The URL can be used to link to this page

03-21-2017 HUCCPMINUTES Special Meeting — Hutchinson Utilities Commission Tuesday, March 21, 2017 Call to order — 7:00 a.m. President Morrow called the meeting to order. Members present: President Monty Morrow; Vice President Anthony Hanson; Secretary Mark Girard; Commissioner Robert Wendorff; Commissioner Don Martinez; General Manager Jeremy Carter. Others present: Dave Hunstad, Jared Martig, and Kim Koski. The purpose of the special meeting was to discuss the proposed cost of service and 2017 rate study. A draft request for proposal (RFP) along with the 2005 and 2012 rate study reports were sent to the Board for their review prior to this meeting. (RFP and rate studies attached.) GM Carter presented a general overview of the proposed cost of service study, steps involved in the study, historical rate study information, and HUC's changes since the 2012 study. HUC's goal is to align charges with costs to secure incoming revenue as HUC may not be recovering enough revenue through its monthly fixed charge to cover fixed costs. (Presentation attached.) GM Carter requested feedback from the Board on the initial draft request for proposal. GM Carter mentioned the proposal has language that allows firms to separately bid on each division or combined. This should provide HUC the greatest options in firms submitting bids and pricing. The request for proposal will be on the next regular commission meeting agenda for approval. After approval, GM Carter will send out the request for proposal to about six to eight firms for consideration to perform the 2017 rate study. There being no further business, a motion was made by Vice President Hanson, seconded by Secretary Girard to adjourn the meeting at 8:08 a.m. Motion was unanimously carried. Mark Girard, Secretary ATTEST: Monty Mo ow, President Cost of Service &Rate Study Workshop Tuesday, March 21, 2017 7:00 a.m. �CHINSO,y Overview of Cost of Service Studies Determine the level and structure of the rates that a utility should charge its customers. The starting point in assessing the reasonableness of the rates to be charged by a utility is to evaluate the cost of providing service. Utilities perform cost of service studies to determine what it costs to provide service to its customers, both in total and by individual rate class (e.g. residential, commercial, industrial). Effective Analytic Tool to design rates that equitably assign costs to each customer rate class. Mutually beneficial to both utility and customer. Methodologies established by industry experts Accepted by regulatory commissions Approved by courts Methods must determine as accurately as possible what it costs for the utility to serve a class of customers �tCNIHSO,y Principal• Steps of a Cost of Service Study (11ti I IT 10 Functional Assignment Costs are assigned (or "functionalized") to the major functional groups related to providing service. Classification 13 Major cost drivers are identified (or "classified") for each group of functionally assigned costs. D, Allocation The functionally assigned and classified costs are directly assigned (or "allocated") to the customer classes on the basis of an allocation factor that is representative of the service characteristic that drives the utility's costs. (Joint Costs) �jCH^INS,# Principal Steps of a Cost of Service Study �TI L ITIIt" Cost of Service Study Functional Classification Allocation Assignment Demand - Purchased Residential Power Costs Energy Demand All Distribution Commercial Costs Costs Customer Industrial Other Customer Rate Design/Study A bedrock principle of Rate Making (Rate Studies) is to recover fixed costs through fixed charges and variable costs through variable charges. Fixed Charges: Meter Charges & Demand Charges Variable Charges: kWh energy charge Intra -class subsidies can result if this principle is not followed. Also puts fixed cost recovery at risk. Example... Demand Costs recovered through kWh charge 000 Historical Rate Studies & HUC Changes �t11,ITIES 2005 —COS &Unbundled Rate Study (2004 Test Year) 2012 —COS &Unbundled Rate Study (2010 Test Year) 2017 —COS &Rate Design Study (2016 Test Year?) Previous Rate Study Information Changes 2005 PCA - $55.70/Mwh, 2016 PCA - $54/Mwh 2005 FCA - $7.85/MCF,. 2016 FCA - $5.25/MCF Phased in industrial rates (2015 — 2017) Operating and Capital Reserve Policies Over estimated Retail Sales &Expenses (Gas &Electric) Sales for Resales significantly different, energy & gas costs Questions???? ME Final Report Electric and Gas Cost -of -Service .and Unbundled Rate Study Hutchinson Utilities, Minnesota December 2005 1 IDecember 6, 2005 Hutchinson Utilities Commission 225 Michigan St. SE Hutchinson, MN 55350 Commission Members: Subject: Electric and Gas Cost of Service and Unbundled Rate Study Report Transmitted herewith is the report of our study of the retail electric and gas rates for Hutchinson Utilities ("HU"). This study has been completed to determine recommended adjustments in Hutchinson's retail electric and gas rates. There are three principal components to the study. The first of these is an examination of the revenue requirements for Hutchinson's Electric and Gas Divisions. To remain financially sound, Hutchinson's Electric and Gas Divisions must produce sufficient revenues through their retail rates to cover their revenue requirements. The second component of the rate study is the cost -of -service' analysis. The electric and gas cost -of -service analyses are performed to detcmitne the allocated cost of providing service to each class of customers. Section 4 shows unbundled rates for each customer class in the Electric and Gas Divisions. These are a result of the cost -of -service analysis. The final component of the rate study is the design of new electric and gas rates. The new rates have been designed, taking into account the results of the revenue requirements, cost -of -service analyses and unbundled analyses- Section 5 of the report presents our recommendations and the proposed rates developed as a result of our analyses. Thank you for the opportunity to have prepared this study for Hutchinson. We would like to express our appreciation for the valuable assistance provided by Hutchinson staff during the performance of this study. Sincerely, R. BECK, erl,David A.Bg Principal and St ;'..1.! ;:;vl / N)4'!: I !et.;:):: i w Ga 4 C:CI Rd![ S:uJi',Rr;--!Fier zr.c rp4'!: 13 do C ; 4por,itc (.er,e` l ,rr iic 31,1� S'. ,^•a.i .:MN :: i? i Ph iro VA . 'i 1.7 H . ! i ;A (i-510 '49.1-8396, - --- — Table of Contents List of Tables List of Figures Section 1 Introduction .......................... Hutchinson Utilities Final Report Table of Contents ..........................................................1-1 Section 2 Estimated Operating Results — Existing Rates......................................2-1 ElectricDivision................................................................................................2-1 Historical Electric Requirements.............................................................2-1 Estimated Electric Requirements..............................................................2-2 Estimated Revenue Requirements............................................................2-3 Generation and Purchased Power Expenses.................................2-3 Operating and Maintenance Expenses..........................................2-5 Other Income and Expenses.........................................................2-5 Transfers/Services-In-Kind to the City.........................................2-5 Capital Improvements...................................................................2-5 DebtService.................................................................................2-6 Revenue Requirements.................................................................2-6 Estimated Revenues — Existing Rates......................................................2-6 Estimated Operating Results...................................................................2-6 GasDivision.......................................................................................................2-8 Estimated Gas Requirements...................................................................2-8 Estimated Revenue Requirements...........................................................2-8 Purchased Gas Expenses..............................................................2-8 Operating Expenses......................................................................2-9 Contributions to the City..............................................................2-9 Other Income and Expenses.......................................................2-10 Capital Improvements........•........................................................2-10 DebtService...............................................................................2-10 Revenue Requirements...............................................................2-10 Estimated Revenues — Existing Rates....................................................2-10 Estimated Operating Results.................................................................2-1 1 Gas and Electric Combined Cash Reserves....................................................2-11 81600 Table of Contents 1 Section 3 Cost -of -Service Study..............................................................................3-1 ElectricDivision..............•.•----...........................................................................3-1 Classification of Costs..............................................................................3-1 ' Allocation to Customer Classifications....................................................3-2 Demand Allocations.....................................................................3-2 EnergyAllocations.......................................................................3-3 ' Customer Allocations...................................................................3-3 Revenue Allocations ...................................•• -----............................3-3 Cost -of -Service Study Results.................................................................3-3 ' GasDivision.......................................................................................................3-5 Classificationof Costs ..............................................................................3-5 Allocation to Customer Classifications....................................................3-6 , Demand Allocations...................................................•--•--............3-6 Commodity Allocations..............................................................3-7 Customer Allocations...................................................................3-7 1 Revenue Allocations.....................................................................3-7 Cost -of -Service Study Results.................................................................3-7 ' Section 4 Unbundled Rates.....................................................................................4-1 Electric Rate Components..................................................................................4-1 WholesalePower......................................................................................4-1 ' Transmission............................................................................................4-1 Distribution...............................................................................................4-1 Customer..................................................................................................4-2 , Contributionto the City............................................................................4-2 Unbundled Electric Rates ..................... .........4-2 GasRate Components.......................................................................................4-5 ' Purchased Gas/Production.............................................................. :........ 4-5 Transmission.........................................................................................•..4-5 Distribution...............................................................................................4-5 ' Customer.............................................................................. .4-5 ----------------••- Contributionto the City............................................................................4-5 UnbundledGas Rates...............................................................................4-5 Section5 Proposed Rates........................................................................................5-1 Electric Division Rate Design............................................................................5-1 , Propose(] Rates........................................................................................5-1 PowerCost Adjustment............................................................................5-3 ' StreetLight Costs....................................................................................5-4 Rate Comparison with Xcel Energy.........................................................5-5 Estimated Operating Results at Proposed Rates.......................................5-5 GasDivision Rate Design..................................................................................5-7 ' ProposedRates.....................................................................•---...............5-7 Fuel Cost Adjustment ..................• ---•--.....................................................5-7 Rate Comparison with Xcel Energy.........................................................5-9 ' HU Gas Service Contract with 3M...........................................................5-9 Additional Recommendations................................................................5-10 Table of Contents Estimated Operating Results at Proposed Rates.....................................5-10 Gas and Electric Combined Cash Reserves.....................................................5-10 RateComparisons............................................................................................5-11 Transfersto the City.........................................................................................5-12 List of Tables Section 2 Historical Electric Requirements(MWh).............................................. ...................... 2-2 Estimated Electric Requirements(MWh)....................................................................2-2 Estimated Electric Puchases and Generation (M Wh)..................................................2-3 Cost of Electric Generation and Market Purchases....................................................2-3 CMMPA Purchased Power Rate..................................................................................2-4 Estimated Electric Generation and Purchased Power Expenses..................................2-4 Estimated Electric Annual Sales Revenues: Existing Rates........................................2-6 Estimated Electric Division Annual Operating Results: Existing Rates ....................2-7 Estimated Gas Requirements (MCF)...........................................................................2-8 Estimated Wholesale Gas Commodity Rates Per MNj IBtu..........................................2-9 Estimated Wholesale Gas E.xpense.............................................................................2-9 Estimated Gas Annual Sales Revenues: Existing Rates............................................2-11 Estimated Gas Division Annual Operating Results: Existing Rates .........................2-11 Estimated Combined Cash Reserves: Existing Rates..............................................2-12 Section 3 Classification of Electric Division Costs: 2004 'Test Year ......................................... 3-2 Electric Division: Comparison of Revenues and Allocated Cost of Service: 2004 Test Year...................................................................................•.............3-4 Electric Division: Percentage Comparison of Revenues and Allocated Cost . of Service: 2004 Test Year..............................................................................3-4 Classification of Gas Division Costs: 2004 Test Year...............................................3-2 Gas Division: Comparison of Revenues and Allocated Cost of Service: 2004 TestYear..........................................................................................................3-4 Gas Division: Percentage Comparison of Revenues and Allocated Cost of Service: 2004 Test Year...................................................................................3-4 Section 4 Unbundled Electric Costs......•.....................................................................................4-3 UnbundledElectric Rates...........................................................................................4-4 UnbundledGas Costs...................................................................................................4-6 UnbundledGas Rates..................................................................................................4-7 auoo iii Table of Contents Section 5 Current and Proposed Retail Electric Rates ............................................... Street Lights Cost Analysis......................................................................... Average Monthly Bill Comparison............................................................. Electric Division:Estimated Annual Operating Results Proposed Rates..... Current and Proposed Retail Gas Rates ...................................................... Average Monthly Bill Comparison............................................................. Gas Division: Estimated Annual Operating Results Proposed Rates.......... Estimated Combined Cash Reservices Proposed Rates ................................ List of Exhibits Exhibit 2-A: Electric Operating Results: Existing Rates Exhibit 2-13: Gas Operating Results: Existing Rates Exhibit 3-A: Classification of Electric Test Year Revenue Requirements: 2004 Test Year Exhibit 3-13: Classification of Electric Plant -In Service: 2004 Test Year Exhibit 3-C: Electric Demand, Energy and Customer Allocation Factors: 2004 "best Year Exhibit 3-D: Allocation of Electric Revenue Requirements: "Test Year 2004 Exhibit 3-E: Classification of Gas Test Year Revenue Requirements: 2004 Test Year Exhibit 3-F: Classification of Gas Plant -in Service: 2004 Test Year Exhibit 3-G: Gas Demand, Commodity and Customer Allocation Factors: 2004 "Test Year Exhibit 3-11 Demand Cost Allocation by Average -Excess Demand Exhibit 3-1: Allocation of Gas Revenue Requirements: Test Year 2004 Exhibit 5-A: Residential Electric Rate: Monthly Bill Comparison Graph Exhibit 5-13: Small General Service Electric Rate: Summer Monthly Bill Comparison Graph Exhibit 5-C: Small General Service Electric Rate: Winter Monthly Bill Comparison Graph Exhibit 5-D: 150kW Large General Service Electric Rate: Monthly Bill Comparison Graph Exhibit 5-E: Residential Gas Rate: Monthly Bill Comparison Graph Exhibit 5-F: Commercial Gas Rate: Monthly Bill Comparison Graph r iv 1H1600 I I 1 Y i I I 1 1 1 I I i 1 1 I I I Table of Contents This report has been prepared for the use of the client for the specific purposes identified in the report. 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 report, 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 report. Copyright 2005 R. W. Beck, Inc. All rights reserved. 