plan... 2-3 Funding of Capital Expenditures... 2-3 Debt Service - Existing... 2-4 Other Adjustments... 2-4 Cash to meet TIER... 2-4 Working Capital Fund... 2-4 Other Income & Expenses... 2-4 System Growth... 2-4 Test Year Revenue Requirement... 2-4 Section 3 COST OF SERVICE MODEL Step 1: Functionalization... 3-1 H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc

Table of Contents DRAFT Allocation Factors...3-1 Direct Assignment...3-1 Labor O&M Expense...3-1 Total O&M Expense...3-2 Plant in Service...3-2 Electric Capital Improvement Plan...3-2 Functionalization Results...3-2 Step 2: Classification...3-2 Power Supply...3-3 Transmission...3-3 Distribution...3-3 Customer...3-3 Classification Results...3-3 Step 3: Allocation of the Test Year Revenue Requirement...3-4 Customer Rate Classes...3-4 Allocation Factors...3-4 Demand Allocation Factors...3-5 Energy Allocation Factors...3-5 Customer Allocation Factors...3-5 Direct Assignment...3-6 Subsidization among Customer Classes...3-6 Allocation Results...3-7 Section 4 RATE DESIGN Proposed Rate Design Options...4-3 Residential Class...4-3 Residential Electric Heat Class...4-8 General Service Class...4-13 Oil & Gas Field Service...4-15 Large Power Service Class...4-18 Public Street Highway and Private Area Lighting Class...4-20 Irrigation Class...4-21 NAPI...4-23 SRP...4-24 BISTI...4-24 Customer Class Summary...4-24 Section 5 CONCLUSIONS AND RECOMMENDATIONS ii H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT Table of Contents List of Tables Table 2-1 Projected Electric Utility Capital Improvement Plan... 2-3 Table 2-2 Test Year Revenue Requirement... 2-5 Table 3-1 Unbundled Electric Utility Test Year Revenue Requirement... 3-2 Table 3-2 Test Year Revenue Requirement Cost Classifications... 3-3 Table 3-3 Cost of Service by Customer Class... 3-8 Table 4-1 Proposed Rates - Residential... 4-3 Table 4-2 Example of Average Monthly Bills - Residential... 4-4 Table 4-3 Example of Average Monthly Bills - Residential Life Support / Senior Citizens Discount Program... 4-6 Table 4-4 Proposed Rates Residential Electric Heat... 4-8 Table 4-5 Example of Average Monthly Bills Residential-Electric Heat... 4-9 Table 4-6 Example of Average Monthly Bills - Residential Electric Heat Life Support / Senior Citizens Discount Program... 4-11 Table 4-7 Proposed Rates General Service... 4-13 Table 4-8 Example of Average Monthly Bills - General Service 15 kw Demand Customer... 4-14 Table 4-9 Proposed Rates Oil & Gas... 4-16 Table 4-10 Example of Average Monthly Bills - Oil & Gas 80 kw Demand Customer... 4-17 Table 4-11 Proposed Rates Large Power Service... 4-18 Table 4-12 Example of Average Monthly Bills - Large Power Service 20,000 kw Demand Customer... 4-19 Table 4-13 Proposed Rates Public Street Highway and Private Area Lighting... 4-21 Table 4-14 Proposed Rates Irrigation... 4-21 Table 4-15 Example of Average Monthly Bills - Irrigation 220 kw Demand Customer... 4-22 Table 4-16 Test Year Revenue Requirement Combined Results... 4-24 List of Figures Figure 1-1: Development of Test Year Revenue Requirement... 1-2 Figure 1-2: Functionalization of Test Year Revenue Requirement to Business Functions... 1-2 Figure 1-3: Allocation of Business Function Costs to Customer Classes... 1-3 Figure 1-4: General Service Class Rate Design Example... 1-4 Figure 4-1: Residential Average Monthly Bill... 4-5 Figure 4-2: Residential Average $/kwh... 4-5 Figure 4-3: Residential Life Support / Senior Citizens Discount Program Average Monthly Bill... 4-7 Figure 4-4: Residential Life Support / Senior Citizens Discount Program Average $/kwh... 4-7 Figure 4-5: Residential Electric Heat Average Monthly Bill... 4-10 Figure 4-6: Residential Electric Heat Average $/kwh... 4-10 Figure 4-7: Residential Electric Heat Life Support / Senior Citizens Discount Program Average Monthly Bill... 4-12 H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 iii