81400 v Section 1 INTRODUCTION 'l'he City of Hutchinson, Minnesota through Hutchinson Utilities (Hi1), owns, operates and maintains a municipal utility which provides retail gas and electric service to its residents and businesses. HU provides electric service to approximately 6,800 retail customers through its Electric Division. HUC provides natural gas service to approximately 5;060 customers through its Gas Division. Overall responsibility for the operations of the Electric and Gas Divisions is charged to the Hutchinson Utilities Commission which has the authority to review and set the rates for service charged by Hu. 1 R. W. Beck has performed a cost -of -service and rate design study for HU's Electric and Gas Divisions. The study include(] an analysis of -estimated revenue requirements for 2005 - 2009 (the "Study Period"), the preparation of detailed cost -of -service analyses based on a 2004 test year, a rate analysis and the development of proposed new electric and gas rates for each customer classification. This report summarizes the analyses undertaken in our study of HU's retail electric and gas rates and describes the results of our study and otir recommendations. The cost -of -service analysis performed for each of HU's retail electric and gas customer classifications was based on fully embedded -costs. The rate design portion of the study includes recommendations on retail rates for each customer classification. s 1 it .1 e e I B 1600 Section 2 ESTIMATED OPERATING RESULTS - EXISTING RATES To remain financially sound, HU's electric and gas rates must produce sufficient revenues to cover the cost of providing electric and natural gas service and to permit I the continued replacement and expansion of its facilities. These expenditures are commonly referred to as "revenue requirements" and consist of normal operating expenses, capital improvements and additions, contributions to the City and non- operating expenses. Periodically, a utility must examine its current and forecasted revenues and expenses to verify that the total revenue, including interest earnings and miscellaneous income is sufficient to cover all revenue requirements. This part of the study compares projected income earned from revenues at present rates to the expenses expected to be incurred in serving customers during the Study Period. In order to determine the adequacy of HU's existing electric and gas rates, we have worked with the HU personnel to develop estimates of the annual revenues and revenue requirements for the Study Period. These estimates serve as the basis for determining the overall level of revenue recovery and provide a foundation for our cost -of -service analyses. The analyses and assumptions incorporated in our development of estimated revenues and revenue requirements are described below. Electric Division Historical Electric Requirements HU purchases the majority of its electric requirements and generates the remainder of I its requirements. In 2005, HU signed an agreement with Central Minnesota Municipal Power Agency (CMMPA) to purchase 30 MW of capacity and energy. HU will continue to generate a portion of its requirements and purchase from the open market Iany amounts needed beyond CMMPA purchases and generation. In addition to providing electric service to its retail customers, HU sells to resale I customers, depending on market prices. HU's historical electric requirements for 2000 through 2004 are shown in the table below. Both retail sales and resale sales have fluctuated during 2000-2004, causing a small reduction in total purchases and generation between 2000 and 2004. B 1600 Section 2 Historical Electric Requirements (MWh) Year Purchases Generation Total 2000 206,847 113,748 320,595 2001 302,052 49,606 351,658 2002 282,626 38,909 321,535 2003 290,920 23,053 313,973 2004 306,780 11,919 318,699 Estimated Electric Requirements HU's forecasted electric requirements for the Study Period are shown in the table below. These requirements reflect sales to HU's retail customers, as well as electricity supplied for street and traffic lights, l -IU internal use and system losses. Resale sales have been eliminated from the sales forecast, due to wide fluctuations in historical sales as well as the changing market conditions that determine the amount of resale sales. Internal energy requirements represent an average system growth rate of 1.9 percent per year. Estimated Electric Requirements (MWh) Year Retail Street & Traffic Losses 8 Total Annual Sales Lights & Utility Other I'► Percent Use Change 2005 304,265 6,015 18,673 328,953 2006 311,064 6,135 9,000 326,199 (0.8%) 2007 316,987 6,258 9,000 332,244 1.9% 2008 323,038 6,383 9,000 338,421 1.9% 2009 329,221 6,510 9,000 344,732 1.9% )1) Incudes 9.673 MWh resale sales recorded as of ocloter 2D6-5 Yea, lo Cale The "Estimated Purchases and Generation" table below reflects the new purchased power arrangement HU began in 2005. 11U will purchase 30 MW of capacity and energy from Central Minnesota Municipal Power Agency (CMMPA), equivalent to 262,800 MWh per year. It is assumed that HIJ will generate 5 percent of its requirements and will purchase the remainder of its requirements from the market. 2-2 Hutchinson Utilities B 160 M I�I I it -.1 Ll 1 w .1 i t w 7 7 7 117 7 r r 7 7 Ci r J 7 7L Dl_ Estimated Operating Results - Existing Rates Estimated Electric Purchases and Generation (MWh) Year CMMPA Generation Market Total (per MWh) Purchases $78.47 Purchases 2006 2005 262,800 21,952 44,201 328,953 2006 262,800 16,310 47,089 326,199 2007 262,800 16,612 52,832 332,244 2008 262,800 16,921 58,700 338,421 2009 262,800 17,237 64,695 344,732 Estimated Revenue Requirements A forecast of HU's Electric Division expenses, called revenue requirements, has been prepared for the Study Period. These revenue requirements consist of generated and purchased power costs and operating and non-operating expenses. Estimated revenues from the sale of electricity at current rates during the Study Period have been forecasted and compared to the revenue requirements. The estimates of the Study Period revenues and revenue requirements are contained as Exhibit 2-A at the end of this Section. Estimated revenue requirements for the Study Period were developed based on HU's annual financial reports for 2000 through 2004, year-to-date and budgeted expenses for 2005 and forecasts of expenses for 2006-2009, as well as discussions with HU personnel. The assumptions used in these estimates are explained in detail below. Generation and Purchased Power Expenses R. W. Beck has used the estimated cost of natural gas to forecast the total cost of gas for HU's generation during the Study Period, as shown in the following table. It is assumed that the cost for market purchases will be 90 percent of the cost of gas fired generation in any year. B 1600 Cost of Electric Generation and Market Purchases R. W. Beck 2-3 Cost of Gas Fired Market Purchases Generation (per MWh) (per MWh) 2005 $78.47 $70.62 2006 $92.16 $82.94 2007 $75.50 $67.95 2008 $65.50 $58.95 2009 $57.17 $51.46 R. W. Beck 2-3 0 Section2 The following table shows the rate paid by HU for its purchases from ('entral Minnesota Municipal Power Agency, beginning in 2005. A 6.9 percent increase in the rate components has been assumed to begin in 2006 and an additional 1.15 percent increase in these same rate components has been assumed to begin in 2007. These rate increases are based on the rate increase plans announced by Xcel Energy, under whose rates HU purchases its energy from CMMPA. CMMPA Purchased Power Rate (Current) Rate Component Oct -May Jun -Sep Customer charge/month $25.04 $25.04 Demand W 111month $4.26 $6.91 On Peak/ kWh $0.037407 $0.037407 Off Peak/ kWh $0.026943 $0.026943 Load Factor Credit ($0.007) ($0.007) Trans Credit/ kW -mo ($1.18) ($1.18) Interrupt Credit/kW-mo ($2.25) ($2.25) Fuel Cost AdjlkWh $0,01 $0.01 Resource Adj/kWh $0.000751 $0.000751 Conserv Irnprvmt Rider (% of bill) 1.49% 1.49% The tables below show the estimated wholesale power and energy expense for the projected purchases shown in the table earlier in this Section. Purchased gas for generation and purchased power expenses for 2006-2009 are shown below and in Exhibit 2-A. Estimated Electric Generation and Purchased Power Expenses Year CMMPA Cost Market Purchases Transmission and MISO Fees Gas Cost for Generation Total 2005 $12,217,589 $3,006,544 $168,000 $1,687,62.1 $17,085,671 2006 $11,609,685 $3,905,757 $180,000 $1,613,717 $17,309,160 2007 $11,717,213 $3,589,819 $180,000 $1,344,777 $16,831,809 2008 $11,717,213 $3,460,256 $180,000 $1,186,896 $16,544,366 2009 $11,717,213 $3,329,016 $180,000 $1,054,104 $16,280,333 2-4 Hutchinson Utilities 01600 r is F. a Estimated Operating Results - Existing Rates HU generation expenses other than the cost of natural gas are shoxv-n in the forecasted operating results in Exhibit 2-A. Operating and Maintenance Expenses ' Operating and maintenance expenses incun-ed are related to Production and Distribution facilities and services. Customer Accounting and Collecting, Administrative and General expenses and Depreciation are also part of operating and maintenance expenses. Expenses for 2005 have been based on October year-to-date recorded expenses and discussion with Fit] staff. For the years 2006-2009, expenses were escalated from 2005 expenses by 2.5 percent per year, except for Distribution Operation, which is expected to have a higher level of increase, based on discussions with HU staff. Sales expense is based on 1.5 percent of retail sales revenue. A new expense line item has been added for "Power Generation Pipeline" for payments to the Gas Division for the use of the new natural gas pipeline constructed by HU. A new expense line items has also been added for "Transmission Payment" to MISO, based on the assumption that HU will join MISO as a transmission owner. Other Income and Expenses Revenues from non-utility operations are classified as Other Income and include interest income and other miscellaneous sources of income_ Interest income for the Study Period has been based on earning 3.5 percent on forecasted cash reserves. A new income line item has been added for "Transmission Credit", based on the assumption that HU will receive credits from MISO as a transmission owner. Other f`spertses include the interest portion on IIU's debt service payments for the gas pipeline. In past years the Electric Division has paid 50 percent of the interest and principal payments on the bond issue for the gas pipeline. Beginning in 2006, the Electric Division will change the payment method for its use of the gas pipeline. Instead of making interest and principal payments, the Electric Division will make a direct payment to the Gas Division for use of the gas pipeline for its power generation needs." Transfers/Services-In-Kind to the City "Transfers and services -in-kind are provided to the City of Hutchinson by HU through a cash transfer based on Elie Utility's net worth and through the provision of' street lighting electricity and maintenance service at no charge to the City. In 2005 the total amount of the transfer payment fur the Electric Division is scheduled to be $681,345. Capital Improvements The capital improvements included in the forecasted operating results are based on HU's Capital Improvements Plan, plus discussion with HU staff. Capital improvements during the Study Period %%,ill be financed through a combination of' curTerit operating revenues and cash reserves. 0 d131600 R. W. Beck 2-5 Section 2 1 Debt Service Through 2005, the Electric Division has paid 50 percent of the principal and interest payments on the bonds used to finance the gas pipeline. Beginning in 2006, the Electric Division will make a payment to the Gas Division for use of the gas pipeline that is equivalent to 50 percent of the debt service payments. 7'he Gas Division will then assume full payment of the gas pipeline debt service. Revenue Requirements ' Each category included in the calculation of revenue requirements has been described above. The revenue requirements indicate the amount of funds on an annual basis necessary to operate the system. Estimated Revenues - Existing Rates Estimated operating revenues have been developed by R. W. Beck for the Study Period to compare to forecasted revenue requirements during the same period. Operating revenues consist of revenues from the sale of- retail electricity, including Power Cost Adjustment (PCA) revenues, plus sale of electricity for resale, and revenues from security lights and pole rental fees. Due to the relatively higher cost of the energy component of electricity purchases than the current power cost base rate, considerable revenue is forecasted as coming from the PCA. Revenues from the 1'CA are estimated to increase from $4,813,829 in 2004 to $9,130,563 in 2005. Estimated Electric Annual Sales Revenues Existing Rates Year 2005 2006 2007 2008 2009 Sales Revenues $15,888,561 $16,236,939 $16,530,572 $16,830,426 $17,136,643 Before PCA PCA 9,090,093 8,860,442 8,136,251 7,609,642 7,102,615 Revenues Other Operating 1,175,050 _639150 639,750 639,75.0 _639,750 Revenues Total Operating $26,153,704 $25,737,131 $25,306,572 $25,079,818 $24,879,008 Revenues Estimated Operating Results Based on the estimates described above, we have prepared the following tables which summarize the Electric Division's estimated annual operating results for the Study Period. As shown below, net income based on the Electric Division's existing rates 2-6 Hutchinson Utilities B1600 —..—..Estimated Operating Results - Existing Rates I will not be sufficient to cover basic operating expenses during the Study Period. Our summary of HU's combined cash reserves is shown at the end of this Section. Our estimate of the Electric Division's annual operating results is presented in detail in Exhibit 2-A at the end of this Section. Estimated Electric Division Annual Operating Results Existing Rates — Year 2005 2006 2007 2008 2009 Estimated $26,153.704 $25,737,131 $25,306,572 $25,079,818 $24,879,008 Revenues Estimated Revenue 25,080,448 26.128,338_ 25.851.198 25350,293 25,972,868 Requirements Net Income $1,073,256 ($391:207) ($544,626) ($870,476) ($1,043,860) Operating Income as Percent of Net 6.0% (3.5%) (3.8%) (4.5%) (4.6%) Assets Net Income as Percent of Net 2.7% (1.0%) (1.4%) (2.2%) (2.5%) Assets H 1600 R. W. Beck 2-7 Section 2 1 Gas Division Estimated Gas Requirements HU's forecasted gas consumption for the Study Period is shown in the table below. , The consumption reflects sales to HU's retail customers and system losses. We have forecasted gas consumption based on historical usage levels and used this consumptions as the basis for our estimates of annual operating revenues and costs for purchased gas. Estimated Revenue Requirements A forecast of HU's Gas Division expenses, called revenue requirements, has been prepared for the Study Period. "These revenue requirements consist of' purchased gas costs and operating and non-operating expenses. Estimated revenues frorn the sale of gas at current rates during the Study Period have been forecasted and compared to the revenue requirements. The estimates of the Study Period revenues and revenue requirements are contained as Exhibit 2-B at the end of this section. Estimated revenue requirements for the Study Period were developed based on HU's annual financial reports for 2000 through 2004, budgeted expenses for 2005-2006, estimated wholesale gas bills, and discussions with IIU personnel. The assumptions used in these estimates are explained in detail below. Purchased Gas Expenses Projected capacity and commodity expenses for 2.005-2009 are based on forecasted rates and expenses developed through discussions with }IU staff. Due to the construction of the gas pipeline, transportation costs paid to a wholesale gas supplier ' have dropped significantly from past levels. HU has a significant portion of its gas commodity purchases locked in at a fixed rate. The commodity rates shown below 2-8 Hutchinson Utilities B 160 Estimated Gas Requirements (MCF) Year Retail Sales Losses Total Annual'Percent Change 2005 1,295,396 12,954 1,308,350 0.9% 2.006 1,306,936 13,069 1,320,006 0.9% 2007 1,320,006 13,200 1,333,206 1.0% 1 2008 1,333,206 13,332 1,346,538 1.0% _2009 1,346,538 _ _ 13,465 1,360,003 _ 1.0% Estimated Revenue Requirements A forecast of HU's Gas Division expenses, called revenue requirements, has been prepared for the Study Period. "These revenue requirements consist of' purchased gas costs and operating and non-operating expenses. Estimated revenues frorn the sale of gas at current rates during the Study Period have been forecasted and compared to the revenue requirements. The estimates of the Study Period revenues and revenue requirements are contained as Exhibit 2-B at the end of this section. Estimated revenue requirements for the Study Period were developed based on HU's annual financial reports for 2000 through 2004, budgeted expenses for 2005-2006, estimated wholesale gas bills, and discussions with IIU personnel. The assumptions used in these estimates are explained in detail below. Purchased Gas Expenses Projected capacity and commodity expenses for 2.005-2009 are based on forecasted rates and expenses developed through discussions with }IU staff. Due to the construction of the gas pipeline, transportation costs paid to a wholesale gas supplier ' have dropped significantly from past levels. HU has a significant portion of its gas commodity purchases locked in at a fixed rate. The commodity rates shown below 2-8 Hutchinson Utilities B 160 Estimated Operating Results _Existing Rates reflect a weighted average of the locked --in gas purchases and gas purchases on the market at forecasted market prices. Estimated Wholesale Gas Commodity Rates Per MMBtu Year Commodity Rate 2005 $8.53 2006 $8.16 2007 $7.40 2008 $6.55 2009 $5-72 The table below shows the estimated wholesale gas capacity and commodity expense for the projected purchases shown in the table earlier in this Section. This table reflects the total gas expenses for supplying; 3M and }]U's other retail customers. Contributions to the City Contributions are made to the City of FIutchinson through a cash transfer from the Gas Division. Currently, the value of this cash transfer is set each year by HU and the City- It is estimated to range between $300,000 and $355,000 per year during the Study Period. 81600 R. W. Beck 2-9 Estimated Wholesale Gas ExpenseYear - Capacity Cost Commodity Cost Total 2005 $8,147 $9,805,168 $9,813,315 2006 $6,000 $10,771,2.47 $10,777,247 2007 $6,000 $9,865,723 $9,871,723 2008 $6,000 $8,819,588 $8,825,588 2009 $6,000 $7,775,765 $7,781,765 ' Operating Expenses Operating and maintenance expenses incurred are related to Production and Distribution facilities and services. Customer Accounting and Collecting, Depreciation and Administrative and General expenses are also part of operating and maintenance expenses. Sales Expenses relate to conservation improvements. Expenses for the Study Period have been estimated based on the 2005 and 2006 budgets provided by HU staff and escalation of budgeted levels for 2007-2009. Contributions to the City Contributions are made to the City of FIutchinson through a cash transfer from the Gas Division. Currently, the value of this cash transfer is set each year by HU and the City- It is estimated to range between $300,000 and $355,000 per year during the Study Period. 81600 R. W. Beck 2-9 Section 2 Other Income and Expenses Revenues from non-utility operations are classified as Other -Net, Interest Income and Miscellaneous Income. Other -Net includes late payment penalties. Levels for these payments are higher in 2005 than expected in later years of the Study Period. Interest income is based on interest earned from cash reserves. As cash reserves are negative, no interest income is forecast during the Study Period. Other Expenses, in addition to the Contributions described above, include the interest portion of debt service payments for the gas pipeline. Beginning in 2006, the Gas Division is expected to assume full responsibility for both the principal and interest for the gas pipeline debt. Capital Improvements Planned improvements for the Gas Division during the Study Period range between $375,000 and $2,515,000 per year. Capital improvements will be paid from cash reserves. Debt Service HU has gas revenue bonds issued to pay for the gas pipeline. Interest payments for the bonds have been included in the forecasted operating results shown in detail in Exhibit 2-13. Principal payments have been included in the calculation of annual operating reserves. As discussed earlier, the Gas Division will assume full responsibility for interest and principal payments !or the gas pipeline, beginning in 2006. Revenue Requirements Each category included in the calculation of revenue requirements has been described above. The revenue requirements indicate the amount of' funds on an annual basis necessary to operate the system. Estimated Revenues - Existing Rates Estimated operating revenues have been developed by R. W. Beck For the Study Period to compare to forecasted revenue requirements during the same period. The revenues are based on rates in effect in 2005. Operating revenues consist of revenues from the sale of retail gas, including Fuel Cost Adjustment (FCA) revenues, gas sales to 3M and transportation fees from New Ulm and the Electric Division for use of the gas pipeline. As the cost of gas is forecasted to be higher than,the current FCA base rate during 2005-2009, the monthly FCA is expected to be an additional charge to retail customers during all of the months of the Study Period. 2-10 Hutchinson Utilities B 1600 w t w E .1 A w w rEstimated Estimated Gas Division Annual Operating Results Operating Results - Existing Rates Estimated Gas Annual Sales Revenues Year Existing Rates 2007 2008 2009 Year 2005 2006 2007 2008 2009 $12,094,074 Retail Sales Before FCA $4,322,125 $4,422,686 $4,467,608 $4,512,992 $4,558,845 11,142,426 FCA Revenues 4,307,993 4.592,318 4,259,401 3,544,274 2,773,910 $951,648 Sales to 3M 3,104,240 3,765,810 3,163,891 2,808.613 2,511,319 Transportation 650,000 2,250,000 2,250,000 2,250,000 2,250,000 8.2% Revenues Net Income as - Total Operating $12,384,358 $15,030,813 $14,140,900 $13,115,879 $12,094,074 _ 3.3%_ Revenues d Estimated Operating Results Based on the estimates described above, we have prepared the following table which summarizes the Gas Division's estimated annual operating results for the Study Period. As shown below, net income based on the Gas Divisions existing rates will be sufficient to cover operating expenses. Our estimate of the Gas Division's annual operating results is presented in detail in Exhibit 2-B at the end of this Section. 14 Gas and Electric Combined Cash Reserves Combined cash reserves for the Electric and Gas Divisions are presented below. INReserves at existing rates are estimated to be ($364,481) by the end of 2009. B1600 R. W. Beck 2.-11 Estimated Gas Division Annual Operating Results Existing Rates Year 2005 2006 2007 2008 2009 Estimated Revenues $12,384,358 $15,030,813 $14,140,900 $13,115,879 $12,094,074 Estimated Revenue Requirements 12.,006,162 13.971,082 13,117,900 12,116,109 11,142,426 Net Income $378,196 $1,059,732 $1,022,999 $999,771 $951,648 Operating Income as Percent of Net Assets 3.6% 8.0% 8.3% 8.3% 8.2% Net Income as Percent of Net Assets _ _ 1_2% — 3.4% — 3.5% _ — — 3.4% _ 3.3%_ 14 Gas and Electric Combined Cash Reserves Combined cash reserves for the Electric and Gas Divisions are presented below. INReserves at existing rates are estimated to be ($364,481) by the end of 2009. B1600 R. W. Beck 2.-11 Section 2 Estimated Combined Cash Reserves Existing Rates Year 2005 2006 2007 2008 2009 Beginning of Year $1,900,000 $2,933,851 $1,525,142 $1,313,250 $1,176,330 Cash in Bank = Plus Electric Net 1,073,256 (391,207) (544,626) (870,476) (1,043,860) Income Plus Gas Net Income 378,196 1,059,132 1,022,999 999,771 951,648 Plus Big Stone Expense Reimbursement 200,000 0 0 0 0 Less Electric Capital (900,000) (1,947,000) (3 385,500) Improvements ) ' Less Gas Capital (1,700,000) (2,514,735) (1,062,000) (576,500) (374,500) Improvements Less Debt Service Principal (970,000) (975,000) (995,000) (1,025,000) (1,055,000) Plus Depreciation 2 952,399 3,047,897 3,186.235 3,282,285 3.366,401 End of Year Cash in $2,933,851 $1,525,142 $1,313,250 $1,176,330 ($364,481) –Bank --- — -- ------ -- 2-12 Hutchinson Utilities BI600 i Other Income Ioresast Operating Itcsenue 44,570 Sales-Elecinc Encr_ev ?006 Sales Int Resale _ 2008 Net Inc Clher Suurces 124.978.654 Secunry Lmlthts ' Pole Rental $24.239,258 Total OperatingRr.rnmte 500,000 Operating Expenses 2000 fltoducnan Ctpcta^nn 2001. Production Maintenance 2004 P'+ -r Gener2non Pipeline 517,722.698 Purch Gas.6cncratiu1J 519,627,120 Purchased Lias -Resale 906,827 Purch Power-Intrmal L1se 753,612 Sys Cttt1 & Ertginecring 278,157 Transmission Payment 87,956 Transmission Ope-anon 110,063 Transmission Maint 12,0.15 Distrmburion Operation 11.580 Visviberion Maintenance 1 I ,05.1 Oust Acctg & Collecting 7,244 Sales Expense Ly¢19 Administrative & General 19.015.422 D ep r e c is ti on - E l e c tri c 15,838,296 Tool Olxrating Expenses 20.397.718 Operating Income r 9 r r r Exhibit 2-A Other Income Ioresast Hutchinson utilities. Minnesota 44,570 Transmission Credit ?006 Electric Operaliny, Results _ 2008 Miscellaneous Income 124.978.654 Esisling.Rates ' Loss on Disposal $24.239,258 Histcr:cal 500,000 Other Expenses 2000 2001 2001. 2003 2004 S1B4O17,720 517,722.698 S14.97h.392 519,627,120 519.994,766 906,827 2,756,490 753,612 584,61] 278,157 76.555 87,956 94,811 110,063 11 I,8 i 0 12,0.15 11,796 11.580 10.558 1 I ,05.1 2265 7,244 1901 Ly¢19 1,717 19.015.422 10581,194 15,838,296 1033}('0? 20.397.718 1.171.497 845.167 1.067,5.11 2.981.388 2.000.991 506.768 479,385 428,672 420,346 303.U84 4,936201 3.257,484 7,003.224 0 0 6,457,241 9,906,199 6,477,243 10,561,643 11.812,650 1,400 251 155 1,730 783 49,945 57,934 150,720 210,115 52,068 355,404 358,496 415,061 462,028 388,795 183.165 151,857 174,839 178 70B 121,186 165,379 287,534 306.867 797,067 304,367 1,206,870 1,791,592. 1,75 3,044 1,431,773 1,513,807 L02-4117 "7 7,-,31 LL4 i u 15 Zi(.! 53 2.195122 16,70'7,227 18,915.125 14,613,782 18,604,650 18.617,959 2,308,195 1,666,059 1,224,514 1,728,351 1,7.19,859 r 9 r r r Exhibit 2-A Other Income Ioresast Other - Net 44,570 Transmission Credit ?006 Interest Income _ 2008 Miscellaneous Income 124.978.654 Gain on Disposal ' Loss on Disposal $24.239,258 7Dial Other Income 500,000 Other Expenses 500,000 Miscellaneous Lxpenses 139.48 1 Interest fapensc 125,7511 Total Other Expenses 125.750 Contribution to the Cin• 12,000 Nun -Operating Ind (Expo) 12.000 Net 6mcome 1,6(1Q aper Income as :'. o1 Net Asses 2CDS Net Income %of'Net Assets p� Revenue Requirements r 9 r r r Exhibit 2-A 1.7},406 170,493 BY -'.250 914,556 937;120 351.500 423,000 433,515 444,414 455,525 1,100,000 1,100,000 1,100,000 1. I OO,UCO 1,090,749 1,613.717 1,3.14,777 1,186,896 1,054,104 596,873 455,000 455,000 455,000 455,000 15 ,752.962 15.695,443 15,491,032 15,357.469 15,776,229 462,696 397,000 406,975 417,0911 477,576 0 1,545,500 1,545,500 1,54 5,500 1,545.5W) 100 7,000 7,050 2,101 2,154 8,570 6,0011 6,150 6,304 6,461 797,000 312,500 370.313 328,370 336,578 151.13$ 167,500 171,6118 175,980 1BO,379 220,608 2.18,178 244,117 250,236 256,492 76,287 193,17.8 196,991 366,601 363.589 1.819,812 1,981,772 2,032,3.11 2,083,150 2,135,219 211rW-L72 2135 2.193.1 OZ i 25L12 ;a!1M 23.794.471 17,140,875 26,031.816 26,887,438 76,BD4,848 3,359,233 (1.403,744) (1.575,313) (1,807,621) (1,911.840) 84,487 170,209 Ioresast 77,647 44,570 _ ___ 2065 ?006 2001 _ 2008 _ 2009 124.978.654 S?5.097,381 524.666,822 S14,440,068 $24.239,258 1.027.569 500,000 500.000 500,000 500,000 139.48 1 I?5,7`0 125,7511 125,750 125.750 12,000 12,000 12.000 12.000 12,000 1,6(1Q 2 000 2CDS 2,Qgl 2,000 2[•.151.704 75,73'1.1]1 25.366.577 25,079.819 24,8/9.069 ' 1.7},406 170,493 BY -'.250 914,556 937;120 351.500 423,000 433,515 444,414 455,525 1,100,000 1,100,000 1,100,000 1. I OO,UCO 1,090,749 1,613.717 1,3.14,777 1,186,896 1,054,104 596,873 455,000 455,000 455,000 455,000 15 ,752.962 15.695,443 15,491,032 15,357.469 15,776,229 462,696 397,000 406,975 417,0911 477,576 0 1,545,500 1,545,500 1,54 5,500 1,545.5W) 100 7,000 7,050 2,101 2,154 8,570 6,0011 6,150 6,304 6,461 797,000 312,500 370.313 328,370 336,578 151.13$ 167,500 171,6118 175,980 1BO,379 220,608 2.18,178 244,117 250,236 256,492 76,287 193,17.8 196,991 366,601 363.589 1.819,812 1,981,772 2,032,3.11 2,083,150 2,135,219 211rW-L72 2135 2.193.1 OZ i 25L12 ;a!1M 23.794.471 17,140,875 26,031.816 26,887,438 76,BD4,848 3,359,233 (1.403,744) (1.575,313) (1,807,621) (1,911.840) 84,487 170,209 61,102 77,647 44,570 26,054 20,000 20,000 70,000 20,000 0 1,598,200 1,598,200 1,5911,2UO 1,598 00 276,594 232,670 40,808 116,764 56,408 35,000 109,949 113,771 107,7117 88,059 45,794 235,504 '71,761 190,027 71,611 2,0(J11 0 0 0 0 0 490 0 901,9.11 21,749 0 0 0 0 0 L9�71) 9 9 Q Q 0 4 4 4 9 346,401 588,871 111,671 1,216,364 194,331 63,054 1,778,049 1,711,971 1.725,987 1,706259 74,671 94,930 126,195 105,691 65,385 18,160 1610 100 100 100 a7l�§7) 17.4.$.24 471,22; 29.477!4 0142514 5.525.24 9 Q Q 9 516j42 671,761 548,117 3122.484 716,219 667,686 Ino 100 100 IDO 692,5110 568,284 588,280 617,660 649.1 BO 681,345 715,417 '151,183 708,742 828,179 (892,520) (651,175) (962,736) 306,199 (1,171,031) (1285,971) 1,012,537 980,688 917,145 977,990 1,415,675 1,014,884 261,778 2,03.1,551 0478.719 1,073,256 (391,207) (544,676) (870.476) (1,043,860) 5 44% 60% .35 : -38% 45% A6% 15% 23% -1.0% -14% -2.2% -2.5% 17,5Q9,747 19,566,300 15,5'16,518 18298,451 19,788,939 25,080,448 26,128,338 25,851,198 25.950,293 25,922,869 PA004712 Hutchinson4Gas & Elec' Rate StudylElec open results'existing raics%oper results Hutchinson Illililies. Minnesota Gas Operating Results Existing Rales P 1004712 Ilutchmson%Gas & Flrc Rare Study\Gas oper results existing ra%esloper results Exhibit 1-D 0 Forecast I list orical D - - 2006 _ .-- 2000_. - 2001 2002 2063 2004_ Oprrahnl; Rrcerur 58.057.266 57,332,755 S3.)04.240 51,765,810 53.163,891 Sales -635 S8.146.245 58.605.4/8 38.070,500 59.855,698 $10.258,242 Sales -31,1 2,500 S1,100.000 S1.100,000 $1.100.000 S 1.100.000 New lqm llmnsporratron 0 C 0 0_ 5550.257 Electric Dry Tratrsporianon 1.1,140,900 13.115.979 12.094.074 57,997 59,737, Net Income from OtSer Sources 18-8 11-67.2 12,057 72 05 22�LQ Total Operating Revenue 8.165.074 8.623.155 8,089,553 9.877,903 10,831,041 Operating Expenses 787,R2 909 248 99.1.073 1028,873 17_69 9 MFG Gas Roduction Overahen 638 119 0 0 0 MFG Ihaductiun Maintenance: 3.527 844 0 D 0 Purchased Ws Expense ReL,rl 6,922,703 7.445,306 6,898,141 8,770,068 8,059,319 Purchased Gas Expense -31,1 0 5,000 5,000 5.000 5,000 Transmission Operation 0 0 0 211 36,296 Transmission Mamteramr 0 0 0 0 3,455 IAslnbtrtion Operation 263,993 267.458 413,765 402,967 446,417 Dtstrrl+ution Maintenance 79,150 86,412 103,485 101,689 68,575 Cust Accounting & Collernng 110,2.52 70,633 76,71 i 74,267 76,092 Sales Expense 0 0 0 0 0 Administrative & General 471,810 381,980 112,774 97,864 91,932. Depreciation -Gas 170 671 IYU)1 19_84P -3 f�U.1 IIB U9 T0121 Operating Expenses 8,031,743 8,452,384 7,803,294 9,706,396 9,601,954 Operating Income 133,331 170.771 286,269 171,507 1,229,C87 Other Income 1.2% 3.4% 3.5% 3.4% 3.3:: Other - Net 45,493 :4,621 15.276 93,115 2.2,929 Interest Income 127,397 58,167 75,787 116,7(A 56,408 Miscellaneous Income 26,1'76 28.379 9,156 4,730 2,049 Gain on Disposal 0 0 0 136.558 5.840 Loss on Disposal (13,649) 0 0 0 D Mise Income - Gas Wells 443.2t6 195,281 1 S5 yD 1 1 W L89.0) Total Other Income 628,703 506,449 255,219 3.52,451 (2,149) Other Expenses Depletion - Gas %ells 57,171 40.747 14,480 0 0 Miscellaneous Expenses 37,493 16.961 10,519 4,049 1,380 Interest Expewc Au 0056 1 0111 12.;1004 64P1`9 Total Other Expenses 95,&17 58,764 45,999 127,053 650,529 Contribution to the City 296,820 232,116 252,120 264,720 278.220 Non-Operahng Incomei(Espense 236,036 2115,569 (42,900) (39,312) (930,898) Net Income 369,367 386,340 243,369 1.12,185 298,189 Oper Income as % of Net Assets Net Income as % of . let HsscU 1.0 RevenurRequirements 7,795,707 8,216,814 7,846,184 9,745,718 10,532.857 P 1004712 Ilutchmson%Gas & Flrc Rare Study\Gas oper results existing ra%esloper results Exhibit 1-D D 0 Forecast D D 2005 2006 2007 _ 2008-- 2009 58.630,1 1 B S9,015.004 58.727.009 58.057.266 57,332,755 S3.)04.240 51,765,810 53.163,891 52.808,613 52,511.319 5650.000 51,150.000 51.150,0 0 51.150.000 51,150.000 2,500 S1,100.000 S1.100,000 $1.100.000 S 1.100.000 0 0 C 0 0_ 12,384.358 15.030.813 1.1,140,900 13.115.979 12.094.074 D 0 D D D 0 0 0 0 0 6,957,627 7,264,362 6,992.997 6,294,391 5,550,143 2.855.688 1.492,885 2.08.731 2,531.196 2,231,622 74,000 85,000 87,550 90,177 92,682 2,500 47,000 7,500 2,575 49,000 310,0(10 313,429 327,832 332.517 347,492 98,500 129,500 133,385 137,387 141,508 57,997 59,737, 61,529 63,375 65,276 6,600 61,376 59.454 54,)29 49,220 136,648 149,240 151,717 150,329 16'1,079 787,R2 909 248 99.1.073 1028,873 17_69 9 11,289,586 12.534,777 11.685,763 10.692,748 9,732,911 1.094,772 2,496,036 2.455.136 2.421,131 2,361,162 136.000 25,001 25,000 25.000 25,000 35,000 0 0 0 0 5,000 5,000 5.000 5,000 5,000 0 0 0 0 0 0 0 0 0 0 0 9 0 9 9 176,000 30,000 30,000 30,000 30,000 0 0 0 0 0 11,000 0 0 0 0 589.526 1 15r16_52 1 140,152 1 1152`6 LQ81,520 600,526 1,159,652 1,140,157 1,115,276 1,094,5 26 292,050 306,653 321,985 339,084 354,989 (716,576) (1,436,305) (1,432,137) (1,423,360) (1,409,515) 378,196 1,059,731 1,012,999 999,771 951,648 3.61. 80Y. 83% -93% 8.2% 1.2% 3.4% 3.5% 3.4% 3.3:: 12,006,162 13,971,062 13,1 17,900 12,116,109 11,142426 Section 3 COST -OF -SERVICE STUDY Electric Division In order to compare revenues to revenue requirements by class for the Electric Division, we have performed an analysis of the cost to serve each customer classification based on adjusted 2004 revenue requirements ("Test Year"). In the cost - of -service study, the functionalized costs of providing service are first classified by cost component arid then allocated to each class of service based upon certain specific service characteristics. The results of the study indicate the degree to which existing rates recover revenues from each customer classification on a cost of service basis and are considered in designing new electric rates. The cost -of -service analyses used in this study have been based on: ■ Test Year reported revenue requirements and revenues based on current rates ■ total system and customer classification power and energy requirements ■ actual and assumed customer service characteristics, and ■ information obtained from customer accounts and records. Classification of Costs As a basis for allocating costs to individual customer classifications, we have first classified the Electric Division's Test Year revenue requirements to five specific cost components. These components and the type of costs assigned to each are described below. Demand Component - Those costs incurred to provide an electric system capable of meeting the total combined demands of customers. Demand costs include the portion of purchased power and generation costs, operating and maintenance expenses, capital expenditures and other costs which are generally fixed and do not vary materially with the amount of electricity consumed or which cannot be designated specifically as a customer or energy cost. Energy Component - Those costs that vary substantially or directly with the amount of energy purchased or generated. Energy costs are those costs which could be expected to vary with electricity consumption. Customer Service Component - 1 -hose costs directly related to the number and type of customers, such as customer service, customer accounting, billing and collection. Customer Facilities Component - Those costs directly related to the number and size of customers, such as the costs of meters and services and other equipment needed to provide service. D1600 Section 3 _ _ _ _ _ 1 Revenue Component – Other operating revenues, other income and expenses and contributions to the City are all revenue related. These revenues and income and expenses were divided between customer classifications based on each classification's percentage of total revenue requirements. Adjustments have been made to the Test Year revenue requirements to more accurately reflect costs during the Study Period, in particular the cost of purchased power. The table below summarizes the adjusted Zest Year revenue requirements of 4 ~ the Electric Division by cost classification. Exhibit 3-A at the end of this Section sets forth in detail classification of adjusted revenue requirements. Exhibit 3-13 details the classification of electric plant -in-service. Allocation To Customer Classifications Based upon actual and assumed customer service characteristics, we have developed various factors for use in allocating the Electric Division's adjusted Test Year revenue requirements to individual customer classifications_ "These allocation factors reflect accepted ratemaking principles and are based upon fully -distributed, embedded cost allocation procedures. The following summary describes the specific allocation factors used in our cost -of -service analysis. Exhibit 3-C at the end of this Section sets forth the development of each of these factors. Demand Allocations The demand allocation methods used in this study require the development of estimated coincident and non -coincident peak demands for each customer classification. Customers on the large General Service and Large Industrial rates are demand metered. This billing demand information was used to develop coincident and non -coincident peak demands for the two classes. Class peak demands for the remaining rates were estimated, based on the results of load research studies for other utilities and the experience of other utilities relative to the load characteristics of individual classes of services. u 3-2 Hutchinson Utilities 1 131600 1 Classification Of Electric Division Costs 2004 Test Year .----- ---Cost ---------- Revenue.— .— — Component Requirements Demand $7,789,975 Energy 14,749,451 Customer Service 485,537 Customer Facilities 533,646 Revenue 518,695 Total _ _ $24,077,304 Allocation To Customer Classifications Based upon actual and assumed customer service characteristics, we have developed various factors for use in allocating the Electric Division's adjusted Test Year revenue requirements to individual customer classifications_ "These allocation factors reflect accepted ratemaking principles and are based upon fully -distributed, embedded cost allocation procedures. The following summary describes the specific allocation factors used in our cost -of -service analysis. Exhibit 3-C at the end of this Section sets forth the development of each of these factors. Demand Allocations The demand allocation methods used in this study require the development of estimated coincident and non -coincident peak demands for each customer classification. Customers on the large General Service and Large Industrial rates are demand metered. This billing demand information was used to develop coincident and non -coincident peak demands for the two classes. Class peak demands for the remaining rates were estimated, based on the results of load research studies for other utilities and the experience of other utilities relative to the load characteristics of individual classes of services. u 3-2 Hutchinson Utilities 1 131600 1 Cost of Service Study Energy Allocations 'Mie costs related to generation and the energy component of purchased power have been allocated on the basis of each customer classification's annual energy requirements at the inlet to HU's electrical system for the Test Year. Customer Allocations Customer Service related costs have been allocated among the customer classifications based on the Customer Service allocation factor. This factor allocates customer related costs such as customer billing, customer service and meter reading in proportion to each classification's weighted number of customers. Such weighting factors are developed to represent the difference in service configurations between customer classifications. Customer Facilities related costs have been allocated among the customer classifications based on the Customer Facilities allocation factor. This factor allocates customer facilities related costs in proportion to each classification's weighted number ol' customers. The weighting factor represents the difference in the cost of equipment used by different classifications. These two weighting factors were developed based on the experience of other utilities, as well as information obtained from HU. dRevenue Allocations Costs classified to the revenue component have been allocated to each customer classification based on total allocated revenue requirements before revenue -related costs. For purposes ol' this calculation, allocated revenue requirements are assumed to represent the proportionate share of revenues which will be recovered from each class of service in the future. Cost -of -Service Study Results' rBased -upon the cost classifications and allocation methods described above, we have estimated the cost to serve each customer classification during the Test Year. Exhibit 3-A, Classification of Electric Test Year Revenue Requirements shows several adjustments to 2004 recorded expenses. These adjustments were made to better reflect expenses during the Study Period. "total adjusted expenses are $4,691,318 higher than recorded expenses. The increases are due mainly to a $3 million increase in purchased power costs and $1 million in transportation fees for the Electric Division's use of the gas pipeline. Previously, the Electric Division paid for its use of the gas pipeline through debt service payments for the pipeline. The results of this study are presented in detail in Exhibit 3-D at the end of this Section. The table below compares our findings from Exhibit 3-D with revenues from each customer classification during the Test Year. Due to the adjustments made to the Test Year revenue requirements, Test Year revenues are considerably lower than adjusted Test Year revenue requirements. 131600 R. W. Beck 3-3 Section 3 As indicated by the above comparison, Hll's existing electric rates are not exactly in line with the cost to serve each customer class. Cost based rates are one of several goals in establishing rates. The relationship between allocated costs and revenues for a each class should be considered, in addition to other rate related goals; in developing recommended rates. 3-4 Hutchinson Utilities --- _ --- --_ —_ ---- B 160 Electric Division Comparison Of Revenues And Allocated Cost -Of -Service 2004 Test Year Customer Classification Total Allocated Costs Total Revenues ' y Residential/ All Electric $4,683,846 $3,702,238 Small General Service 1,589,783 1,437,418 Large General Service 6,597,470 5,537,580 Large Industrial 11 206.206 9.3 2 46 Total ! _ $24,077,304 $20,009,882 For purposes of determining the extent to which existing rates match recovery of costs for each class, we have made a comparison of Test Year revenues based on existing rates and the allocated cost -of -service for each customer classification. The results of this comparison are shown in the following table on a percentage basis. Also shown in the table are the approximate percentage increase/(decrease) in each customer classification's rates necessary to produce revenues from each classification which are in accordance with the corresponding percentage of total cost of service. The percentage increase or decrease shown in the table below does not represent a recommended rate increase or decrease for these classes. Recommendations for new rate designs will be presented in Section 5. Electric Division Percentage Comparison Of Revenues And Allocated Cost -Of -Service 2004 Test Year Customer Classification Percentage Percentage Increase/ Allocated Revenues (Decrease) (1) Costs Residential/ All Electric 19.5% 18.5% 5% Small General Service 6.6% 7.2% (8%) Large General Service 27.4% 27.7% (1%) Large Industrial 46.5% 46.6% 0% Total 100.0% 100.0% 0% (1) Adjustment represents Test Year data used for cost of service aralys's and does not represent a proposed rale increase or decrease. As indicated by the above comparison, Hll's existing electric rates are not exactly in line with the cost to serve each customer class. Cost based rates are one of several goals in establishing rates. The relationship between allocated costs and revenues for a each class should be considered, in addition to other rate related goals; in developing recommended rates. 