Table of Contents DRAFT Figure 4-8: Residential Electric Heat Life Support / Senior Citizens Discount Program Average $/kwh... 4-12 Figure 4-9: General Service Average Monthly Bill... 4-15 Figure 4-10: General Service Average $/kwh... 4-15 Figure 4-11: Oil & Gas Average Monthly Bill... 4-17 Figure 4-12: Oil & Gas Average $/kwh... 4-18 Figure 4-13: Large Power Service Average Monthly Bill... 4-20 Figure 4-14: Large Power Service Average $/kwh... 4-20 Figure 4-15: Irrigation Average Monthly Bill... 4-23 Figure 4-16: Irrigation Average $/kwh... 4-23 This Study has been prepared for the use of the client for the specific purposes identified in the Study. The conclusions, observations and recommendations contained herein attributed to R. W. Beck, Inc. (R. W. Beck) constitute the opinions of R. W. Beck. To the extent that statements, information and opinions provided by the client or others have been used in the preparation of this Study, R. W. Beck has relied upon the same to be accurate, and for which no assurances are intended and no representations or warranties are made. R. W. Beck makes no certification and gives no assurances except as explicitly set forth in this Study. Copyright 2007, R. W. Beck, Inc. All rights reserved. iv H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT Section 1 INTRODUCTION The Navajo Tribal Utility Authority ( NTUA ) owns, operates, and maintains a combined Electric, Natural Gas, Water, Wastewater, and Photovoltaic ( PV ) Utilities system, collectively ( Combined System ), providing service to the Navajo Nation and its customers. In February 2007, NTUA retained R. W. Beck Inc. ( R. W. Beck ) to perform a Cost of Service and Rate Design Study ( COS Study ). The scope of services for the COS Study included the development of a Test Year Revenue Requirement, functionalization of the cost of business functions, allocation of the business function costs to customer classes, and development of proposed rates for the Electric Utility. For this COS Study, a three-phase process was undertaken as described below. The description and figures are meant to provide a generalized description of the Cost of Service and Rate Design process. This section provides an overview of the methodology and process involved in the COS Study. Sections 2 through 4 describe the process in detail and provide the results of the study. Section 5 outlines our recommendations based on the results of this COS Study. Phase I: Test Year Revenue Requirement The term Revenue Requirement refers to the amount of revenue required from rates to meet the utility s financial obligations. We began with the audited 2006 accounting data by utility (Separation of Services) provided by NTUA. Known and measurable adjustments were made to the 2006 data. The adjustments to the 2006 accounting data were developed in conjunction with NTUA staff and were based on anticipated changes in utility operation and maintenance ( O&M ) expenditures, capital expenditures, and system growth. Figure 1-1 displays the process of developing the Test Year Revenue Requirement. H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

Section 1 DRAFT Utility Expense Description 2006 Accounting Data Known and Measurable Adjustments Test Year Revenue Requirement O&M Expenses Other Expenses Debt Service Rate Funded Capital Revenue Requirement Figure 1-1: Development of Test Year Revenue Requirement Phase II: Cost of Service Model Step 1: Functionalization of Test Year Revenue Requirement To the extent information was available; costs were unbundled into four separate business functions: Power Supply, Transmission, Distribution and Customer Service. Allocation factors were developed based on available information from NTUA and used to allocate the Test Year Revenue Requirement among the business functions for the Electric Utility. Figure 1-2 illustrates the unbundling of the Test Year Revenue Requirements among the business functions. Test Year Revenue Requirement Power Supply Related Service Category Transmission Related Service Category Distribution Related Service Category Customer Service Related Service Category O&M Expenses Other Expenses Debt Service Rate Funded Capital Revenue Requirement Figure 1-2: Functionalization of Test Year Revenue Requirement to Business Functions 1-2 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT INTRODUCTION Step 2: Classification of Test Year Revenue Requirement After functionalization to business functions, the costs within each business function are classified to the specific services that NTUA provides its customers. Common cost classifications include demand related or fixed costs, energy related or variable costs and customer related costs. These services influence utility cost and must be understood for a utility to appropriately price its product. Whenever possible, we directly assigned costs to specific classifications. Step 3: Allocation of Test Year Revenue Requirement Once costs (i.e., Test Year Revenue Requirement) are functionalized and classified, they are allocated to the individual customer classes based on customer usage characteristics. For this COS Study, we developed demand-related, energy-related, customer-related, and direct assignment allocation factors. Allocation factors represent class coincident peak and non coincident peak, class energy usage requirements and class number of customers. Allocation factors were developed based on available information from NTUA. Figure 1-3 shows the allocation of the classified costs from each business function to the general classes such as residential, general service, etc. The customer classes used for the COS Study are Residential, Residential Electric Heat, General Service, Oil & Gas Field Service, Large Power, Public and Street Highway & Private Area Lighting, Irrigation. Due to the nature of their special contracts, NAPI, SRP and BISTI were not included in the study. Test Year Revenue Requirement Residential Customer Class General Service Class Large Power Service Class Power Supply Demand Energy Transmission Demand Distribution Demand Customer Customer Customer Revenue Requirement Figure 1-3: Allocation of Business Function Costs to Customer Classes H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 1-3