3-4 Hutchinson Utilities --- _ --- --_ —_ ---- B 160 Is Cost of Service Study IN Gas Division In order to compare revenues to revenue requirements by class for the Gas Division, we have performed an analysis of the cost to serve each customer classification based on adjusted 2004 revenue requirements ("Test Year"). In the cost -of -service study, the functionalized costs of providing service are first classified by cost component and then allocated to each class of service based upon certain specific service characteristics. The results of the study indicate the degree to which existing rates recover revenues from each customer classification on a cost of service basis and are considered in designing new gas rates. The cost -of -service analyses used in this study have been based on: ■ Test Year reported revenue requirements and revenues based on existing rates ■ total system and customer classification commodity and capacity requirements ■ actual and assumed customer service characteristics, and ■ information obtained from customer accounts and records. Classification of Costs As a basis for allocating costs to individual customer classifications, we have first classified the Gas Division's Test Year revenue requirements to six specific cost components. These components and the type of costs assigned to each are described below. Capacity Component - "Those costs incurred to provide a gas system capable of meeting ISthe total combined demands of customers. Capacity costs include the capacity portion of purchased gas costs, operating and maintenance expenses, capital expenditures and other costs which are generally fixed and do not vary materially with the amount of gas consumed or which cannot be designated specifically as a customer or commodity cost. Commodity Component - Those costs that vary substantially or directly with the amount of gas purchased or sold or which can be attributed to gas purchase volumes. Customer Service Component - Those costs directly related to the number and type of customers, such as customer service, customer accounting, billing and collection. Customer Facilities Component - Those costs directly related to the number and type of customer facilities, such as the costs of meters and services and other necessary equipment. Revenue Component — Other operating revenues, other income and expenses and utility service contributed to the City are all revenue related. These revenues and expenses were divided between customer classifications based on each classification's percentage of total revenue requirements. Direct Component — Those costs which are clearly related to a specific class or type of service. The commodity cost of gas sold directly to 3M is a direct cost. 131600 R. W. Beck 3-5 Section 3 The table below summarizes the classification of Test Year revenue requirements of , the Gas llivision. )exhibit 3-E at the end of this Section shows the detailed classification of revenue requirements. Exhibit 3-F details the classification of- gas plant-in-seryice. Allocation To Customer Classifications Based upon actual and assumed customer service characteristics, we have developed various factors for use in allocating the Gas Division's adjusted Test Year revenue requirements to individual customer classifications. These allocation factors reflect accepted ratemaking principles and are based upon fully -distributed, embedded cost allocation procedures. 'rhe following summary describes the specific allocation factors used in our cost -of -service analysis. Exhibit 343 at the end of this Section shows the development of each of these factors. Demand Allocations To allocate demand related revenue requirements to individual customer classifications, we have used two different demand allocation methods. 'these methods are the peak responsibility method and the average/excess method. Under the peak responsibility method, demand costs are allocated to the customer classifications in proportion to their respective contributions to the Gas Division's peak demand. The peak responsibility method is used to allocate demand related purchased gas costs. It is based on class consumption during; the peak month of the "fest Year, January 2004. The average/excess method is used to allocate the remainder of the system capacity related costs. It is a two part formula. One part of the formula determines each class' share of the average use of the system, based on each class' annual consumption. The second part of the formula recognizes each class' share of the costs above the average use of the system (excess). This is done by determining the excess demand of each class on the system above their average demand. This part of the formula takes into 3-6 Hutchinson Utilities — B 160 Classification Of Gas Division Costs 2004 Test Year _– Cost Revenue Component Requirements Demand $94B,676 Commodity 5,427,584 Customer Service 157,2.62 Customer Facilities 1,245,916 Revenue 248,125 Direct 2,230,676 Total $10,258,240 Allocation To Customer Classifications Based upon actual and assumed customer service characteristics, we have developed various factors for use in allocating the Gas Division's adjusted Test Year revenue requirements to individual customer classifications. These allocation factors reflect accepted ratemaking principles and are based upon fully -distributed, embedded cost allocation procedures. 'rhe following summary describes the specific allocation factors used in our cost -of -service analysis. Exhibit 343 at the end of this Section shows the development of each of these factors. Demand Allocations To allocate demand related revenue requirements to individual customer classifications, we have used two different demand allocation methods. 'these methods are the peak responsibility method and the average/excess method. Under the peak responsibility method, demand costs are allocated to the customer classifications in proportion to their respective contributions to the Gas Division's peak demand. The peak responsibility method is used to allocate demand related purchased gas costs. It is based on class consumption during; the peak month of the "fest Year, January 2004. The average/excess method is used to allocate the remainder of the system capacity related costs. It is a two part formula. One part of the formula determines each class' share of the average use of the system, based on each class' annual consumption. The second part of the formula recognizes each class' share of the costs above the average use of the system (excess). This is done by determining the excess demand of each class on the system above their average demand. This part of the formula takes into 3-6 Hutchinson Utilities — B 160 _— — Cost of Service Study account the class load factor. phis capacity cost allocation method recognizes both the average gas requirements, as well as the peak loads of each customer classification. Exhibit 3-11 shows the development of this allocation factor in detail. We have used the peak month data for January 2004 as a measure of peak period requirements, as HU does not have sufficient data available to determine actual peak day usage by the various customer classifications. p■■ Commodity Allocations Commodity related costs have been allocated to each class o1' service based on recorded gas sales for the 2004 Test Year. 71 Customer Allocations Customer Service related costs have been allocated among the customer classifications based on the Customer Service allocation factor. This factor allocates customer related costs such as customer billing, customer service and meter reading in proportion to each classification's weighted number of customers. Such weighting factors are developed to represent the difference in service configurations between customer classifications. Customer Facilities related costs have been allocated among the customer classifications based on the Customer Facilities allocation factor. This factor allocates customer facilities related costs in proportion to each classification's weighted number of customers. The weighting factor represents the difference in the cost of equipment used by different classifications. These two weighting factors were developed based on the experience of other utilities, as well as information obtained from HU. Revenue Allocations Costs classified to the revenue component have been allocated to each customer classification based on total allocated revenue requirements before revenue -related costs' For purposes of this calculation, allocated revenue requirements are assumed to represent the proportionate share of revenues which will be recovered from each class of service in the future. Cost -of -Service Study Results Based upon the cost classifications and allocation methods described above, we have estimated the cost to serve each customer classification during the Test Year. The Small Interruptible and Large Interruptible rate classes have been incorporated into other appropriate rate classes, due to plans to eliminate all interruptible rates. The results of this study are presented in detail in Exhibit 3-1 at the end of this Section. The table below compares our findings from Exhibit 3-1 with the revenues from each customer classification during the Test Year. B 160 R. W. Beck 3-7 Section 3 For purposes of determining the extent to which existing rates match recovery of costs for cacti class, we have made a comparison of Test Year revenues based on current rates and the allocated cost -of -service for each customer classification. The results of this comparison are shown in the following table on a percentage basis. Also shown �1 in the table are the approximate percentage increase (decrease) in each customer classification's rates necessary to produce revenues from each classification which are in accordance with the corresponding percentage of total cost of service. Gas Division Percentage Comparison Of Revenues And Allocated Cost -Of -Service 2004 Test Year Customer Classification Percentage Percentage Increase/ Allocated Gas Division (Decrease) (') Costs Comparison Of Revenues And Residential 37.8% Allocated Cost -Of -Service 0.3% Commercial 30.6% 2004 Tesl Year (1.8%) Customer Classification Total Allocated Total Revenues 3M 25.2% Costs 6.0% Residential $3,880,177 $3,867,185 Commercial 3,139,914 3,197,363 Large Industrial 651,955 751,024 3M 2 586.194 2,439,666 Total $10,258,240 $10,255,238 For purposes of determining the extent to which existing rates match recovery of costs for cacti class, we have made a comparison of Test Year revenues based on current rates and the allocated cost -of -service for each customer classification. The results of this comparison are shown in the following table on a percentage basis. Also shown �1 in the table are the approximate percentage increase (decrease) in each customer classification's rates necessary to produce revenues from each classification which are in accordance with the corresponding percentage of total cost of service. Gas Division Percentage Comparison Of Revenues And Allocated Cost -Of -Service 2004 Test Year Customer Classification Percentage Percentage Increase/ Allocated Revenues (Decrease) (') Costs Residential 37.8% 37.7% 0.3% Commercial 30.6% 31.2% (1.8%) Large Industrial 6.4% 7.3% (13.2%) 3M 25.2% 23.8% 6.0% Total 100% 100% 0% _ (1) Adjustment represents percent increase needed to match revenues to revenue requirements by Gass and does not represent a prcposed rate increase or decrease. The table above indicates that the HU's existing gas rates are not completely in line with the cost to serve each customer class. Cost based rates are one of several goals in establishing rates. The relationship between allocated costs and revenues for each class should be considered, in addition to other rate related goals, in developing recommended rates. 3-8 Hutchinson Utilities --- — — a1600 G P.1004712 Hutchrnson%Gm & Elec Rate Study\Electric Cost of ServrcelClassification It Exhibit 3-.4 Hutchinson Utilities. Minnesota Classifrcalion of Elrciric Test Year Revenue Requirrments 2004 Test Year Total Adjusted Demand Energy Cusi Sen• Cust Facil Revenue Basis for Classification Operating Expenses ProductionOperation 2,000,997 1,204,030 (1) 1,204,000 100% Demand Production Maintenance 303,08: 303,03.1 303,08.7 100% Demand Pwr Generation Pipeline 1,100,000 (2) 1,100.000 100% Demand Purchased Gas-Gerreratron 0 1.139,349 (3) 1,119,349 100% Energy Porch Power -Internal Use 11.812,650 14,969.403 (11) 1.359,000 13.610,102 300 (5) Sys Coll & Engineering 298.011 (6) 298,011 IOU% Demand Transmission Operation 783 783 783 •rransmrssron 100% Demand Mainten.utce 52,068 52,063 52,068 100% Demand Distribution Operatrcn 388.795 388,795 234,137 154.658 Distribution Plant Distribution Marnien3nce 123,186 123,186 74.184 49.002 Distribution Plant' Cust Accig & Collecting 104.167 30.1,367 304,.367 Sales Expense 299,921 (7) 299,921 100%Cuss Service 100% Revenue Adnnnisttative & General 1,523,807 1,523,807 1,234,334 173,428 116,045 (8) Depreciation -Electric 2.108.122 2 108 1 28l 211 22 Im .141 Total Plant Total OpetalrnU. Expenses 18,617,859 23,814,896 7,756,582 14,749,451 478,096 530,845 299,921 Other (Income) Other - Nei (44,570) (4.1,570) (44,570) 100% Revenue Interest Income (56,408) (56,408) Miscellaneous Income (71.611) (71,611) (56,403) (71,611) 10036 Revenue 100% Revenue (lain on Disposal (21,749 r r ) (21,74)) (1),5'11) (2,178) Total Plant Loss on Disposal 0 0 0 0 Total Plant Total Other Income (194,338) (194,338) (19,571) (2,178) (177,589) Other Expenses Miscellaneous Expenses 65,385 65,385 52,96.1 7.442 4,979 (8) Interest Expense 65�i,854 U (y] 0 0 Total Plant Total Other Expenses 716,239 65,385 52,964 7.447. 4,979 0 Contribution rothe City 649,180 649,180 649,180 100% Revenue Revenue on Resale Sales (278,352) (133,217) (10) (133.217) 100% Revenue Credit for Other Otter Rev (I 24_01) 124 .I) (12.1&0) 100%Revenue Subtotal Revenue Requiremt 19,335,986 24,077,304 7,789,975 14,749,451 485,537 513,6.16 518.695 Margin p Total Revenue Requirerner115 19,`385,986 24,077,304 7,789,975 14,749,451 485,537 533,646 518,695 Percentage Rev RegmLs 100% 32% 6156 2% 256 2% (1) Separated natural gnu and fuel oil costs into another line - "Purchased Gas -Generation " (2)Elcc Division paymrni to Gas Division for pipeline transportation will replace Electric Divisions one-half share principal and interest payments for new gas pipeline. (3) Based on assumed 5 percent generation and average 2004 recorded price for natural gas (4) 2004 purchases adjusted to reflect new CMMPA contract purchases and market purchases, as needed, after assumed 5 percent generation CMMPA rates used for 0AMPA purchases, 90 percent of natural gas cost used for market purchases. (5) Based on wholesale power bills, assuming adjustments described in note (4). (6) 2004 System Control costs were not listed separately in the past The cost was increased to reflect expected highcr costs from 2004 in the years going forward (7) Sales expense was begun to 2005 to reflect required expenditures of 1.5 percent of revenue frorn retail sales that are used for energy conservation improvements. (8) Based on production, transmission, distribution, customer services and customer facilities expenses (9) Electric Division payment of hall the interest expense on the gas pipeline has been eliminated. (10) Included only net margin because Cnst of resale sales was removed frorn the analysis G P.1004712 Hutchrnson%Gm & Elec Rate Study\Electric Cost of ServrcelClassification It lescriplion AectriC neration Plant and & Land Rights Structures & Improvements fuel Holders/ Producers eneration & Prbne Movers Accessory Electric Eqpt Misc Power Plant Eqpt Val Generation Plant --ansmission I'lant and & Land Rights 'tructures & Improvements Station Equipment towers & Fixtures oles & Fixtures Overhead Conductors tJJnderground Conduit & Manholes nderground Conductors -otal Transmission Plant Istribufion Plant Land & Land Rights dtructures & Improvements ation Equipment Poles, Towers & Fixtures Overhead Conductors underground Conduit & Manholes nderground Conductors ransformers ervices eters Security Lights Ital Distribution Plant otal Electric Plant Istribution Plant Percent tal Electric Plant Percent Hutchinson Utilities, Minnesota Classification of Electric Plant -in -Sen -ice 2004 Test Year Accumulated System Net Gross Plant Depreciation I'lant-in-Service Exhibit 3-I3 Demand Customer Iiasis of Classification $1,453,900 50 $1,453,900 $1,453,900 2,526,567 795.553 1,731,014 1,731,014 178,532 1771254 1,278 1,278 35,066,851 14,949,227 20,1 17,624 20,1 17,624 668,945 274.208 394,737 394,737 234,919 93.560 141.354 141_,359 40,129,714 16,289,802 23,839,912 23,839,912 223,318 0 223,318 223,318 589,226 69,647 519,579 519,579 4,354,666 1,138,316 3,2.16,350 3,216,350 1,019,523 120,474 899,049 899,049 1,169,097 234,130 934,967 934,967 616,245 192,795 •123,450 423,450 101,078 18,587 82.,491 82,491 711 569 12 172 59 337 59.397 8,144,722 1,'186,121 6,358,601 6,358,601 123,360 0 42.4,401 146,842. 2,868,972 1,346,373 12.3,813 97,701 170,651 129,333 72.8,950 347,326 6,631,963 1,773,850 2,517,432 974,776 933,302 361,243 1,266,008 449,286 0 (1) 15,788,852 5,626,730 $64,063,2.88 523,702,653 ISecurity lights not included bt cost -of -service analysis. 123,360 123,360 277,559 277,559 1,522,599 1,522,599 26,112 13,056 41,318 20,659 381,62.4 190,812 4,858,113 2,429,057 1,542,656 1,542,656 572,059 100% Customer 816,722. 100% Customer 100% Demand 100% Demand 100% Demand 100% Demand 100% Demand 100° o Demand 100% Demand 100% Demand 100% Demand 100% Demand 100% Demand 100% Demand 100% Demand 100% Demand 10.162,122 6,1 19,758 4,042,365 540,360,635 536,318.271 54,042,365 60% 40% 90% 10% IP.\004712 I-Iutchi isonkGas & F.lec Rate Sttidy\[:Iectric Cost of SeivicelPlant in Service 100% Demand 100% Demand 100% Demand 13,056 50% Dmd/ 50% Cust 20,659 50% Dmd/ 50% Cust 190,812 50% Dmd/ 50% Cust 2,429,057 50% Dmd/ 50% Cust 100% Demand 572,059 100% Customer 816,722 100% Customer (1) 10.162,122 6,1 19,758 4,042,365 540,360,635 536,318.271 54,042,365 60% 40% 90% 10% IP.\004712 I-Iutchi isonkGas & F.lec Rate Sttidy\[:Iectric Cost of SeivicelPlant in Service P:1004712 Hutchinson\Gas & Elec Rate Study\Electric Cost of Service\Alloc Factors I Exhibit 3-C Hutchinson utilities, Minnesota Electric Demand, Energy and Customer Allocation Factors 1 2004; Test Year Total Res/All Elec SGS LGS Lt Ind Demand Allocation Factors Coincident Peak Demand (kW) 61,004 12,135 3,686 18,541 26,642 Allocation Factor - Coincl )md 100% 20% 6% 30% 44% Non -Coincident Peak Dmd (kW) 62,702 12,336 3,718 19,736 26,911 Allocation Factor - NonCoincDmd 100% 20% 6% 31% 43% Energy Allocation Factor Annual Energy Reqmts (kWh) (1) 290,843,2.04 48,630,330 18,892,852 75,025,022 148,295,000 Allocation Factor- Energy 100% 17% 6% 26% 51% Customer Service Allocation Factor Average Number ot'Customers 6,792 5,875 797 118 2 Service Weighting Factor 1 2 5 10 Weighted Number of Customers 7,681 5,875 1,196 590 20 Allocation Factor - CustSery 100% 76% 16% 8% 0.3% Customer Facilities Allocation Factor Average Numberof'Customeis 6,792 5,875 797 118 2 I Facilities Weighting Factor 1 2 50 1,000 Weighted Number of Customers 15,369 5,875 1,594 5,900 2,000 Factor - CustFacil 100% 38% 10% 38% 13.0% IAllocation (1) Excludes street lights and security lights and resale sales. INon -Coincident Demand Analysis Class Peak Month Billing T)emand 21,929 27,460 Annual Energy 75,025,022 148,295,000 Class Coincidence Factor 90% 98% Class Non -Coincident Demand 12,336 3,718 19,736 26,911 Non -Coincident load Factor 45% 58% 43% 63% Coincident Demand Anaisis Sys Pk Month Bill Dmd (kW) - Jul 04 21,929 27,460 Peak Month Energy - Jul 04 27,529,036 5,142,608 1,767,540 7,056,888 13,562,000 Class Coincidence Factor 89% 98% Demand 61,00.1 12,135 3,686 18,541 26,647. ICoincident Coincidence w/Sys Ilk Factor 79% 90% 95% 99% Coincident Load Factor 57% 64% IRecorded System Peak I I 61,000 P:1004712 Hutchinson\Gas & Elec Rate Study\Electric Cost of Service\Alloc Factors I Energy Component Purchased Gas -Generation 1,139,349 190,50.1 74,011 293,903 580,931 Exhibit 3-D Purch Potser Internal Use 13 610102 Hutchinson Utililies, Minnesota 3,510 82(1 6 939 513 Encrl;y Total1.ncrgy Allocation of Electric Revenue Requirements 958,108 3,80.1,723 7,520.443 (25.915) Test Year 2004 (62.003) (1) Credit for Oilter Oper Rev LI21.601) L2 _4Z3 2239.) Total Res/ All F:lec SGS LGS Lg Ind Basis of Allocation Demand Component CustSery Cust Acctg & Collecting 304.367 232,818 47,376 23,381 Production Operation 51,204.000 239,491 72.,758 365,931 525.814 CoincDmd Production Maintenance 303.08.1 60,288 18.315 92,117 132,364 CoincDmd Pwi Gencratiun Pipeline 1,100.000 218,807 66,473 334,325 480,395 CoincDmd Purch Power -Internal Use 1.359,000 270,326 82,125 413.043 593.506 ColncDnld Sys Crrtl & Engineering, 298,011 58,633 17,673 93,802 127,902 Non('oincDmd Transmission Operation 783 156 47 238 342. CorncUntd Transntssiun Maintenance 52,068 10,357 3,1.16 15,825 22,739 CoincDmd Distribution Operation 234.137 46,066 13,885 73,697 100.489 NonCoincl)rnd Distribution Maintenance 74,18.1 14,596 4,399 2.3,350 31.839 NonCoincDntd Administrative & General 1,234,334 242.853 73,201 388:520 529,760 NonCotncl)md Deprcciation•Elecinc 1,896,981 373,227 112.499 597.096 814.159 NonCcircD;nd Other (Income) (19,571) (3,851) (1,161) (6,160) (8.400)NonCoincDntd 011ier Expenses 52..96-1 10421, 3,1x1. 16-6D L2_7 1 1. Non('oincDntd Total Demand 7,789,975 1,541,373 466,504 2.408.459 3,373.639 Energy Component Purchased Gas -Generation 1,139,349 190,50.1 74,011 293,903 580,931 Energy Purch Potser Internal Use 13 610102 2 275 672 88.1.097 3,510 82(1 6 939 513 Encrl;y Total1.ncrgy 14.7,19,4 51 2,466,177 958,108 3,80.1,723 7,520.443 (25.915) Cust Service Component (36,503) (62.003) (1) Credit for Oilter Oper Rev LI21.601) L2 _4Z3 2239.) L8 227) Purch Power -Internal Use 300 230 47 23 1 CustSery Cust Acctg & Collecting 304.367 232,818 47,376 23,381 793 CustSery Administrative & General 173,428 132,659 26,995 13,322 452 C.uslSery Other Expenses 7a4 2 5 691 LM 572. 19 CustSery Tolal Customer Service 485,537 371,399 75,576 37,298 1,2.64 5.1% Cust Facilities Component -1.0% -0 2°e (1) Based on demand. energy, custurner service and cu.,tonter laetlines allocations. Distribt:tiouOperation 15.1,658 59,12.0 16,040 59,372 20,126 CuslFacil Distribution Maintenance 49,002 18,732 5,082 18,811 6,377 CustFacil Administrative & General 116.045 44,360 12,036 44,548 15.101 Custl=acil Depreciation -Electric 211,141 80,712 21,899 81,055 27,476 CustFacil Other (income) (2.178) (833) (226) (836) (283) CustFacil Other Expenses 4_92 7 1,903 516 1.912 649 CustFacil Total Customer Facilities 533,646 203,993 55,347 204,861 69,445 Revenue Component Sales Expense 299:921 58.345 19,803 82,182 139,591 (1) Other(Incomc) (172:589) (33,571) (11,396) (47,291) (80,327)(1) Contribution to the City 649,180 126,287 42,864 177,883 302.145 (1) Revenue on Resale Sales (133.217) (25.915) (81796) (36,503) (62.003) (1) Credit for Oilter Oper Rev LI21.601) L2 _4Z3 2239.) L8 227) (34 142) (57 993) (1) Total Re%cnnc 518.695 100.904 34,249 142,129 241.414 Total Re, enue Rcgnrts $24.077,304 $4.683,846 $1.589,783 56.597,470 511,206,206 Total Revenues (2) 520.009,882 53,702.238 51.•137.418 $5.537.580 59,3 32.616 Revenue Regnrts Percent 1000% 195% 6 6% 27.4% 46.5° Re%enue Pcrcent 100.0':1 18.5% 7 2516 27 7".0 46 6`50 Percent Change 5.1% -8 1% -1.0% -0 2°e (1) Based on demand. energy, custurner service and cu.,tonter laetlines allocations. (2) Revenues for L.GS include revenues of S 15,560 which is the amount given ns primary discount in 2004. P:\004712 Iutchinson\Gas & E1ec Rate Study\Electric Cost of Servtec`uAlloc of Rry Req Split cost of gas for 3M from retail Iota] cost of gas. Commodity cost of gas sold directly to 3M. 3) Sales expense was begun in 2005 to reflect required expenditures of 0.5 percent of revenue from retail sales that are used for energy conservation improvements. Based on transmission, distribution, customer service and customer facilities expenses. Income from gas wells varies widely. II is usually not a net loss, as in the 2004 lest year 6) Adjusted to reflect Gas Division payment of all interest related to gas pipeline in future years. Adjusted to reflect Electric Division payment for use of gas pipeline to transport gas used for generation. Allocated based on subtotaled demand, and customer related revenue requirements, except for purchased gas. P-\004712 Hutchinson\Gas & Elec Rate Study\Gas Cost of Service\Classification Exhibit 3-E Hutchinson Ulilities, Minnesota Classification of Gas'rest Year Revenue Requirements i ITotal 2004 Test Year Adjusted Demand Commodity Cust Sery Cust Fan] Revenue Direct Basis for Classification peraung Expenses Purchased Gas Expense-Retail 18,058,319 15,827,643 (1) 5400,059 15,427,584 Per wholesale gas bills Purchased Gas Expense-3M 0 2,230,676 (1) 2,230,676 (2) Transmission Operation 36,296 36,296 36,296 100% Demand Transmission Maintenance 3,455 3,455 3,455 100% Demand Distribution Operation 446,417 446,417 226,063 220,354 Distribution Plant Distribution Maintenance 68,575 68,575 34,726 33,849 Distribution Plant Cust Accounting & Collecting 76,092 76,092 76,092 100% Cust Service Sales Expense 0 51,291 (3) 51,291 100% Revenue Administrative & General 93,932 93,932 44,751 11,330 37,851 (4) Depreciation-Gas 881 A66Q 818.869 414.671 404.1197 Distribution Plant Total Operating Expenses 9,601,954 9,653.246 1,160,022 5,427,584 87,422 696,251 51,291 2,230,676 [her (Income) Other - Net (22,929) (22,929) (22,929) 100% Revenue Interest Income (56,408) (56,408) (56,408) 100% Revenue Miscellaneous Income (2,049) (2,049) (2,049) 100% Revenue Gain on Disposal (5,840) (5,840) (2,957) (2,883) Distribution Plant Lass on Disposal 0 0 0 0 Distribution Plant Misc Income - Gas Wells 89,375 9 (5) Q 100% Revenue Ital Other Income 2,149 (87,226) (2,957) 0 0 (2,883) (81,386) 0 they Expenses Depletion - Gas Wells 0 0 0 100% Revenue iscellaneous Expenses 1.380 1,380 658 167 556 (4) Interest Expense 649.149 I )9$,W (6) U211_51 100% Demand otal Other Expenses 650,529 1,199,532 1,198,809 0 167 556 0 0 contribution to the City 278,220 278.220 278,220 100% Revenue redit-Elec Div Transport Rev 0 (1,100,000) (7) (1,100,000) 100% Demand =redit-New Ulm Transport Rev (550,257) (550,257) (550,257) 100% Demand l Revenue Requirements 59,982,595 9,393,514 705,616 5,427,584 87,588 693,924 248,125 2,230,676 Eevenue 864,726 243,060 69,673 551,992 (8) Requirements 19,992,595 S10258.240 $948,676 55,427,584 S157,262 $1.245,916 1248,125 (2,230,676 levenue Requirements Percent 8% 58% 1% 7%3% 24/0 ° Split cost of gas for 3M from retail Iota] cost of gas. Commodity cost of gas sold directly to 3M. 3) Sales expense was begun in 2005 to reflect required expenditures of 0.5 percent of revenue from retail sales that are used for energy conservation improvements. Based on transmission, distribution, customer service and customer facilities expenses. Income from gas wells varies widely. II is usually not a net loss, as in the 2004 lest year 6) Adjusted to reflect Gas Division payment of all interest related to gas pipeline in future years. Adjusted to reflect Electric Division payment for use of gas pipeline to transport gas used for generation. Allocated based on subtotaled demand, and customer related revenue requirements, except for purchased gas. P-\004712 Hutchinson\Gas & Elec Rate Study\Gas Cost of Service\Classification Exhibit 3-F Ilutchinson Utilities, Minnesota Classification of Gas Plant -in -Service 2004 Test Year Accumulated Systern Net ;caption Gross Plant Depreciation Plant -in -Service Demand -ust Facilities Basis of Classification s Distnbulion rains 28,711.445 1,656,813 27,054,632 13,52.7,316 13,527,316 50%Dmd/50%Cusl I&R Station Equipment -Gen 1,317,577 135,143 1,182,434 1,182,434 100% Demand I&R Station Equipment -City 360,284 81,723 278,561 278,561 100% Demand :rvices 726,782 272,226 454,556 454,556 100% Customer leters & all Fittings 913,197 291,689 621,508 621,508 100%Customer ouse Regulators & All Fillings 85,866 30,569 55,297 55,297 100% Customer idustrial M&R Station Equipmem 95,685 45,023 50,662 50,662 100% Demand Ther Equip (CO tester, Gas Analy; 76. 147 41,382 34.765 17,383 17.383 50% Dmd/ 50% Cust tal Gas Plant $32,286,983 $2,554,568 $29,732,415 $15,056,356 $14,676,060 .tal Gas Plant Percent 51% 49% P:\004712 Hutchinson\Gas & Elec Rate Study\Gas Cost of Service\PI3nt in Service I Exhibit 3-G Hutchinson Utilities, Minnesota Gas Dennand, Commodity and Customer Alkwation Factors 200+ Test Year Lge Indus Total Residential:=oml/lntemipt HT1 Demand Allocation Factor Peak Period Sales (MCF) --Jan 04 201,528 91,368 67,161 11,083 Allocation Factor - Dens -1 100% 45% 330,J0 5% Average.[FxcessDemand (MCF) (1) 201,51.8 81,823 61,604 10,516 Allocation, Factor Dem -2 100% 41% 31% 5% Commodity Allocation Factor Annual Sales w/o 3M (MCF) (2) 918,750 448,368 Allocations Factor Comm 100% 49% Customer Service Allocation Factor 10 21% Average Number ol'Customers 5,058 4,557 Service Weighting Factor 1.0 Weighted Number of Customers 5,830 4,557 Allocation Factor CustSery 100% 78% Customer Facilities Allocation Factor Average Number of Customers 5,058 4,557 Facilities Weighting Factor 1.0 Weighted Number of Customers 9,300 4,557 Allocations Factor CustFacil 100% 49% (1) See Exhibit 3-H for development ofAveragetExcess Demand. (2) 3M commodity costs directly assigned. 382,785 87,597 42% 10% 499 1 2.5 10.0 1,248 10 21% 0.2% 499 7.0 3,493 38% P:\004712 Iiutchinson\Gas & F.lec Rate Study\Gas Cost of Servnce\Alloc I-actors 1 500 500 5.4% 3M 31,916 16% 47,285 23% 0% 1 15 15 0.3% 1 750 750 8.1% � �� o...® �s� � uio �.� tai � 'moi ;t#r ;tai �'� '� �.1� i 'tl• t;♦ `•� Exhibit 3-H Hutchinson Utilities, Minnesota Demand Cost Allocation by Average -Excess Demand (l) Total annual consumption by class. (2) System peak month consumption (January 2004). (3) [ndividual class maximum monthly demands, whenever they occur during the year. (4) Total annual consumption by class, divided by 12 months. (5) Class maximum demand (col 3), less class average demand (col 4). (6) System peak month demand (col 2) less the total system average demand (col 4). (7) Ratio of each line to the total for the Process Demand Alloc Basis (col 5), times the System Excess Demand (col 6) (8) Sum of columns 4 and 7. (9) Ratio of each line to the total for column 8. P:\004712 Hutchinson\Gas & Elec Rate Study\Gas Cost of Service\Avg_Excess Demand Class Max Class Avg Process System Avg & Percent Sys Peak Demand Demand Dmd Alloc Excess Excess Excess Avg & Annual Use Month Month per Month Basis Dcmand Demand' Demand Excess Class of Service (MCF) (MCF) (NCP) (MCF) (MCF/month) (MCF) (MCF/month) (MCF) Demand (1) (2) (3) (4) (5) (6) (7) (8) (9) Residential 448,368 N/A 91,368 37,364 54,004 N/A 44,459 81,823 4!% Commercial 382,785 N/A 67,981 31,899 36,082 N/A 29,705 61,604 31% Large Indus-HTI 87,597 N/A 11,571 7,300 4,271 N/A 3,516 10,816 5% Large Indus -3M 365,219 N/A 50,903 30,435 20,468 N/A 16.850 47,285 230,'n Total 1,283,969 201,528 221,823 106,997 114,826 94,531 94,531 201,528 100% (l) Total annual consumption by class. (2) System peak month consumption (January 2004). (3) [ndividual class maximum monthly demands, whenever they occur during the year. (4) Total annual consumption by class, divided by 12 months. (5) Class maximum demand (col 3), less class average demand (col 4). (6) System peak month demand (col 2) less the total system average demand (col 4). (7) Ratio of each line to the total for the Process Demand Alloc Basis (col 5), times the System Excess Demand (col 6) (8) Sum of columns 4 and 7. (9) Ratio of each line to the total for column 8. P:\004712 Hutchinson\Gas & Elec Rate Study\Gas Cost of Service\Avg_Excess Demand 1 i i w s s N f 1 e s 1 1 Hutchinson Utilities, Minnesota Allocation of Gas Revenue Requ;remenis 2004 Test Year Total Residential Corninercial Lgelndus H 77 Demand Component Purchased Gas Expense Retail 5400,059 5181,377 5133.323 Transmission Operation 36.296 14.737 11.095 Transmission Maintenance 3.455 1.403 1.056 Distribution Operation 226,063 91.785 69,104 Distribution Maintenance 34,726 14.099 10,615 Adininisirative & General 44,751 18.169 13.680 Depreciation -Gas 414,671 168,362 126,758 Other Income (2,957) (1,201) (90.4) Other Expenses 1,198.809 486,732 366.455 Credit for Elec DivTrantiport Rev (1,100,000) (446.614) (336,251) Credit for New Ulm Transport Rev (550,257) (223,412) (168,20-1) Margin 243.060 98.686 74.299 Total Demand 948,676 404,123 301,026 Commodity Component Purchased Gas Expense -Retail 5.427,584 2.648.767 2.261,331 Total Commodity 5,427,584 2,648,767 2,261,331 Customer Services Component Cust Accounting & Collecting 76,092 59,482 16,283 Administrative & General 11,330 8,857 2,425 Other Expenses 167 130 36 Margin 69.673 54.465 14,910 Total Customer Services 157,262 122,934 33,654 Customer Facilities Component Distribution Opet-ation 220,354 107,973 82,763 Distribution Maintenance 33,849 16,586 12,713 Administrative & General 37,851 18,547 14,216 Depreciation -Gas 404,197 198,057 151,813 Other (Income) (2,883) (1,412) (1,083) Other Expenses 556 2.73 209 Margin 551.992 270.476 207.323 Total Customer Facilities 1,245,916 610,499 467,955 Revenue Component Sales Expense 51,291 19,401 15,700 Other (Inc omc) (81,386) (30,784) (24,911) Contribution to the City 2-7-8L20 105.237 85.160 Total Revenue 248,125 93,853 75,948 Direct Component Purchased Gas Expense -3M 2.230.676 Total Direct 2,230,676 0 0 Revenue Requirements 510,258,240 $3,880,177 53.139,914 Total Revenues 510.255.238 53,867,185 53,197.363 Percent Rev Requirements 100% 37.8% 30.6% Percent Revenues 100% 37.7°•0 31.2% Percent Change 0.3% -1.8% (1) [lased on Demand, Commodity, Customer Services, Customer Facilities and Direct expenses. (2) Direct assignment to 3M P:\004712 Hutchinson%Gas & Elec Rate Study\Gas Cost of Setviee\Allocation_Unbundled 522,001 1.948 185 12.133 1.864 2,402 22,256 (159) 64.340 (59,037) (29,532) 13.045 51,446 517.486 517,486 131 19 0 120 270 11,847 1,820 2,035 21,731 (155) 30 29.677 66,985 3,260 (5,172) 17,682 15,769 0 $651,955 S751.024 6.4% 7 3% -13.2% Exhibit 3-1 319 Allocation $63.357 Dem- 1 8,516 Dem -2 811 Dem -2 53,042 Dem -2 8,148 Dem -2 10.500 Dem -2 97,296 Dem -2 (694) Dem -2 281,281 Dem -2 (258,098) Dem -2 (129,109) Dcm•2 57,020 Dem -2 192,082 0 Contin 0 196 CustSery 29 CusiSery 0 CustSery 179 CustSm 405 17,770 CusiFacil 2,730 CustFacil 3,052 CustFacil 32,597 CustFacil (232) CustFacil 45 CusiFacil 44.515 CustFacil 100,477 12,931 (1) (20,518) (1) 70.142 (1) 62,555 2.230.676 (2) 2.,230.676 $2,586,194 $2,439:666 25 2% 23.8% 6.0% Section 4 UNBUNDLED RATES Based on the results of the cost of' service study presented in Section 3 of this report, electric and gas unbundled rates have been developed. The unbundled gas rates have been designed to collect the same total revenue as HU's existing gas retail rates, including the Duel Cost Adjustment revenues collected in the 2004 `fest Year. Due to the adjustments made to the Electric Division's 2004 'rest Year revenue requirements to better reflect costs during the Study Period, the unbundled electric rates represent a revenue increase of 7.0 percent, including the Power Cost Adjustment (PCA) revenues collected in the 2004 Test Year. Electric Rate Components HU's electric rates have been unbundled into five components: wholesale purchased power, transmission, distribution, customer, and contribution to City. Each of these components is described below. Wholesale Power The wholesale puwer component consists of purchased power and generation demand and energy charges. l -or- retail classes billed on the basis of demand and energy, the retail demand portion of the wholesale component represents wholesale dernand charges and the energy portion represents wholesale energy charges. For retail classes billed on the basis of energy only, the retail energy charge represents both wholesale demand and energy charges. Transmission The transmission component represents transmission operations and maintenance charges. The transmission charge is a dernand related charge. This is shown as a retail demand charge for retail demand and energy billed classes and as an energy charge for energy only retail classes. Distribution The majority of' HU's local electric revenue requirements are reflected in the distribution portion of the unbundled retail rates. It includes a portion of the O&M expenses on the distribution system, the majority of the depreciation expenses, certain A&G and non-operating expenses, and a credit for non-operating income. The distribution charge is a dernand related charge. This is shown as a retail demand charge for retail demand and energy billed classes and as an energy charge for energy only retail classes. ©1600 Section 4 Customer I The customer charge reflects both customer service and customer facilities expenses, including accounting and collecting charges, certain A&G expenses, O&M and depreciation on the customer portion of the system, and a credit for non-operating income. The customer charge is a monthly per customer charge. 1 Contribution to the City The Utility contributes cash to the City. The cost of this contribution is expressed as an energy charge. Unbundled Electric Rates Unbundled electric costs and resulting retail rates for the Residential, Small General Service, Large General Service and Large Industrial classes are shown in the tables below. "Ilse individual unbundled components have been summed to show a total unbundled rate. Note that the following rates are not necessarily the proposed rates recommended by R. W. Beck as a result of this study. The following unbundled rates: ■ Generate the same revenues as the adjusted Test Year 2004 revenue requirements, including the revenues collected from the PCA. ■ Reflect the results of the cost -of -service analysis. The cost to serve each customer class is different. The cost depends on the combination of demand needs, the timing and amount energy use compared to demand and the cost of customer facilities and services. ■ Reflect the results of the unbundling of electric utility services. i L LI 4-2 Hutchinson Utilities 81600 1 131600 R. W. Beck 4-3 Unbundled Rates Unbundled Electric Costs _ Rate Class _ _— Unbundled Rate Res! Small Large Large Total Rate Component All Elec General General Industrial Service Service - Purch Pwr $328,959 $99,798 $506,846 $721,408 $1,657,011 Demand Wholesale Purch Pwr Energy 2,275,672 884,097 3,510,820 6,939,513 13,610,102 Power Gen 518,590 157,547 792,376 1,138,572 2,607,084 Demand Gen Energy 190,504 74,011 293,903 580,931 1,139,349 Demand 10,513 3,194 16,063 23,081 52,851 Transmission Energy _ Demand 669,531 200,698 1,063,904 1,432,597 3,366,730 Distribution Energy Customer Customer 563,789 127,575 235,675 67,958 994,997 City Energy 126.287 42,864 177,883 302.145 649.180 Total $4,683,846 $1,589,783 $6,597,470 $11,206,206 $24,077,304 131600 R. W. Beck 4-3 Section 4 Unbundled Electric Rates Rate Class Unbundled Rate Rate Component Res/ Small Large Large All Elec General General Industrial Service Service Purch Pwr Demand ($/kW) $2.12 $2.49 Wholesale Power Purch Pwr Energy ($/kWh) $0.0536 $0.0521 0.046B 0.0468 Gen Demand ($/kW) 3.32 3.93 Gen Energy ($/kWh) 0.0146 0.0123 0.0039 0.0039 Demand ($/kW) 0.07 0.08 Transmission Energy ($/kWh) 0.0002 0.0002 _ Demand ($/kW) 4.46 4.94 Distribution Energy ($/kWh) 0.0138 0.0106 Customer Customer ($Imo) 8.00 13.34 166.44 2,831.60 City Energy ($/kWh) 0.0026 0.0023 0.0024 0.0020 Customer ($Imo) $8.00 $13.34 $166.44 $2,831.60 Total Demand ($/kW) Energy ($/kWh) $0.0847 $0.0774 $9.96 $0.0531 $11.44 $0.0528 4-4 Hutchinson Utilities B1600 .31 - ---- --- -- ---- – -- — Unbundled Rates Gas Rate Components HU's gas rates have been unbundled into Five components: purchased gas/ production, transmission, distribution, customer and contribution to the City. Each of these components is described below. Purchased Gas/ Production 0 The purchased gas/ production component represents the cost of wholesale gas delivered to the City and certain production expenses. It is expressed as both a WAdemand and commodity component based on consumption. Transmission 09 The transmission component represents transmission operations and maintenance charges. The transmission charge is a demand related charge. It is expressed as a demand component based on consumption. Distribution 'rhe distribution portion of the unbundled rate represents O&M expenses on the distribution system, depreciation, certain A&G expenses, a credit for non-operating income plus retained earnings requirements. It is expressed as a demand component based on consumption. dCustomer The customer charge reflects both customer service and customer facilities expenses, including accounting and collecting charges, certain A&G expenses, O&M and depreciation on the customer portion of the system, a credit for non-operating income and retained earnings requirements. The customer charge is a monthly per customer dcharge. Contribution to the City INThe Utility contributes cash to the City. The cost of this contribution is expressed as a consumption charge. dUnbundled Gas Rates Unbundled natural gas costs and resulting retail rates for the Residential, Commercial 01 and large Industrial rate classes are shown in [tie tables below. Costs associated with 3M have been eliminated from the unbundled analysis, due to the fact that 3M has contract rates. The Small InteITuptible and targe Intemiptible rate classes have been incorporated into other appropriate rate classes, due to plans to eliminate all interruptible rates. The individual unbundled components have been surnmed to show 1316-30 R. W. Beck 4-5 Section 4 a total unbundled rate. Nate that the following rales are riot necessarily the proposed rates recommended by R. W. Beck as a result of this study. The following unbundled rates: ■ Generate revenue equal to the 2004 Test Year revenue requirements. ■ Reflect the results of the cost -of -service analysis. The cost to serve each customer class is different. The cost depends on the amount and timing of natural gas use and the cost ol'customer facilities and services_ ■ Reflect the results of the unbundling of gas utility services Unbundled Gas Costs Rate Class Unbundled Rate Residential Commercial Large Industrial Total Rate Component Purchase! Dernand $181,377 $133,323 $22,001 $336,702 Produclion Commodity 2,648,767 2,261,331 _ 517,486 5,427,584 Transmission Demand 16,140 12,151 2,133 30,424 204,104 153,371 26,759 384,234 DistributionDemand Commodity Customer Customer 724,551 494,578 65,894 1,285,024 City Commodity 105.237 85,160 17,682 208.078 Total---- - _ $3,880,177 $3,139,914 $651,955 $7,672,046 4-6 Hutchinson Utilities B1600 17 Unbundled Rates Unbundled Gas Rates Unbundled Rate Rate Component Residential Rate Class Commercial Large Industrial Purchase/ Demand ($/McO $0.40 $0.35 $0.25 Production Commodity ($1McO 5.91 5.91 5.91 Transmission Demand ($/Mcf) _ 0.04 0.03 _ _ _ _ 0.02 Demand ($/Mcf) 0.46 0.40 0.31 Distribution Commodity ($/Mco Customer Customer ($Imo) 13.25 82.59 5,491.19 City ($/McQ 0.23 _ 0.22 0.20 _Commodity _ Customer ($Imo) _ _ _ $13.25 82.59 $5,491.19 Total --- _—. Commodity ($IMcf) --..