Section 1 DRAFT Phase III: Rate Design For the Electric Utility s customer classes, rates were designed to recover the Test Year Revenue Requirement, be fair and equitable and send the proper pricing signal to customers. Figure 1-4 displays how the Cost of Service allocations were used to design rates for the General Service Class. For a General Service customer, rates typically include a monthly customer or service charge, a demand charge and an energy charge. General Service Class Revenue Requirement Monthly Service Charge Demand Charge Energy Usage Charge Customer Demand Energy Figure 1-4: General Service Class Rate Design Example The remaining sections of the report discuss in detail the Cost of Service and Rate Design process. 1-4 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT Section 2 REVENUE REQUIREMENT The various components of costs associated with operating, maintaining, and financing of improvements, renewals, and replacement of facilities are generally referred to as the Revenue Requirements of a utility. Revenue Requirement projections must consider changes in operating practices, proposed new facilities, expected cost increases and other factors that may affect the overall cost of operating and maintaining the Electric Utility. A Test Year is a common term that is a representation of a system s total actual operating costs that are to be recovered by rates. The Test Year for this COS Study represents an average year over the next five-year time period of 2008-2012. An important objective of a Test Year is to provide the means to establish rates and rate levels that will reflect the known future costs of providing service to ensure continuity and adequate service to meet the future period requirements. The determination of the Test Year Revenue Requirement as it relates to NTUA includes the various components of the costs discussed within this section for the year ending December 31, 2006. To establish a basis for developing a Test Year Revenue Requirement, NTUA provided the audited operating results for the year ending, December 31, 2006. Adjustments were then made to the 2006 data based on known or anticipated changes in system operation based on data provided by NTUA including the Common Plant Budget and the Electric Utility Capital Improvement Plan. The assumptions and adjustments related to the development of the Test Year Revenue Requirement are discussed in detail below. A summary of the Test Year Revenue Requirement is provided at the end of this section in Table 2-2. The components that make up the Revenue Requirement include operations and maintenance expense, debt service, capital paid from cash, any fund deposits and other operating income and expenses. NTUA Policy Subsidization among Utilities NTUA Management and the Board has directed that each utility (Electric, PV, Water, Wastewater, and Natural Gas) should be financially self sufficient with no subsidization among the utilities. In other words, Electric Utility revenues should pay for Electric Utility costs. For this study, a small amount of subsidization from the Electric Utility to the PV Utility was included. PV is anticipated to have rate adjustments during 2008 to minimize the level of subsidization from the Electric Utility. H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

Section 2 DRAFT Subsidization among Customer Classes NTUA Management and the Board has directed that subsidization may exist across customer classes within the Electric Utility. For example, General Service class may be set to collect revenues beyond their Cost of Service and the Residential class rates may be set to under collect revenues compared to the class Cost of Service. As a result, the excess revenues from the General Service class may be used to subsidize the Residential class. Operations & Maintenance Expense O&M expenses were approximately 82 percent of the Test Year Revenue Requirement as shown in Table 2-2. Test Year O&M expenses were based on 2006 NTUA O&M expenses. Adjustments to the 2006 O&M expenses were based on data provided by and discussions with NTUA. Details of the 2006 O&M data and the adjustments are described below. 2006 Audited O&M Expense Accounting Data Electric Utility O&M expenses of $40.1 million were based on 2006 audited accounting data provided by NTUA. Combined System Evaluating the unbundled Cost of Service for any one particular utility requires the examination of costs for all five utilities (Electric, Natural Gas, Water, Wastewater, and PV). This examination is required as NTUA operates in a manner such that certain departments are responsible for all five utilities. The operating cost of these departments with joint responsibility was reviewed and allocated to each of the five utilities based on how costs were incurred. NTUA provided this data in their Separation of Services. O&M Adjustments 1. O&M Plan Moderate Level The existing O&M expenses were estimated to increase by approximately $3,055,473 because the 2006 level of O&M expenditures was below average. 2. Labor Contract Expense NTUA plans on a labor cost increase of approximately $610,646 due to employees unionizing. 3. Consultant Fees - The Test Year Revenue Requirement includes a reduction related to outside services including consultant and accounting fees. This adjustment was already accounted for in the data provided by NTUA 4. PV Utility the Electric Utility was assumed to fund the PV Utility by approximately $400,000 annually. 5. Inflation Inflation rates for O&M were approximately 2.3 percent as provided by the Blue Chip Economic Indicators Inc. published in March 2007. 2-2 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT REVENUE REQUIREMENT Capital Expenditures Common Plant Budget Capital Expenditures The Common Plant Budget of $5.1 million annually was provided by NTUA. The Common Plant Budget items were directly allocated to a specific utility if possible. Items that were not directly related to a specific utility were allocated based on labor (number of employees). Approximately $2.7 million of the $5.1 million capital expenditures were assumed to be provided by the Electric Utility. The Common Plant Budget expenses were assumed to be paid for with debt. Electric Utility Capital Expenditures Electric Utility Capital Improvement Plan The Electric Utility Capital Improvement Plan was provided by NTUA for years 2007-2012. The Electric Utility Capital Improvement Plan annual expenditures for years 2007 2012 are provided below in Table 2-1. Table 2-1 Projected Electric Utility Capital Improvement Plan Year Projected Capital Expenditure 2007 $14,245,075 2008 23,730,762 2009 18,222,339 2010 17,913,181 2011 15,793,181 2012 17,215,181 Total $107,119,721 The projected Electric Utility major capital expenditures for the period 2007-2017 total approximately $93 million in 2007 dollars. Inflation for capital was approximately 3.0 percent as provided by NTUA. In addition to capital requirements related to system, the Electric Utility Capital Improvement Plan includes funding for ongoing renewal and replacement projects. Funding of Capital Expenditures The COS Study incorporates a policy assumption that capital expenditures will be funded by a combination of customer contributions, cash and debt. NTUA expects to H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 2-3