-- —_— $7.04 _ _ _ _ $6.91__ _ _ ____ —__ $6.69 F1 1600 R. W. Reck 4-7 Section 5 PROPOSED RATES Retail rate adjustments are generally made in response to revenue requirements and cost-of—service. In Section 2 of this report, the Electric and Gas Divisions' estimated annual operating results for the Study Period were presented. These two sets of . operating results were developed utilizing HU's existing rates. Section 3 of this report summarizes the results of the cost of service analysis for both Divisions. Section 4 presents an analysis of unbundled rates for both Divisions. All of these factors have been considered in the development of the proposed Electric and Gas rates included in this section of the Report. Electric Division Rate Design Forecasted revenues at current rates are lower than necessary to adequately cover forecasted revenue requirements during the Study Period. The cost -of -service analysis has shown that current rates are not completely in line with the cost to serve each of the rate classes. New rates have been designed to be implemented in January 2006 that provides adequate revenues to cover revenue requirements and more accurately reflect the cost to serve each class. Proposed Rates 1. Revenues from the Residential rate have been adjusted to include PCA revenues forecasted to be collected from this rate in 2006. After including PCA revenues, Residential revenues have been increased by 9.0 percent per year. A customer charge has been introduced and the two -block energy rate has been changed to a single block rate. 2. The All Electric Residential rate has been eliminated. All customers will be moved to the Residential rate. 3. Revenues from the Small General Service rate have been adjusted to include PCA revenues forecasted to be collected from this rate in 2006. After including PCA revenues, Small General Service revenues have been increased by 6.5 percent per year. A customer charge has been introduced and the two -season four -block energy rate has been simplified to an annual two -block rate. 4. Revenues from the large General Service rate have been adjusted to include PCA revenues forecasted to be collected from this rate in 2006. After including PCA revenues, Large General Service revenues have been increased by 8.1 percent per year. The demand charge has been increased. The energy charge has been simplified from a three -block energy rate to a single block rate. 5. Revenues from the Large Industrial rate have been adjusted to include PCA revenues forecasted to be collected from this rate in 2006. After including PCA revenues, Large Industrial revenues have been increased by 8.2 percent per year. D1600 Section 5 The $16,960 per month minimum charge has been eliminated and all metered demand will be billed. The demand charge has been increased and the energy charge has been decreased. Hutchinson Utilities Current And Proposed Retail Electric Rates Class Rate Component Current Rate Current Rate Proposed Including PCA I'f Rate Residential Monthly Charge None None $6.50 i First 300 kWh/mo $0.0714 $0.0999 Over 300 kWh/mo 0.0514 0.0799 All kWh/mo 0.0872 All Electric Monthly Charge None None Eliminate Res Rate First 300 kWh/mo 0.0734 0.1019 Next 500 kWh/mo 0.0534 0.0819 Over 800 kWh/mo 0.0459 0.0744 Small General Monthly Charge None None 10.00 Service Oct -May First 500 kWh/mo 0.0751 0.1036 Oct -May Next 1500 kWh/mo 0.0592 0.0877 Oct -May Next 2000 kWh/mo 0.0539 0.0824 Oct -May Over 4000 kWh/mo 0.0486 0.0771 Jun -Sep First 500 kWh/mo 0.0751 0.1036 Jun -Sep Next 1500 kWh/mo 0.0619 0.0904 Jun -Sep Next 2000 kWh/mo 0.0566 0.0851 Jun -Sep Over 4000 kWh/mo 0.0513 0.0798 First 2000 kWhlmo 0.0911 Over 2000 kWh/mo 0.0855 Large General Demand per kW/mo 3.65 3.65 6.00 I Service First 2000 kWh/mo 0.0608 0.0893 Next 2000 kWh/mo 0.0502 0.0787 Over 4000 kWh/mo 0.0449 0.0734 All kWh/mo 0.0737 Large Fixed Fee _ 16,960 16,960 Industrial (includes first 4000 kva) Demand per kva 2.12 2.12 7.00 All kWh/mo 0.0410 0.0695 0.0675 V) Current rates include forecasted 2006 PCA of $0.0285 per kWh. Proposed rates assume a PCA of $0.00 I I 5-2 Hutchinson Utilities B 160 Proposed Rates Power Cost Adjustment The Power Cost Adjustment (PCA) formula applies to customers on the Residential, Small General Service, Large General Service and Large Industrial rates. The PCA is calculated and applied each month to these customers. Currently the PCA base rate is $0.0345 per kWh. Costs in the current PCA monthly calculation include purchased power, natural gas and internal production costs of electric generation, the cost of HU's internal use of gas, some insurance costs, bond payment, some payroll costs and computer software expenses related to purchased power and generation. As many of these expenses are fixed and are known in advance, it is recommended that the Electric Division's PCA formula be simplified to include only the costs associated with purchased power and generation that tend to fluctuate month to month and cannot be controlled by HU. A new Power Cost Adjustment formula has been designed that includes only the wholesale purchased power costs from CMMPA and market purchases, plus fuel expense (natural gas and fuel oil) used for HU's generation to serve its own retail customers. The base rate of $0.0557 per kWh in the formula below was determined by applying the proposed PCA formula on an annual basis, using 2006 estimated retail sales and wholesale power purchase and generation costs. Proposed PCA Formula This calculation is designed to be used once per month. (A+B+C)/D—$0.0557=N A = Purchased power cost from previous month. B = Purchased fuel cost (natural gas and fuel oil) from previous month. C = Unrecovered (positive) or excess (negative) PCA revenues collected in the previous month. D = Estimated retail sales (kWh) for the coming month. N = PCA for the coming month ($/kWh) There are two options available to the Electric Division in its application of the PCA formula. Option l: Each month, the Electric Division will use the PCA formula to calculate its average monthly purchased power and generation costs per retail kWh sold and determine the adjustment to customer bills needed, based on the difference between the new PCA base rate of $0.0557 per kWh and the calculated monthly cost per kWh. If the average purchased power cost is lower than the base rate, the adjustment will be a credit to customers' bills. if the average purchased power cost is higher than the base rate, the adjustment will be an additional charge to customers' bills. Option 2 (Recommended): The Electric Division will initiate a Rate Stabilization Fund in which it keeps a running balance of the amount of money related to the PCA revenues. The Electric Division then determines, based on the balance in the account, 13100 R. W. Beck 5-3 Section 5 when to apply a PCA charge or credit, as appropriate, in order to keep the balance in I the PCA account at a reasonable level. This is the recommended method, as it provides the Electric Division with a greater level of control over the sometimes widely fluctuating monthly PCA adjustments that are applied to customers' bills. Street Light Costs An analysis of the costs for the Electric Division to install, maintain and supply electricity to the city's street lights has been performed. Following is the table showing annual and monthly costs for each type of fixture. Currently, the total annual cost for the street lighting; system is estimated at $119,904. This cost will increase if HU becomes responsible for purchasing arid installing street lights in the future. Hutchinson Utilities crser t tr,hte r—t AnAlu%ls Oescr,ption Wattage Number of I Fixtures Capital Cos! (1) per unit Annual Carrying Cost per unit I Annual Energy Cost per unit Annual I Demand Cost per unit Annual 08M Cost per unit Annual Cost per Unit Monthly Cost per Unit Total Annual C051 r_�Sq Wholesale Energy Cost $00511 0l Carry Cost/Capdai 10.00% O&M per year $ 48,000 150 W lips 150 1,283 $3963 $2.44 $32.30 $74.37 $6.20 $95.421 750 W HPS 250 113 66.05 4.07 $32.30 310242 854 $11.574 400 W HPS 400 5 105.58 651 $32.30 5144.49 17.04 $722 175 W MV 175 16 46.23 2.85 $32.30 $81.39 6.78 $1,302 250 W MV 250 40 66.05 407 $32.30 $102.42 8.54 $4.097 400WMV 400 9 1.35.68 651 $32.30 $14449 1204 $1,300 s0 FlU Owne 150 W HPS 150 20 $2,000 $700 3963 2.44 $32.30 5274.37 2285 I4A7 70181 1,466 $119,804 Assumptions_ IlgrnLLG Percent On 50% Months on Peak 3 Losses 18% Wholesale Dmd Cost $4.60 �1 Wholesale Energy Cost $00511 0l Carry Cost/Capdai 10.00% O&M per year $ 48,000 (1) The City purchased and installed of street lights under the heading 'City Owned' No capital costs are associated with these lights (7) 2006 Xcel norrsurnmer demand ung per kW, rnckrdrng 6 9% rale rruense far tar (3) 2006 average energy fast per kWh, ircka5^B !,Wchases aro generation 5-4 Hutchinson Utilities F31600 Proposed Rates Rate Comparison with Xcel Energy Xcel Energy is an investor owned utility and is the largest provider of retail electric service in Miruiesota. Shown below is a comparison of typical monthly bills for residential, small general service and large general service customers. The comparison is shown for HlYs existing and Proposed rates and for Xcel's existing and proposed rates. The proposed rate for Xcel assumes an 8.05 percent increase over Xcel's current rate. This assumption is based on Xcel's request in its pending retail rate case before the Minnesota Public Utilities Commission. The following bill comparisons reflect M1SO charges which have increased utility costs significantly since the advent of MISO "Day 2" market operations. These operations commenced on April 1, 2005. Bill Comparison Average Monthly 2005 Bill Rate Class HU Rates Xcel Rates Existing (1) Proposed (2) Existing (3) Proposed (a) Residential (5) $67 $72 $64 $69 Small General Service (6) 188 192 165 178 Large General Service (7) 4753 5030 3596 3885 (1) Includes a PCA charge of 3.05 cenlslkWh average 2005 PCA. (2) Includes a PCA charge or 0 cenlsrkWh (3) Includes applicable Xcel rate adjustrnents. including average 2005 FCA of 0.779 cenlsrkWh. (4) Assuming B 05% increase (5) Assuming 750 kWh and average annual rale for Xcel. (6) Assuming 2,000 kWh and average annual rale for Xcel and HU. (7) Assuming 175 kW and 54,000 kWh and average annual rale for Xcel. Estimated Operating Results at Proposed Rates The estimated Electric Division operating results for the Study Period incorporating the proposed rates and the new PCA base rate beginning in 2006 are shown in the table below. The new rates were designed to better reflect the cost -of -service and to provide sufficient revenue to meet revenue requirements during the Study Period. Our summary of HU's combined electric and gas cash reserves is shown at the end of this Section. B1600 R. W. Beck 5-5 Section 5 Year Electric Division Estimated Annual Operating Results Proposed Rates 2005 2006 2007 2008 2009 Estimated Revenues $26,153,704 $27,801,800 $27,498,684 $27,388,999 $27,306,385 Estimated Revenue Requirements 25.080.448 26.128.338 25,778,935 25.833.415 25.722,850 Net Income $1,073,256 $1,673,462 $1,719,750 $1,555,585 $1,583,535 Operating Income as 6.0 /0 1.7 /0 o 1.7 /0 1.2 /0 o 1.1/o Percent of Net Assets Net Income as Percent of Net Assets 2.7% 4.2% 4.3% 3.9% 3.8% 5-6 Hutchinson Utilities B 160 i _ Proposed Rates Gas Division Rate Design As stated in Section 2, forecasted revenues at existing rates are expected to be sufficient to adequately cover forecasted revenue requirements during the Study Period. Our cost -of -service analysis has shown that current revenues for the Large = Industrial Rate are higher than the cost to serve that rate class. The unbundled rate analysis has shown that the customer, commodity and demand rate components are not in line with unbundled costs. Additionally, the Fuel Cost Adjustment (FCA) base rate utilized in the FCA calculation no longer reflects the average cost of purchased gas. R. W. Beck has designed new rates for HU to consider for implementation in January 2006. These new rates are expected to provide approximately the same revenues as under existing rates, but more closely reflect the results of the cost -of -service and unbundled rate analyses. All of these rates are based on a new FCA base rate that better reflects the expected cost of wholesale gas purchases Proposed Rates 1. A new Residential rate has been designed to include FCA revenues forecasted to be collected from this rate in 2006. No additional revenues will be collected from the Residential class beyond the amount forecasted using existing rates. A customer charge has been introduced and the three -block commodity rate has been changed to a single block rate. 2. A new Commercial rate has been designed to include FCA revenues forecasted to be collected from this rate in 2006. No additional revenues will be collected from the Commercial class beyond the amount forecasted using existing rates. A customer charge has been introduced and the three -block commodity rate has been changed to a single block rate. 3. A -new Large Industrial rate has been designed to include FCA revenues forecasted to be collected from this rate in 2006. The demand rate has been increased to reflect the results of the unbundled rate analysis. The commodity rate has been adjusted to result in 5 percent less total revenue from this class, based on results of the cost of service analysis. 4. The Interruptible rate has been eliminated, as it is no longer needed, due to HU's gas pipeline. Fuel Cost Adjustment The Fuel Cost Adjustment (FCA) formula applies to customers on the Residential, Commercial and Large Industrial rates. The FCA is calculated and applied each month to these customers. Currently the FCA base rate is $3.85 per MCF. This rate is low as compared to current purchased gas costs and has resulted in high FCA adjustment rates applied to customers' bills each month. 'rhe current FCA monthly calculation includes the cost of gas purchased to serve the Gas Division's retail customers, not including 3M. It also includes gas pipeline costs, 61600 R. W. Beck 5-7 Section 5 1 and some payroll expenses. As the gas pipeline and payroll expenses are fixed and are known in advance, it is recommended that the Gas Division's FCA formula be simplified to include only the costs associated with purchased gas that tend to fluctuate month to month and cannot be controlled by HU. A new Fuel Cost Adjustment formula has been designed that includes only the cost of gas purchased to serve the Gas Division's retail customers, not including 3M. This also does not include the cost of gas used by the Electric Division for power generation. The base rate of $7.85 per _ MCF in the formula below was determined by applying the proposed FCA formula on an annual basis, using 2006 estimated retail sales and the cost of gas purchased to serve non -3M retail custorners. Proposed FCA Formula This calculation is designed to be used once per month. (A + B) / C — $7.85 = N A = Purchased gas cost from previous month. B = Unrecovered (positive) or excess (negative) FCA revenues collected in the previous month. C = Estimated retail sales (MCF) for the coming month, not including 3M. N = FCA for the coming month ($/MCF) There are two options available to the Gas Division in its application of the FCA formula. Option l: Each month, the Gas Division will use the FCA formula to calculate its average monthly purchased gas costs per retail MCF sold and determine the adjustment to customer bills needed, based on the difference between the new FCA base rate of $7.85 per MCF and the calculated monthly cost per MCF. if the average purchased gas cost is lower than the base rate, the adjustment will be a credit to customers' bills. if the average purchased power cost is higher than the base rate, the adjustment will be an additional charge to customers' bills. Option 2 (Recommended): The Gas Division will initiate a Gas Rate Stabilization Fund in which it keeps a running balance of the amount of money related to the FCA revenues. The Gas Division then determines, based on the balance in the account, when to apply a FCA charge or credit, as appropriate, in order to keep the balance in the FCA account at a reasonable level. This is the recommended method, as it provides the Gas Division with a greater level of control over the sometimes widely fluctuating monthly FCA adjustments that are applied to customers' bills. 5-8 Hutchinson Utilities B1600 Proposed Rates Hutchinson Utilities Current And Proposed Retail Gas Rates Class Rate Component Current Rate Current Rate Proposed Including FCA Rate (1) Residential Commercial Large Industrial Monthly Charge (Includes first 400 cflmo Next 3600 cl/mo per MCF Over 4000 cf/mo per MCF Monthly Charge All MCF/mo Monthly Charge (Includes first 400 cf/mo Next 3600 cf/mo per MCF Over 4000 cl/mo per MCF Monthly Charge All MCF/mo Demand per MCF $3.32 $5.30 5.05 10.00 4.58 9.53 $6.50 9.08 3.32 - ........... 5.30 ._. 5.05 10.00 4.58 9.53 31.50 9.08 4.31 4.31 10.00 All MCF/mo _ 4.33 9.28 8.54 (') Current rales include forecasted 2006 FCA of $4.95 per MCF. Proposed rates assume a FCA of $0.00 per MCF. Rate Comparison with Xcel Energy Xcel Energy is an investor owned utility that provides retail gas service in Minnesota. Shown below is a comparison of typical monthly bills for residential and commercial customers for HU's and Xcel's retail gas rates. Average Monthly Bill Comparison Rate Class HL Rates +') Xcel Rates (2) Residential (3) $94 $99 Commercial (4) 535 536 (1) Includes a FCA charge of $6.501MCF (2) Includes applicable Xcel rale adjustments (3) Assuming 8 2 MCF (4) Assuming 48 MCF HU Gas Service Contract with 3M HU Provides natural gas service to 3M under the terms of an expired agreement between HU and 3M. Based on the expired agreement, 3M receives both firm and interruptible gas service. HU purchases wholesale gas in the market on 3M's behalf. HU is reimbursed for gas purchased and receives additional payment from 3M for D1600 R. W. Beck 5-9 Section 5 1 local operating expenses. We recommend that HU and 3M meet to revisit the terms of the expired agreement and put in place a new agreement that is acceptable to both parties. Additional Recommendations 1 m R. W. Heck recommends that HU establish a reserve fund to hold at least 1 '/: month of operating expenses for both its Electric and Gas Divisions. This is a recognized practice among many utilities, in order to provide a hedge against natural disasters and other unforeseen occurrences. Estimated Operating Results At Proposed Rates The estimated Gas Division operating results for the Study Period incorporating the proposed rates are shown in the table below. The new rates were designed to provide approximately the same revenue as under existing rates. The operating results below assume implementation of the proposed rates in combination with the proposed FCA base rate calculation in January 2006. Our summary of HU's combined electric and gas cash reserves is shown at the end of this Section. Gas Division Estimated Annual Operating Results Proposed Rates Year 2005 2006 2007 2008 2009 Estimated Revenues $12,384,358 $15,043,475 $14,157,840 $13,131,816 $12,108,328 Estimated Revenue 12,006,162 13,971,082 13,117,985 12,116,188 11.142,497 Requirements Net Income $378,196 $1,072,393 $1,039,855 $1,015,627 $965,831 Operating Income as 3.6% 8.1% 8.4% 8.4% 8.2% Percent of Net Assets Net Income as 1.2% 3.4% 3.5% 3.5% 3.4% Percent of Net Assets Gas and Electric Combined Cash Reserves Combined cash reserves for the Electric and Gas Divisions are presented below. Reserves at proposed rates are estimated to be $9,077.576 by the end of 2009. 