Section 2 DRAFT receive approximately 46 percent of the capital expenditures in contributions from customers and 54 percent will be paid for with long-term debt and cash. We assumed that NTUA will issue new debt each year, as construction funds are needed for capital projects. The estimated average debt service payment for the study period was included in the Test Year Revenue Requirement. Debt Service - Existing Debt service payments of $3.2 million were assumed for the period 2008-2012 based amortization schedules provided by NTUA. Other Adjustments Cash to meet TIER Additional margin was required to maintain a Times Interest Earned Ratio ( TIER ) or Debt Service Coverage Ratio ( DSCR ) ratio. Working Capital Fund Based on discussions with NTUA, we have assumed that NTUA will build working capital reserves by approximately $1.2 million per year in the development of the Test Year Revenue Requirement. In the near term, NTUA has assumed to use short-term borrowing to meet cash requirements. Other Income & Expenses Other Income & Expenses include interest earned on funds, surcharge and penalty income and other miscellaneous items. NTUA reports that it earns approximately three percent return annually on its cash reserves. Other Income & Expenses were estimated based on information provided by NTUA. System Growth System growth adjustments were three percent per year based on data provided by NTUA. Test Year Revenue Requirement Table 2-2 shows the components of the Test Year Revenue Requirement. The major components of the Test Year Revenue Requirement are outlined below: O&M Expenses - approximately 81.6 percent of the total. Debt Service payments (existing and proposed) - approximately 7.4 percent of the total. 2-4 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT REVENUE REQUIREMENT Cash for capital from TIER 10.3 percent Working Capital - 2.0 percent Capital paid from Current Earnings 2.9 percent Photovoltaic 0.7 percent Other Income and Expenses decreases Revenue Requirement by 5.0 percent Table 2-2 Test Year Revenue Requirement Revenue Requirement Components Revenue Requirement Operations & Maintenance Expense O&M - Purchased Power $27,780,914 O&M - Labor 10,149,407 O&M - Non Labor 10,699,345 O&M - Total $48,629,666 Debt Service Existing - Principal $ 1,559,897 Existing - Interest 1,609,680 Proposed - Principal 309,011 Proposed - Interest 917,071 Debt Service Total $ 4,395,659 Capital Paid from Current Earnings $1,746,167 Cash for Capital from TIER 6,149,700 PV 395,615 Working Capital Fund Deposit 1,215,742 Subtotal Revenue Requirement $62,532,549 Less Other Income & Expenses 2,962,157 Test Year Revenue Requirement $59,570,392 NTUA s financial goals include a minimum DSCR of 2.00 and a TIER of 2.00 for years 2008, 2009 and 2010 for the Electric Utility. For years 2011 and 2012, the ratio could fall below a 2.00 but must remain above a 1.25 according to Rural Utilities Service ( RUS ) requirements. The Test Year Revenue Requirement results in an average DSCR of 2.49 and a TIER of 2.00. H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 2-5

DRAFT Section 3 COST OF SERVICE MODEL Step 1: Functionalization We begin the unbundling process by functionalizing the Test Year Revenue Requirement (Cost of Service) to utility business functions. It is important to note that unbundled services described herein reflect the full cost of providing such services including direct costs, overhead costs, other income or expenses and capital costs associated with each function. The Test Year Revenue Requirement as described in Section 2 was unbundled into the following four business functions: Power Supply Transmission Distribution Customer Service Allocation Factors For each business function, the Test Year Revenue Requirement was unbundled through the application of the following allocation factors: Direct Assignment Labor O&M Expense Total O&M Expense Plant in Service Electric Capital Improvement Plan Direct Assignment Direct assignment of cost to functions was used whenever possible, and as its name implies, directly assigns certain costs to a specific business function. For example, purchased power cost is directly related to the Power Supply function. Labor O&M Expense Labor was used to allocate certain joint costs among the business functions. For example, administrative and general ( A&G ) costs were allocated to the various functions using labor O&M as an allocation factor. This is due to a primary function of A&G is to support managers and the labor force. H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

Section 3 DRAFT Total O&M Expense Total O&M Expense was used to allocate the Working Capital Fund deposits among the business functions. This is due to the primary function of Working Capital to provide cash for O&M expenses. Plant in Service Plant in service (assets) was used to allocate NTUA s existing debt service. A record of how the historical loan funds were spent was not available; therefore, plant in service was the best allocator available for debt service. Electric Capital Improvement Plan The plant placed into service as a result of the Electric Capital Improvement Plan was used to allocate NTUA s proposed debt service. Functionalization Results The unbundled Cost of Service is shown in Table 3-1. Table 3-1 Unbundled Electric Utility Test Year Revenue Requirement Percent of Business Function Amount Total Power Supply 27,706,047 46.5% Transmission 3,380,184 5.7% Distribution 26,983,178 45.3% Customer 1,500,983 2.5% Test Year Revenue Requirement 59,570,392 100.0% Power Supply cost is approximately 46.5 percent of the Electric Utility Test Year Revenue Requirement. Transmission expenses represent 5.7 percent of the Test Year Revenue Requirement NTUA owns very little transmission assets relative to other business functions. Step 2: Classification Once costs were unbundled into functions, they were classified as demand related, energy related, customer related or direct assignment. Demand related costs are generally fixed and do not vary with customer usage. Demand related costs represent the cost incurred by NTUA to meet system demands. Energy related costs are costs that very with customer usage. Theses costs typically include purchased power or fuel usage. Customer related costs are costs that are incurred in serving customers including accounting, billing and meter reading. These costs vary based on the number of customers. Finally, direct assignments are costs related directly and assigned directly to a customer class. By function, the classifications are listed below: 3-2 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT COST OF SERVICE MODEL Power Supply Power supply includes the demand, energy, and wheeling charges for purchased power. The cost to NTUA varies with NTUA s demand and energy. However, the majority of NTUA s purchased power contracts are under fixed demand payments. Therefore, Power Supply costs were allocated according to: Energy Transmission Transmission plant is fixed assets in the ground built to meet the peak demands of NTUA. Transmission plant costs do not vary with the level of generation or customers. Therefore Transmission costs were allocated according to: Demand Distribution Distribution plant is fixed assets in the ground built to meet the demands of NTUA. Distribution plant costs do not vary with the level of generation, but do vary with the number of customers. Therefore, Distribution costs were allocated to: Demand Customer Customer Customer expenses were classified based on NTUA staff expenses related to supporting the accounting, meter reading, and sales functions. Therefore, customer costs were allocated to: Customer Classification Results For the Test Year, NTUA s costs are classified as follows in Table 3-2: Table 3-2 Test Year Revenue Requirement Cost Classifications Business Function Amount Percent of Total Demand Related $24,691,411 41.4% Energy Related 27,706,047 46.5% Customer Related 7,172,934 12.0% Test Year Revenue Requirement $49,570,392 100.0% H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 3-3

Section 3 DRAFT Step 3: Allocation of the Test Year Revenue Requirement For each business function, the cost of providing services to NTUA customers was identified and allocated to the customer classes as described in Section 1. In Table 3-3 at the end of this section, the Test Year Revenue Requirement is compared to the estimated Test Year Rate Revenues to determine the estimated over or under collection by class. Test Year Rate Revenues are the revenues calculated based on the current rates and the Test Year electricity sales. Customer Rate Classes For the purposes of performing the COS Study, the following customer classes were utilized: Residential Residential Electric Heat General Service Oil & Gas Field Service Large Power Service Irrigation Public Street Highway & Private Area Lighting Customers under special contracts that were not included in the study are: NAPI SRP BISTI Allocation Factors Allocation factors were developed based on available information from NTUA and number of customers used to allocate the costs among customer classes including billed energy, demand, and service voltage level. Allocation factors assign costs to each rate class based on 2006 customer usage information for each class. Allocation factors take into consideration wholesale contracts, infrastructure costs and customer care requirements to serve customers in each rate class. Without specific allocation factors, all costs for the Electric Utility could be shared equally between all customers. Although this approach is straight forward, it does not recognize that different customers create different costs on the system. Depending upon the service requirements of a particular customer, the actual cost incurred by NTUA to service these loads may vary substantially. Therefore, specific allocation factors that recognize these cost differentials were developed in an effort to equitably assign NTUA s actual costs. 3-4 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT COST OF SERVICE MODEL The following paragraphs discuss development of allocation factors utilized to allocate fixed, variable and customer related costs among NTUA's various rate classes. Demand Allocation Factors Capacity (fixed- or demand-related) costs are those costs incurred to maintain a utility system in a state of readiness to serve, enabling it to meet the total combined demands of its customers. Capacity costs include the portion of operating and maintenance expenses, debt service, capital expenditures, and other costs that do not vary materially with the quantity of usage or which cannot be designated specifically as a customer or variable costs. Demand allocation factors used include: Class Non-Coincident Peak ( NCP ) the non-coincident peak represents the peak demand the class places on the system. The demand related components of distribution expense were allocated to the various customers classes based on the average annual non-coincident peak. Distribution facilities are typically sized based on system localized demands. Therefore, class peaks, regardless of the timing of their occurrence are equitable allocators of these types of fixed costs. Class Coincident Peak ( CP ) the coincident peak for each class represents the class demand at the time of the system peak. CP for peak season ( 4CP ) fixed costs related to transmission expense were generally allocated on a 4 CP basis reflecting the size of these facilities to meet the system load. The four peak months used to develop the 4CP were November, December, January, and February based on NTUA s monthly load profiles. Energy Allocation Factors Energy or variable costs are costs that vary directly with energy usage, including such items as fuel, energy-related purchased power, and a portion of maintenance expenses. Energy allocation factors used include: Net Energy for Load Net Energy for Load is the load at NTUA s transmission delivery points required to meet the needs of the system. For NTUA, it can be defined as the total power purchases or retail sales plus losses. Net Energy for Load was used to allocate the purchased power energy costs among the rate classes with the exception of NAPI, SRP and BISTI. NAPI, SRP and BISTI s exact purchased power costs are known and those costs were directly assigned and removed from the COS Study. Customer Allocation Factors Customer costs are defined as those costs that are related to the number of customers. Included in the customer-related costs are the costs associated with meter reading, billing and other customer-related accounting services. The customer allocation factors were based on the average number of customers in each class. H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 3-5