5-10 Hutchinson Utilities 81600 Proposed Rates Estimated Combined Cash Reserves Proposed Rates Year 2005 2006 2007 2008 2009 Beginning of Year Cash $1,900,000 $2,933,851 $3,602,473 $5,671,812 $7,976,809 in Bank Plus Electric Net Income 1,073,256 1,673,462 1,719,750 1,555,585 1,583,535 Plus Gas Net Income 378,196 1,072,393 1,039,855 1,015,627 965,831 Plus Big Stone Expense 200,000 Reimbursement Less Electric Capital (900,000) (1,635,395) (1,819,500) (1,947,000) (3,385,500) Improvements Less Gas Capital (1,700,000) (2,514,735) (1,062,000) (576,500) (374,500) Improvements Less Debt Service (970,000) (975,000) (995,000) (1,025,000) (1,055,000) Principal Plus Depreciation 2.,952,399 3,047,897 3,186,235 3,282,285 3,366,401 End of Year Cash in $2,933,851 $3,602,473 $5,671,812 $7,976,809 $9,077,576 Bank Rate Comparisons Exhibits 5-A through 5-D show graphically the effect of the proposed rates on the Electric Division's monthly bills for Residential, Small General Service and Large General Service customer classes based on a range of monthly consumption for each class. Exhibits 5-E and 5-F show the effect of the proposed rates on the Gas Division's monthly bills for the Residential and Commercial customer classes based on a range of monthly consumption for each class. Exhibit 5-A graphs the average monthly electric bill under the current and proposed rate for the Residential customers. All monthly bills at proposed rates are higher than the monthly bills at current rates. Exhibits 5-B and 5-C graph the average summer and winter monthly electric bill under the current and proposed rate for the Small General Service customers. All monthly bills at proposed rates are higher than the monthly bills at current rates. Exhibit 5-D graphs the average monthly electric bill under the current and proposed rate for the Large General Service customers. All monthly bills at proposed rates are higher than the monthly bills at current rates. 91600 R. W. Beck 5-11 Section 5 Exhibit 5-E graphs the average monthly gas bill under the current and proposed rate I for the Residential customers. The monthly bill at proposed rates is higher than the monthly bill at current rates for consumption from 0-7 MCF per month and lower than the bill at current rates for consumption more than 7 MCF per month. f Exhibit 5-F graphs the average monthly gas bill under the current and proposed rate for the Commercial customers. The monthly bill at proposed rates is higher than the monthly bill at current rates for consumption from 0-60 MCF per month and lower than the bill at current rates for consumption more than 60 MCF per month. Transfers to the City Hutchinson Utilities, like most municipal utilities, makes a cash contribution from I both the Electric and Gas Divisions to the City of Hutchinson. These contributions are often referred to as payments in lieu of taxes, transfers to the general fund or contributions to the city. Cities have made an investment when they establish and operate a municipally owned utility. Contributions back to the city are a usual and proper recognition of the city's investment. There are several varied methods for determining the amount to be transferred from a utility to a city. Some common methods are summarized below. 1. Annual amount as set by utility or city. 2. Annual amount as negotiated between utility and city. 3. Fixed annual payment, may or may not be adjusted for inflation. 4. Percentage of operating revenues. 5. Percentage of operating or net income. 6. Percentage of plant in service. 7. Fixed amount per unit of service (kWh or MCF) sold. In our recommendations to utilities and cities, we advocate for fair, stable and predictable transfers from utilities to their city. Based on the three principles stated above, we generally recommend either method 6 or 7 as shown. 5-12 Hutchinson Utilities s1600 Exhibit 5-A Hutchinson Utilities, Minnesota Residential Electric Rate Monthly Bill Comparison $220 $200 $180 -POO - $160 ---- - $140 00 $120 $100 -- C O $80 _ -- $60 — $40 - $20 $0 100 300 500 700 900 1100 1300 1500 1700 1900 2100 kWh —E—Current -4-- Proposed Exhibit 5-B Hutchinson Utilities, Minnesota Small General Service Electric Rate Summer Monthly Bill Comparison $550 $500 $450 $400 . ......... $350 . ......... 'S Ii wu $250 0 $200 $150 . . .... . . . . ... . ... . ........... $100 . ...... . $50 9 r**OANOP $0 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 kWh 1-11—Current —4—Proposel Exhibit 5-C Hutchinson Utilities, Minnesota Small General Service Electric Rate Winter Monthly Bill Comparison $550 $500 $450 $400 $350 $300 21 -5 r- $250 $200 $150 $100 $50 so. . . . . . . . . . . . . . . . . . . . . . . . . . . ... . . . 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 kWh --II—Current --*--Proposed $9,000 $8,000 $7,000 $6,000 ao $5,000 G $4,000 0 $3,000 $2,000 $1,000 $0 Hutchinson Utilities, Minnesota 150 kW Large General Service Electric Rate Monthly Bill Comparison 5% 15% 25% 35% 45% 55% Load Factor —@-- Current -4—Proposed Exhibit 5-D 65% 75% 85% 95% Exhibit 5-E Hutchinson Utilities, Minnesota Residential Gas Rate Monthly Bill Comparison $200 $180 -- $160 $140 - – -.-.----- .r $120 — ---- m $100 – $80 — - $60 --- $40 -.—_.-.._....--------- ----- $20 $0 1 3 5 7 9 11 13 15 17 19 MCF f Current —*—Proposed Exhibit 5-F Hutchinson Utilities, Minnesota Commercial Gas Rate Monthly Bill Comparison $2,000 $1,800 . ......................................... $1,600 . . . .... ... .. . ..... $1,400 $1,200 $1,000 - ----- - $800 . ..... . . . $600 . . . . ........... ... ------ VOOO $400 ......... . $200 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $0 10 30 50 70 90 110 130 150 170 190 MCF —*--Current —*--Proposed Final Report Electric and Gas Cost -of -Service and Unbundled Rate Study Hutchinson Utilities May 2012 SAIL Electric and Gas Cost -of -Service and Unbundled Rate Study Hutchinson Utilities Table of Contents ol'Trc ismi[[ul List !!l'Tuhl"s List n/'Fi-Ures Section 1 Introduction Section 2 Estimated Operating Results — Existing Rates ElectricDivision...................................................................................... Historical Electric Requirements................................................... Estimated Flectric Requirements................................................... Estimated Revenue Requirements ................................................. Generation and Purchased Power Expenses ...................... Operating and i\•1aintenance Expenses ............................... Other Income and Expenses .............................................. Payment in lieu of'I'axes Services -in -bind ...................... Capital Improvements........................................................ DebtService ....................................................................... Revenue ReClUlrements...................................................... Estimated Revenues FxistinT Rates ............................................ i:stimated Electric Operating Results and Cash Reserves ............. GasDivision ............................................................................................ Estimated Gas Requirements......................................................... E=stimated Revenue Requirements ................................................. Purchased Gas Expenses .................................................... Operatim, Expenses........................................................... Payment in Lieu of Taxes .................................................. Other Income and Expenses .............................................. Capital Improvements........................................................ DebtService ....................................................................... Revenue Requirements...................................................... Estimated Revenues -- Existim, Rates ............................................ Estimated Gas Operating Results and Cash Reserves ................... Combined Electric and Gas Results ............................................... Section 3 Cost -of -Service Study ElectricDivision .................................................................................... Classification ol'Costs................................................................. B I.K45 .2-1 .2-1 .24 .2-4 .2-4 .2-5 2-5 . 2-5 .2-5 .2-6 .2-7 .1-7 .2-7 .2-7 .2-8 .2-9 .2-9 .2-9 .2-9 2-9 .-)-g 2-l0 2-11 3-1 3-1 SAIC. Table of Contents Allocation to C LISlomel- Classifications ............................. Demand Allocations .............................................. Encroy Allocations ................................................ Customer Allocations ............................................ Cost-ol-Service Study Results ........................................... CasDivision ................................................................................ Classification of ('osis ....................................................... Allocation to Customer Classi I ications ............................. Demand Allocations .............................................. Ener,,v Allocations ................................................ Customer Allocations ............................................ Cost-01'SCI-Vice Stttdy Results ........................................... Section 4 Unbundled Rates Electric Rate Components........................................................... Wholesale Powei................................................................ Transmission...................................................................... Distribution........................................................................ Customerr............................................................................ Unhandled Electric Rates .................................................. Gas Rate Components................................................................. Purchased Gas Production ................................................. T-ransmission...................................................................... DistrIbt.Ition........................................................................ Customerr............................................................................ l.11tht.Indled Gas Rates ........................................................ Section 5 Proposed Rates Electric Division Rate Dean= Table of Contents List of Tables Table 2-1 Historical Reeluirements............................................................................ ?-2 Table 2-2 Estimated Electric Requirements............................................................... . Table 2-3 Estimated Electric Purchases and Generation ........................................... 2-3 Table 2-4 Estimated Electric Generation and Purchased Power Expenses ................ 2-4 Table 2-5 Estimated Electric Operating Revenues — Existing Rates ......................... 2-5 Table 2-6 Estimated Electric Division Operating Results Existing Rates .............. 2-6 Table 2-7 Estimated Electric Division Cash Reserves -- Existing Rates ................... 2-6 Table 2-8 estimated Gas Requirements..................................................................... 2-7 Table 2-9 Estimated Wholesale Gas Comniodity Rates for Retail Customers.......... 2-8 Table 2-10 Estimated Wholesale Cas Expenses........................................................ 2-8 Table 2-11 Estimated Gas Operating ReVenues....................................................... 2-10 Table 2-12 Estimated Gas Division Operating Results ............................................ 2-10 Table 2-1 3 Estimated Gas Division Cash Reserves- Existing Rates ....................... 2-11 Table 2-14 Estimated Combined Electric and Gas Operating Results ExistingRates........................................................................................ 2-11 Table 2-15 Estimated Combined Electric and Gas Cash Reserves — Existing Rates 2-12 Table 3-1 Classification ol'Electric Division Costs — 2010 Test Fear ...................... 3-2 Table 3-2 Electric Division. Comparison ol' Revenucs and Allocated Cost -of -Service 2010 Test Yew................................................................. 3-4 Table 3-3 Electric Division. Percentage Comparison of Revenues and Allocated Cost -of -Service 2010 Test Fear ............................................... 3-5 Table 3-4 Classification of Gas DIN-ision Costs — 2010 Test Year ............................ 3-6 Table 3-5 Gas Division, Comparison of Revenues and Allocated Cost -of -Service 2010 Test Yearr................................................................ 3-8 Table 3-6 Gas Division, Percentage Comparison of Revenues and Allocated Cost -of -Service 2010 Test Year 9 Table 4-1 Unbundled Electric Costs.......................................................................... 4-2 Table 4-2 Unbundled Electric Rates.......................................................................... 4-3 Table 4-3 Unbundled Gas Costs................................................................................ 4-4 Table 4-4 Unbundled Gas Rates................................................................................ 4-5 Table 5-1 Current and Proposed Retail Electric Rates ............................................... 5-2 „i,a; SAIC Energy. Environment & InfrastruC[Ure, I.LC iii Table of Contents This report has been prepared for the use of the client for the specific purposes identified in the report. The conclusions, observations and recommendations contained herein attributed to SAIC constitute the opinions of SAIC. To the extent that statements, information and opinions provided by the client or others have been used in the preparation of this report. SAIC has relied upon the same to be accurate, and for which no assurances are intended and no representations or warranties are made. SAIC makes no certification and gives no assurances except as explicitly set forth in this report. -' - 2012 SAIC All rights reserved. h- SAIC Encruy. Environment & IntPastrLlCCUrc. I.I.0 „isa; SAIL May 23. 2012 Hutchinson Utilities Commission 225 Michigan Street SE Hutchinson. MN 55 350 Commission Members: Subject: Electric and Gas Cost of Ser -vice and Unbundled Rate Study Report Hutchinson Utilities enraged the services of SAIC to conduct an Electric and Gas Cost of Service and Unbundled Rate Study. The attached report presents our findings and recommendations based Oil our analysis. There are lour principal Components to the study. The first of these is an exanunition of'the revenue requirements for Hutchinson's Electric and Gas Divisions. To remain financially sound, Ilutchinson's Electric and Gas Divisions must produCC sufficient revenues through retail rates to coyer revenue requirements. 'file second component of the rate study is the cost -of -service analysis. The electric and gas cost-of=service analyses are perlormed to determine the allocated cost of providing service to each class ofcustomers. The third study aspect is an unbundled rate analysis for each customer class. 'these rates are a direct result of the cost -of -service analysis fir each Division. The fourth and final component of the rate study is the design of new rates. The new rates have been desioned, laking into account the results of the revenue requirements, cost -of -service analyses and unbundled analyses. Section 5 of the report presents our recommendations and the proposed rates developed as a result of our analyses. It also presents graphs comparing the monthly bills of each customer class at current and proposed rates. At this time, there are fey specific rate design recommendations. however, we have also included general rate recommendations for Hutchinson's consideration as tilture rate changes are considered. Thank you for the opportunity to have prepared this study fur Hutchinson Utilities. We would like to express our appreciation for the valuable assistance provided by Hutchinson personnel during the performance of this study. Sincerely. SAIC Energy, Environment & Infrastructure, LLC i David A. Berg, P_)E. Senior Project Manager 31531ulnlu-(]IM I Ilulchills, n Cover' I cite' At cx SAIC Energy, Environment & Infrastructure, LLC 1380 Corporate Center Curve, Suite 305 St. Paul, MN 55121 rel. -651.994.8415 fax: 651.994.8396 saic.com/EEandi Section 1 INTRODUCTION The City of Hutchinson. Minnesota throuph I lutchinson Iitilitics (HU). owns, operates and maintains it municipal utility Which retail gas and electric service to its residents and businesses. HL; provides electric service to approximately 7,000 retail customers thruu`1111 its Electric Division. HUC provides natural gas service to approximately 5.400 customers through its Gas Division. Overall responsibility lilr the operations ol'the Electric and Cas Divisions is charged to the Hutchinson utilities Commission which ha, the authority to and set the rates 1()1- service charoed by I1U. SAIL has performed it cost-ol-service and rate design study for HU's Electric and (gas Divisions. The study included an analysis ofestinlatcd revenue requirements liar 2012 - 2016 (the "Study Period"). the preparation ofdetailed cost -of -service analyses based on a 2010 test year. it rate analysis and the development of proposed neW electric and fps rates lilr cath customer classification. This report summarizes the analyses undertaken in our study of HU's retail electric and gas rates and describes the results of our stud• and our recrnnmcndations. The cost-ol-servicc analysis perlormed liar each of Ilt)-•s retail electric and gas CUS10111Cr classifications was based on filly embedded costs. The rate dcsiu.;n portion of the study includes recommendations on retail rates 1i-ir each customer classification. SAIL Section 2 ESTIMATED OPERATING RESULTS — EXISTING RATES To remain financially sound, HU's electric and gas rates must produce sufficient reyenucS to coyer the cost of providing electric and natural gas service and to permit the continued replacement and expansion of its facilities. These expenditures are commonly relerred to as "revenue requirements" and consist of normal operating expenses, capital improvements and additions. contributions to the City and non- operating expenses. Periodically, a utility must examine its current and forecasted revenues and expenses to eerily that the total revenue, including interest earnings and miscellaneous income is Sufficient to coyer all revenue requirements. This part of the study compares projected income: carried from revenues at present rates to the expenses expected to be incurred in serving custiuners during the Study Period. In order to determine the adequacy of HU's existing electric and gas rates. Nye have worked with the HU personnel to develop estimates of the annual revenues and revenue requirements for the Study Period. These estimates serve as the basis for determining the overall level of revenue recovery and provide a inundation for our cost -of -service analyses. The analyses and asSllmp11011S incorporated in our development of estimated reyenucS and revenue requirements are described below. Electric Division Historical Electric Requirements I IU purchases the majority of its electric requirements anis generates the remainder of its requirements. HU signed an agreement with Missouri River Energy Services (MRES) to begin receiving capacity and energy in 2010. Its contract calls for 15 MW of capacity and energy in 2011 and 2012, with an increase to 25 MSV of capacity and energy in 2013. HU's contract with Northern States Power'lcel Energy for purchased power ends on December 31, 2012. HU \ •ill continue to generate a portion of its requirements and purchase frons the open market any amounts needed beyond MRES purchases and generation. Hl►'s historical electric requirements lm 2007 through 2011 are shown in the table below. R I x4,; SAIC Section 2 Table 2-1 Historical Electric Requirements (MWh) Year Requirements Losses Sales (excluding Resale) 2007 328.860 13.086 315.774 2008 319,643 9.223 310,420 2009 289.175 15.519 273.656 2010 306,063 12,461 293,602 2011 311.359 12.564 298.795 Estimated Electric Requirements HU's li recasted electric sales, losses and requirements liar the Studv Period are shown in the table below. 'I'hese requirements were lorecasted by HU and reflect sales to I-I1.1's retail CustomCrs. as Well as electricity supplied for street and trallic lights. HU internal use and system losses. In addition to providing electric service to its retail custonurs. HU sells to resale customers. 