Section 3 DRAFT In apportioning certain customer-related costs to the various customer classifications, weighted customer allocation factors were utilized. Weighting customer classes recognizes that servicing certain types of customers requires more effort than other types of customers. Weighting factors were developed upon discussion with NTUA staff. Customer allocation factors used include: Number of Customers In the Customer business function, Sales expense was allocated using the number of customers in each of the rate classes. Sales expense is incurred as a result of having and maintaining customers. Meter Reading In the Customer business function, Meter Reading expense was allocated using the number of customers in each of the rate classes and the types of meters each customer class uses. Large General Service and industrial classes typically have more sophisticated meters or multiple meters that require effort beyond just an energy reading. Therefore, typically large General Service or industrial meters are weighted heavier than residential meters thereby allocating more meter reading expenses per customer to these classes. This allocation factor takes into account those customers that have automatic meter reading (AMR) meters. Billing - In the Customer business function, billing expense was allocated using the number of customers in each of the rate classes and the level of effort involved in billing each customer in the rate class. Direct Assignment Costs that are directly assigned are those costs that are directly attributable to a customer or customer class. Directly Assignable costs include: PV to Residential The PV related expense is passed directly through the Cost of Service study and allocated to the Residential class. PV s customers are only residential customers and therefore the PV expense allocated fully to the Residential customer class as shown in the next section. Subsidization among Customer Classes NTUA Management has directed that subsidization may exist across customer classes within the Electric Utility. For example, General Service class may be set to collect revenues beyond their Cost of Service and the Residential class rates may be set to under collect revenues compared to the class Cost of Service. As a result, the excess revenues from the General Service class may be used to subsidize the Residential class. NTUA Management assumptions: Residential rate increase capped at 20 percent for the average 400 kwh use customer 3-6 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT COST OF SERVICE MODEL Residential Electric Heat rate increase capped at 22 percent for the average 1,000 kwh use customer Discounted rates for the Life Support / Senior Citizen Residential and Residential Electric Heat customers Irrigation (for crops) average rate increase for the class overall capped at 20 percent. Allocation Results The results of the Cost of Service analysis by rate class are summarized in Table 3-3.. H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 3-7

Section 3 DRAFT Table 3-3 Cost of Service by Customer Class Class 2006 Revenue Less PCA (1) 2006 Sales Test Year Less PCA Test Year Sales 2006 Revenue Less PCA Test Year Revenue Less PCA Revenue Change Adjusted Test Year (4) Adjusted Test Year Revenue Change from 2006 ($) (MWh) ($) (MWh) ($/MWh) ($/MWh) (%) ($) ($/MWh) (%) Residential (ER-01) 11,416,249 156,614 18,393,913 176,270 72.89 104.35 43.2% 15,393,913 87.33 19.8% Residential Electric Heat (ER-02) 1,515,274 23,139 2,249,736 26,044 65.48 86.38 31.9% 2,079,736 79.86 21.9% General Service (EG-03) 16,981,814 222,161 21,723,402 250,044 76.44 86.88 13.7% 23,766,434 95.05 24.3% Oil & Gas Field Service (EL-04) 140,192 1,938 156,708 2,181 72.33 71.84-0.7% 174,531 80.01 10.6% Large Power Service (EL-05) 6,408,461 112,537 8,792,545 126,662 56.95 69.42 21.9% 9,827,458 77.59 36.3% Public Street Highway & Private Area Lighting (EL-06) (2) (3) 1,549,981 13,031 1,594,582 14,667 8.75 9.50 8.6% 1,672,014 9.50 8.6% Irrigation (EL-10) 50,417 769 63,715 769 65.53 82.82 26.4% 60,515 78.66 20.0% NAPI (Special Contract) 63,469 1,564 63,469 1,564 40.57 40.57 0.0% - - - SRP (Special Contract) 2,030,902 22,606 2,030,902 22,606 89.84 89.84 0.0% - - - BISTI (Special Contract) 2,432,752 43,620 2,432,752 43,620 55.77 55.77 0.0% - - - Total 42,589,511 597,980 57,501,724 664,427 71.22 86.54 21.5% 52,974,601 88.79 21.5% (1) Purchased Power Cost Adjustment ( PCA ) (2) Street Lighting is shown on a number of bulbs and a $/light basis (3) PCA does not apply (4) Adjustments include a $2.2 million credit to the Residential customers for the Colorado River Storage Project ( CRSP ) energy allocation to NTUA due to Native customers. It also includes subsidization for the Residential and Irrigation (crops) classes. (Note: Excluding NAPI, SRP and BISTI, the revenue change is 23.7%) 3-8 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT Section 4 RATE DESIGN Rate Design is the culmination of a COS Study where the rates and charges for each customer classification are established in such a manner that the total Test Year Revenue Requirement of the utility will be recovered in the most equitable manner, consistent to the extent reasonable and practical in accordance with specific NTUA Board policy. In general, proposed rate structures that are developed and submitted for consideration and adoption should meet the following objectives: Rates should be simple and understandable. Rates should be equitable among customer classes and individuals within classes, taking into consideration the costs incurred to serve each customer class. Rates should be designed to encourage the most efficient use of the utility s system. Rates may take into other important factors such as competitive concerns, conservation, etc. In addition, utilities may review or set their policy objectives regarding rates and rate making based on many objectives including the following: Promote or maintain subsidization across utilities. For example, one utility may over collect revenues to help support another utility that is under collecting revenues. NTUA has made the policy decision to eliminate subsidization across utilities. Promote or maintain subsidization within a utility, but across different customer classes. For example, the Utility s policy might be to promote subsidization of the residential customers by the General Service customers. In this case, the General Service customers rate would be higher than their Cost of Service and the Residential rate would be lower than their Cost of Service. The over collection of revenues from the General Service class would be used to balance the under collection of revenues from the Residential class. NTUA policy has been to promote and maintain subsidization across the customer classes. Specifically, general service and industrial customers subsidize the residential customers. Promote or maintain subsidization within a customer class. For example, the utility may want to charge the customers that are high energy users more to over collect revenues. These excess revenues could then be used to assist customers that utilize less energy such as retired persons, fixed income customers, etc. NTUA currently has subsidization within customer classes. Because NTUA H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

Section 4 DRAFT prefers not to raise the monthly service charge to the level that would reduce subsidization, the subsidization within the customer classes will continue. Promote conservation or promote more consumption. For example, a utility may have a contracted volume for power purchases from a wholesaler and any purchases over this set amount are charged at a much higher rate. Therefore, if its customers use more than this contract amount, the utility experiences higher unit costs to serve its customers. As a result, the utility may want to introduce inclining blocked or tiered rates. These block or tier rates send a signal to the customer that as their usage increases, so does the unit price. This pricing strategy promotes conservation. A utility may want to level the receipt of revenues from customers over the year. Seasonal usage utilities, like electric, may bring the utility high revenues in the winter months and low revenues in the summer months. If the utility wants to help balance out the variations of the revenues, the utility may decide to increase the fixed portion, or Service Charge, of the tariff rate. By shifting more of the costs into a fixed rate that is collected each month and not based on usage, the utility can help level out the revenues received over the year. NTUA prefers not to raise the monthly service charge to smooth out the receipt of revenues. Current NTUA electric rates reflect the following design elements: A monthly service charge All customer classes except Large Power Service have a monthly service charge An energy charge based on usage Residential, Oil & Gas, Large Power Service and Irrigation have a flat energy rate General Service has a declining block rate where the unit cost decreases with increasing electricity use A demand charge based on peak demand General Service has a declining block rate where the unit cost decreases with increasing electric demand Oil & Gas, Large Power Service and Irrigation have a flat demand rate A PCA charge. Currently the PCA is adjusted monthly to collect any purchased power costs not already collected through rates. All customer classes except Public Street Highway and Private Area Lighting pay the monthly PCA charges Based on discussions with NTUA, it was determined that the structure of the rates should be updated to reflect the following: Maintain the $0.03574 per kwh in the base rate. The PCA rate should continue to be adjusted monthly to ensure NTUA collects the revenues in a timely manner. Service charges were adjusted for inflation for 20 years by NTUA. 4-2 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT RATE DESIGN Proposed Rate Design Options The Rate Design information is organized by NTUA customer class. For each customer class, two rate options were designed: Option A: recover revenues with pre-determined subsidization levels for the Residential and Irrigation customers. Therefore, under Option A proposed rates, over and under collection among rate classes is apparent. Option B: recover the Test Year Revenue Requirement based on the Cost of Service results. This option does not consider NTUA policy decisions. For each customer class, the proposed rates and example monthly customer bills are presented. In addition, graphs were included to provide a visual understanding of how current rates and proposed rates compare to the COS Study results based on energy usage and load factor. Proposed rates compared with current rates are shown in the following tables. Residential Class The Cost of Service results show that the Residential class is projected to under-collect by approximately 43 percent as shown in Table 3-3. Option A was designed to achieve a specified level of subsidization for the Residential customers. The Residential class was estimated to under-collect by approximately $3 million under Option A. Option B reflects the proposed rates based on the Cost of Service results. Energy related expenses were assumed to be recovered through the base rate as well as the PCA charge. Demand related expenses were assumed to be recovered through the Energy Charge since Residential customers do not have demand meters and are not charged a demand rate. All customer related expenses were assumed to be recovered through the Service Charge. Table 4-1 Proposed Rates - Residential Current Rates Option A Proposed Rates Change (%) Option B Cost of Service Change (%) Service Charge $3.00 $5.75 92% $11.92 297% Energy Charge $0.0660 $0.0740 12% $0.0753 14% Revenue $15,313,289 $18,400,702 Cost of Service (2) 18,393,913 18,393,913 Difference (1) ($3,080,625) $6,789 (1) The Cost of Service results do not equal zero. Rates were designed using four decimal places to match Cost of Service results as closely as possible. (2) Does not reflect CRSP adjustment. H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 4-3

Section 4 DRAFT Table 4-2 presents example monthly bills for Residential customers. Based on a customer s energy usage, the estimated monthly bill was calculated using the current rates. The Option A proposed rate levels the Residential rate increase across all customers usage patterns. In effect, Option A proposed rates allow high energy users to subsidize the low energy users within the Residential class. Option A rates were designed to limit the average Residential customer at 400 kwh usage per month a 20 percent rate increase. Option B proposed rates were developed based on the cost of providing service to each customer. As shown in Figures 4-1 and 4-2, the low energy user customers are charged significantly below their Cost of Service. Table 4-2 Example of Average Monthly Bills - Residential Average Monthly Energy (kwh) Current Rate ($/month) Option A Proposed Rates ($/month) Option A Proposed Rates Bill Change (%) Option B Cost of Service Average Bill ($/month) Option B Cost of Service Bill Change (%) 300 (1) 22.80 27.95 22.6% 34.51 51.4% 400 29.40 35.35 20.2% 42.04 43.0% 500 36.00 42.75 18.8% 49.57 37.7% 600 (2) 42.60 50.15 17.7% 57.10 34.0% 700 49.20 57.55 17.0% 64.63 31.4% 800 55.80 64.95 16.4% 72.16 29.3% 900 62.40 72.35 15.9% 79.69 27.7% 1,000 69.00 79.75 15.6% 87.22 26.4% 1,100 75.60 87.15 15.3% 94.75 25.3% 1,200 82.20 94.55 15.0% 102.28 24.4% 1,300 88.80 101.95 14.8% 109.81 23.7% 1,400 95.40 109.35 14.6% 117.34 23.0% (1) Summer usage levels (2) Winter usage levels Figure 4-1 represents the average monthly bills for different usage levels. Figure 4-2 represents the average energy price for various energy usage levels within the Residential class. As the figure shows, the cost of serving low energy usage customer is significantly higher than what the existing and proposed tariffs charge. 4-4 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT RATE DESIGN Residential Average Monthly Bill $120 $90 $60 $30 Current Rate Option A - NTUA Proposal Option B - COS $0 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500 kwh Usage per Month Figure 4-1: Residential Average Monthly Bill Residential Average $/kwh $0.15 $0.14 Current Rate $0.13 Option A - NTUA Proposal $0.12 Option B - COS $0.11 $0.10 $0.09 $0.08 $0.07 $0.06 $0.05 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500 kwh Usage per Month Figure 4-2: Residential Average $/kwh H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 4-5

Section 4 DRAFT Table 4-3 presents example monthly bills for Life Support / Senior Citizens Discount Program customers in the Residential class. Life Support / Senior Citizens Discount Program customers receive the following discounts: Service Charge: $0 Energy Charge: 10 percent below the Residential class PCA Charge: no discount As a result, Option A proposed rates offer the Life Support / Senior Citizens Discount Program customers in the Residential class the largest discount because many of the fixed costs of serving customers were contained in the Service Charge. Table 4-3 Example of Average Monthly Bills - Residential Life Support / Senior Citizens Discount Program Average Monthly Energy (kwh) Current Rate ($/month) Option A Proposed Rates ($/month) Option A Proposed Rates Bill Change (%) Option B Cost of Service Average Bill ($/month) Option B Cost of Service Bill Change (%) 300 21.21 19.98-5.8% 34.51 62.7% 400 27.35 26.64-2.6% 42.04 53.7% 500 33.49 33.30-0.6% 49.57 48.0% 600 39.63 39.96 0.8% 57.10 44.1% 700 45.77 46.62 1.9% 64.63 41.2% 800 51.91 53.28 2.6% 72.16 39.0% 900 58.05 59.94 3.3% 79.69 37.3% 1,000 64.19 66.60 3.8% 87.22 35.9% 1,100 70.33 73.26 4.2% 94.75 34.7% 1,200 76.47 79.92 4.5% 102.28 33.8% 1,300 82.61 86.58 4.8% 109.81 32.9% 1,400 88.75 93.24 5.1% 117.34 32.2% Figure 4-3 represents the average monthly bills for different usage levels. Figure 4-4 represents the average energy price for various energy usage levels within the Residential Life Support / Senior Citizen Discount Program customers. As the figure shows, the cost of serving low energy usage customer is significantly higher than what the existing and proposed tariffs charge. 4-6 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07

DRAFT RATE DESIGN Residential - Life Support / Senior Citizen Average Monthly Bill $120 $105 $90 $75 $60 $45 Current Rate Option A - NTUA Proposal Option B - COS $30 $15 200 300 400 500 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500 kwh Usage per Month Figure 4-3: Residential Life Support / Senior Citizens Discount Program Average Monthly Bill Average $/kwh $0.15 $0.14 $0.13 $0.12 $0.11 $0.10 $0.09 $0.08 $0.07 $0.06 $0.05 Residential - Life Support / Senior Citizen Current Rate Option A - NTUA Proposal Option B - COS 200 400 600 800 1,000 1,200 1,400 kwh Usage per Month Figure 4-4: Residential Life Support / Senior Citizens Discount Program Average $/kwh H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07 R. W. Beck 4-7

Section 4 DRAFT Residential Electric Heat Class The Cost of Service results show that the Residential Electric Heat class is projected to under-collect by approximately 32 percent as shown in Table 3-3. Option A was designed to achieve a specified level of subsidization. Option B reflects the proposed rates based on the Cost of Service results. Energy related expenses were assumed to be recovered through the base rate as well as the PCA charge. Demand related expenses were assumed to be recovered through the Energy Charge since Residential customers do not have demand meters and are not charged a demand rate. All customer related expenses were assumed to be recovered through the Service Charge. Table 4-4 displays the rates. Table 4-4 Proposed Rates Residential Electric Heat Current Rates Option A Proposed Rates Change (%) Option B Cost of Service Change (%) Service Charge $7.00 $13.35 91% $11.97 71% Energy Charge $0.0580 $0.0656 13% $0.0731 26% Revenue $2,080,215 $2,248,489 Cost of Service (2) 2,249,736 2,249,736 Difference (1) ($169,520) ($1,247) (1) The Cost of Service results do not equal zero. Rates were designed using four decimal places to match Cost of Service results as closely as possible. (2) Does not reflect CRSP adjustment. Table 4-5 presents example monthly bills for Residential Electric Heat customers. Based on the customer s energy usage, the estimated monthly bill was calculated using the current rates, Option A proposed rates and Option B proposed rates. The Option A proposed rate levels the Residential Electric Heat rate increase across all customers usage patterns. In effect, Option A proposed rates allow high energy users to subsidize the low energy users within the Residential Electric Heat class. Option A rates were designed to limit the average Residential Electric Heat customer at 1,000 kwh usage per month to a 22 percent rate increase. Option B proposed rates were developed based on the cost of providing service to each customer. As shown in Figure 4-5, the low energy usage customers are charged significantly below their Cost of Service. 4-8 R. W. Beck H:\004330\02-01634\WP\R1083 DRAFTREPORTrv1 081307.doc 8/13/07