1-I1_;'s contract with Southern Minnesota NiLinicipal Power Aj,,.encv (SMMPA) tier resale capacity sales ends in 2012. HU's contract to sell capacity to MRES heL_ins in .lune 2013. The MRES contract is for capacity sales of 25 ,MW per nwnth at S2.55 per NqW,-nwnth. ill► also provides energy sales to resale Customers. depending on market prices. However. the ntar�gm on energy sales for resale is low, so no resale energy sales were assumed in the fiorecast. Table 2-2 Estimated Electric Requirements (MWh) Year Retail Sales Losses Total Requirements Annual Percent Change 2012 303.989 12.666 316.655 2013 324.899 13,537 338.436 6.9% 2014 328,927 13.705 342.632 1.2% 2015 350.474 14,603 365,077 6.6% 2016 354.714 14.780 369.493 1.2% 'I'lhc "Estimated electric Purchases and (veneration" table below reflects the new purchased power arrangement Hli began in 2010 with I\1RES. HU's purchase: of' 15 NIM' of capacity and cnern, from MRES in 2011 and 2012 is equivalent to 131.4(1(1 Nl\'4'h per year. The 25 N1W capacity purchase in 2013 is equivalent to 219.11U1) I\• WII. It is assumed that I -IU will generate 24 percent of its remaining requirements, alter the i\1IZE:S purchase. The remaining 76 percent of its remaining requirements will be market purchases through MISO. -'_ SAIC' Fnergv. Fnviremment S InfirasU•uchu-c. I.I.0 „i,4; ESTIMATED OPERATING RESULTS — EXISTING RATES Estimated Revenue Requirements A forecast of HU's Electric Division expenses, Called rCyenue requirements. has been prepared For the Study Period. These revenue requirements consist of generated and purchased power costs and operating and non-operating expenses. Estimated reyCnuc, Irons the sale of elect rlClty at Current rates durin-g the Study Period have been forecasted and compared to the rcyCnue requirements. The estimates of the Study Period revenues and reyenuC requirements are contained as Exhibit 2-A at the end of this report. Estimated 1'e%'CIILle requirements for the Study Period were developed based on HU's annual financial reports for 2007 throu(Ih 2011. budgeted expenses for 2012 and forecasts of expenses for 2013-2016. as NyCll a, IisCussion, with HU personnel. 'rhe assumptions used in these estimates are explained in detail below. Generation and Purchased Power Expenses SAIC used the rates frons HU's contract with NIRES to develop the cost for N4RL•S capacity anis energy purchases through the Study Period. The cost for Nyind purchases Was escalated by I percent per year. The price for market purchases through MISO %\-as escalated frons 2012 levels by 3 percent per year. Transmission fees are i recasted to increase by $100.000 per year during the Study Period. The cost of natural gaff fir electric generation was based oil the cost ofniarket gas as forecasted on the NYME\ futures market website. The cost to transport the natural gas is estimated at S 1.1 million per year. The table below shows the estimated expense for the prjected generation and power Purchases shown in the table earlier in this Section. Local production and transmission expenses are not included in this table. Exhibit 2-A at the end of this report shoe's total expenses forecasted for the Study Period. VIN,45 SAIC Energy. Fnvironnient & InFrasiniCtUre. LLC 2-3 Table 2-3 Estimated Electric Purchases and Generation (MWh) Year MIRES/ NSP Wind Market (MISO) Generation Total Purchases Purchases 2012 262.800 240 40,930 12,685 316,655 2013 219.000 240 90.772 28.425 338.436 2014 219.000 240 93,961 29.432 342,632 2015 219.000 240 111.018 34.818 365.077 2016 219,000 240 114.375 35.878 333.375 Estimated Revenue Requirements A forecast of HU's Electric Division expenses, Called rCyenue requirements. has been prepared For the Study Period. These revenue requirements consist of generated and purchased power costs and operating and non-operating expenses. Estimated reyCnuc, Irons the sale of elect rlClty at Current rates durin-g the Study Period have been forecasted and compared to the rcyCnue requirements. The estimates of the Study Period revenues and reyenuC requirements are contained as Exhibit 2-A at the end of this report. Estimated 1'e%'CIILle requirements for the Study Period were developed based on HU's annual financial reports for 2007 throu(Ih 2011. budgeted expenses for 2012 and forecasts of expenses for 2013-2016. as NyCll a, IisCussion, with HU personnel. 'rhe assumptions used in these estimates are explained in detail below. Generation and Purchased Power Expenses SAIC used the rates frons HU's contract with NIRES to develop the cost for N4RL•S capacity anis energy purchases through the Study Period. The cost for Nyind purchases Was escalated by I percent per year. The price for market purchases through MISO %\-as escalated frons 2012 levels by 3 percent per year. Transmission fees are i recasted to increase by $100.000 per year during the Study Period. The cost of natural gaff fir electric generation was based oil the cost ofniarket gas as forecasted on the NYME\ futures market website. The cost to transport the natural gas is estimated at S 1.1 million per year. The table below shows the estimated expense for the prjected generation and power Purchases shown in the table earlier in this Section. Local production and transmission expenses are not included in this table. Exhibit 2-A at the end of this report shoe's total expenses forecasted for the Study Period. VIN,45 SAIC Energy. Fnvironnient & InFrasiniCtUre. LLC 2-3 Section 2 Table 2-4 Estimated Electric Generation and Purchased Power Expenses Operating and Maintenance Expenses Operatino and maintenance expenses incurred are related to Production and Distribution facilities and services. Customer Service and Collection. Sales. Administrative and General and Depreciation are also hart of operating and maintenance expenses. Expenses for 3012 have been based on IIL)''s 2012 budget and diSCLl',Slon With III; staff•. For the years 21)13-2(110, local transmission, distribution and customer related expense; were escalated Irons ?012 levels by 3 percent per year. Most administrative and general expenses were escalated by 9 percent, clue to their historically higher rates of increase each year. Forecasted depreciation Is based on esistin, depreciation levels plus an assumed '10 year depreciation sclhcdule on planned capital improvements. Other Income and Expenses The Amortization ol' Development Study is related it) planning expenses from the Billy Stone li power project. Payment; are expected to he completed 1112015. Revenues from non-utility operations include Other Income. Interest Income and Nl[Seel laneous Income. Levels for Other Income and MisccllaneouS Income durin�'T the Study Period are hased on the 2012 buLlget. Interest Income is based on 0.25 percent interest on cash reserve levels and is expected to decrease considerably. clue to use ol'cash reserves to liuul planned capital improvements. Other Expenses include Miscellaneous Iapcnse and Interest Expense. Nliscellancous Expense during the Study Period is based on the 2012 budget. Interest Expense is the interest portion of the Electric Dix ision's debt service payments. the interest portion on HU's debt service payments for the gas pipeline. Payment In Lieu Of Taxes/Services-In-Kind Payment In Lieu OI' Taxcs (PII.o,r) and services -in-kind are provided to the City of Hutchinson by the Electric Division In two forms. The Electric Division provides a PILOT cash transfer based on 2.75 percent of the Division's total operatirt�1 revenues. as determined by the second preceding year's financial audit. The Electric Division also reimburses the City of I lutchlnson for charges related to the Division's provision ?--t SAIL Energy. l:mvironmenl & III IrLISIRICIure. LLC f+il".1; Market Transmission Natural Gas and Total Year MRESI NSP Wind Purchases and Other Fees Transportation (MISO) 2012 $12,643.3344 510.008 51,547.141 S890.699 51.632..776 $16.723.969 2013 10,240.500 10.108 3.534.106 1.008.389 2.189.379 16.982.481 2014 10.240.500 10,209 3,768.011 1.116.647 2.397.941 17.533.308 2015 10.486.272 10.311 a 585 615 1.236.272 2781.728 19100.198 2016 10 579.169 10 4' 4 4.865.99 1.345.655 3,209.650 20.010.883 Operating and Maintenance Expenses Operatino and maintenance expenses incurred are related to Production and Distribution facilities and services. Customer Service and Collection. Sales. Administrative and General and Depreciation are also hart of operating and maintenance expenses. Expenses for 3012 have been based on IIL)''s 2012 budget and diSCLl',Slon With III; staff•. For the years 21)13-2(110, local transmission, distribution and customer related expense; were escalated Irons ?012 levels by 3 percent per year. Most administrative and general expenses were escalated by 9 percent, clue to their historically higher rates of increase each year. Forecasted depreciation Is based on esistin, depreciation levels plus an assumed '10 year depreciation sclhcdule on planned capital improvements. Other Income and Expenses The Amortization ol' Development Study is related it) planning expenses from the Billy Stone li power project. Payment; are expected to he completed 1112015. Revenues from non-utility operations include Other Income. Interest Income and Nl[Seel laneous Income. Levels for Other Income and MisccllaneouS Income durin�'T the Study Period are hased on the 2012 buLlget. Interest Income is based on 0.25 percent interest on cash reserve levels and is expected to decrease considerably. clue to use ol'cash reserves to liuul planned capital improvements. Other Expenses include Miscellaneous Iapcnse and Interest Expense. Nliscellancous Expense during the Study Period is based on the 2012 budget. Interest Expense is the interest portion of the Electric Dix ision's debt service payments. the interest portion on HU's debt service payments for the gas pipeline. Payment In Lieu Of Taxes/Services-In-Kind Payment In Lieu OI' Taxcs (PII.o,r) and services -in-kind are provided to the City of Hutchinson by the Electric Division In two forms. The Electric Division provides a PILOT cash transfer based on 2.75 percent of the Division's total operatirt�1 revenues. as determined by the second preceding year's financial audit. The Electric Division also reimburses the City of I lutchlnson for charges related to the Division's provision ?--t SAIL Energy. l:mvironmenl & III IrLISIRICIure. LLC f+il".1; ESTIMATED OPERATING RESULTS — EXISTING RATES r►f street lighting, electricity and maintenance service. In 2012 the total anulunt of these two forms ol'transli r payments are estimated at S885.646. Capital Improvements 'Flic capital impi-m-cments included in the Cash Reser%es portion of the forecasted operating, results are based on 1-111's Capital Improvemems Plan. plus discussion With 1 lu staff. Final determination has not been made on the liuulins' sources for capital I11111rovelllellIS. Debt Service '171c C'ash Rcsen•es portion of the 101-ccasted operatin"' results includes the principal portion of the debt ,er\-Icc paynlcrlts made by the Flectric Division. Debt service principal paylllellts oil cLirre It debt are appmNinlatelvS 125.000 per year. Revenue Requirements Each cate`,ory included in the calculation of reVC11LI ; requircnlcrlts has been described above. 1'he revenue reLluirements indicate the anunnit of funds on an annual basis necessary to operate the system. Estimated Revenues - Existing Rates Estimated operating, revenues have been de\ eloped by SAIC lice the Study Period to compare to forecasted revenue requirements clurim-, the same period. Operating, revenues consisl of revenues From the sale of retail electricity. sale of electricity lily resale. and other operating, revenues, including, nct income li'0n1 other sources. re\-cnues from security lights and pole rental lees. W,;, SAIC Ener"v. Eriimnn;en; & Infira;tructure. LLC 2-5 Table 2.5 Estimated Electric Operating Revenues Existing Rates Year — -- 2012 -- 2013 2014 2015 2016 Retail Sales -- --. ..-- -- -- -- ---- —.— Revenues $26.591,070 S28.V9.562 S28.727.590 S30,570.476 S30,936.722 Resale Revenues 600.000 446.750 765.000 765.000 765.000 Other Operating Revenues 238.000 238.000 238.000 238.000 238,000 Total Operating Revenues S27.429.070 529.063.812 529.730.590 $31.573.476 531.939.722 W,;, SAIC Ener"v. Eriimnn;en; & Infira;tructure. LLC 2-5 Section 2 Estimated Electric Operating Results and Cash Reserves Based o11 the estimates described above, we have prepared the folloxvin-, tables which SUllllllal'17.0 the Electric 131%-isio11's cstinlrtted annual operating, results and cash reserves liar the SUKIN: Period. As shown below, net income based oil the Elcetric Mvisloil s existi110 rates will be sul'ClCient to cover basic annual operating expenses, but cash reserves will 1101 be sullicie11t 10 CON'Cr Capital hiipr(wenle11ts durill" the Stud)- Period. Howevcr. the ending cash reser%e balance does relllain positive by the end ol'the study period CVCn though it dcereases from approximately S12.3 trillion to S2.5 11111110/1 dorm" the period. Our estimate ol' the I lectric I)i\.isi0n's annual operating results is presented in detail in 1-ahibit ?-:-\ at the end Ol'this report. Table 2.6 Estimated Electric Division Operating Results Existing Rates Year 2012 2013 2014 2015 2016 Estimated Operating 527.429.070 529.063.812 S29.730.59C $31.573.476 S31.939.722 Revenues Estirna;ed Revenue 26,474.747 Req:lire—encs Net Income S951.323 Net Income as Percent of Operating 3.50% Revenues 27,291.939 28.248.113 29.647.493 51,771.872 S1.482.477 $1.925.983 30.672.660 S1.267.062 6.1% 5.0% 6.1% 4.0% Table 2.7 Estimated Electric Division Cash Reserves Existing Rates Year 2012 2013 2014 2015 2016 Beginn'ng o` Year $12.340.501 $6.741.174 $7.177.001 S3.757.434 $7.351.738 Cash Reserves Plus Net Income 954.323 1.771.87 2. 1.482.477 1.925,983 1.267.062 Plus Depreciation 2.400.000 2.693.955 2.823.955 3.077.322 3.120.122 Less Capital (8,818.650) (3.900.000) (7.601,000) (1.284.000) (9.073.000) Improvements Less Bond Principa' 1135.000) 130.00 ('25.000;12( 5.000) 125 000 End of Year Cash $6.741.174 S7.177,001 $3.757.434 S7.351.738 $2.540.922 Reserves -6 SAIC E.uere�. i-mMromment & lnirasu•ucture. I I.C' B? ^+; ESTIMATED OPERATING RESULTS — EXISTING RATES Gas Division Estimated Gas Requirements HU Provides gas for its retail customers and also purchases and transports gas for its transportation customers. HU has 10recasted gas purchases for the Study Period. as shown in the table below. The purchases reflect sales to HU's retail customers and transportation customers and unaccounted liar gas of I percent. Table 2-8 Estimated Gas Requirements (MCF) Year Purchases for Retail Customers Purchases for Transport Customers Total 2012 999,882 848.546 1,848.429 2013 955.169 797.900 1.753.069 2014 969.885 797,900 1.767.785 2015 984.601 797.900 1,782.501 2016 999.317 797.900 1.797.217 Estimated Revenue Requirements A liirecast of IIII's Gas Division expenses, called rcVcnue requirements, has been prepared tur the Study Period. `These revenue requirements Consist of purchased ;gas costs and operating and non-operating expenses. Estimated NX-CrIucs from the sale of -as at current rates during the Study Period have been forecasted and compared to the revenue requirements. The estnnates of the Study Period revenues and revenue requirements are contained as Exhibit 2-13 at the end of this report. Estimated revenue requirements for the Study Period were developed based on HU's annual financial reports fir 2007 through 2011. budgeted expenses for 2012, forecasts of expenses liar 2013-2016, estimated wholesale gas costs, and discussions Nvith HU personnel. "fhe assumptions used in these estimates are explained in detail below. Purchased Gas Expenses Projected commodity and reservation expenses for 2012-2016 are based on forecasted gas comntodlty costs and reservation lees as developed through discussions%%it HU staff. Reservation fees are estimated to remain level at approximately S 10,000 per year. IiU has a signilicant portion of its gas commodity purchases for2012 and 3013 locked in at a fixed rate. The commodity rates shown below reflect a weighted avcrage ul'the locked -in gas purchases and gas purchases on the market at forecasted market prices. as listed on the NYN EX futures market website. The weighted average B1s1; SMC Energy. Environment & lnfrastrurture. 1.1-C 2-7 Section 2 eonunodit"• rags apply only to HU's retail custoniers. HU's transportation customers pay market rates li,r their gas purchases. Table 2-9 Estimated Wholesale Gas Commodity Rates (Weighted Locked -In and Market) for Retail Customers Per MCF Year Commodity Rate - - — -- 201.2 - - -- — -— 55.58 2013 4.68 2014 4.54 2015 4.60 2016 5.50 "1 -he table below Shows the estimated wholesale gas commodity expense !br the I'I-t'.leCted kurChaSea shoWn in the table earlier in this Secllon. 'flus table reflects the total Vitas expenses li ESTIMATED OPERATING RESULTS — EXISTING RATES Payment In Lieu Of Taxes Payment In lieu Of Taxes (PILO-]') is provided to the Cite of Hutchinson by the Gas Division. The Gas Division provides a PILOT cash transfer based on 2.75 percent of the Division's total operating revenues, as determined by the second preceding, year's financial audit. In 2012 the PILOT cash transfer is estimated at S394,000. Other Income and Expenses Revenues iron non-utility operations are classified as Other Income -Net. Interest Income and N iscellaneous Income. Other Income -Net and Miscellaneous Income levels for the Study Period have been based on the Gas Division's 2012 budget. Interest Income is based on interest earned tronl cash reserves at 0.25 percent interest rate. Other Expenses include the expense portion on the gas pipeline debt service payments and Miscellaneous Expense, which has been based on the 2012 budget. Capital Improvements Planned improvements tier the Gas I)iyision during the Study Period range between $430,000 and $1.5 million per year. Capital improvements will be paid fi•on1 cash reserves. Debt Service I-Il1 has gas revenue bonds issued to pay for the -as pipeline. Interest payments liar the bonds have been included in the torecasted operating results shOW11 in detail in Exhibit 2-B. Principal payments have been included in the calculation of cash reserves. Principal payments range between $1 IllllllOtl and S11.2 million per year. Revenue Requirements Each category included in the calculation of revenue requirements has been described above. The revenue requirements indicate the amount of Funds on an annual basis necessary to operate the system. Estimated Revenues - Existing Rates Estimated operating revenues have been developed by SAIL for the Study Period to compare to forecasted revenue requirements during the same period. The revenues are based oil rates in effect in 2012. Operatin, revenues consist of revenues front the sale of retail gas, transportation revenues from gas sales to 3M and HTI and transportation fees from New Ulm and the Electric Division 1101- use Of the gas Pipeline. 1111,45 SMC Encru*. Fnvironment & Infi-astructure. LLC 2-9 Section 2 Estimated Gas Operating Results and Cash Reserves Based on the estimates described above, «-e have prepared the folloNvIii, tables which summarize the Gas DIN-ision's estimated annual operating results and cash reserx-es liar the Study Period. As sho\vii bolo\%-, net income based on the Gas M-1sion's existin, rates \%ill be sutticient to coyer operating expenses and capital impro\,enieMs Burin, the Study Period. In tact, estimated cash reser%'es increases from approximately $l.2 million to S7.5 million during the study period. Our estimate of the Gas Dix-ision's annual operatin'T results is presented in detail in Exhibit ?-B at the end ol'this report Year Estimated Revenues Estimated Revenue Requirements Net Income Net Income as Percent of Operating Revenues Table 2-12 Estimated Gas Division Operating Results Existing Rates 2012 2013 2014 2015 2016 S14.665,954 Table 2.11 Estimated Gas Operating Revenues Existing Rates S14.620.662 S15.071,477 Year 2012 2013 2014 2015 2016 Retail Sales $9.571.619 $9.172.258 S9.307.061 $9.441.875 59,576.701 Sales to 3M & HTI 3.294,335 3.079,101 3.513.601 3,829.601 4,619.601 New Ulm & Electric Division Transportation 1,800.000 1.800.000 1.800.000 1.800,000 1.800.000 Total Operating Revenues S14.665.954 $14,051.360 S14.620.662 $15,071.477 S15,996.302 Estimated Gas Operating Results and Cash Reserves Based on the estimates described above, «-e have prepared the folloNvIii, tables which summarize the Gas DIN-ision's estimated annual operating results and cash reserx-es liar the Study Period. As sho\vii bolo\%-, net income based on the Gas M-1sion's existin, rates \%ill be sutticient to coyer operating expenses and capital impro\,enieMs Burin, the Study Period. In tact, estimated cash reser%'es increases from approximately $l.2 million to S7.5 million during the study period. Our estimate of the Gas Dix-ision's annual operatin'T results is presented in detail in Exhibit ?-B at the end ol'this report Year Estimated Revenues Estimated Revenue Requirements Net Income Net Income as Percent of Operating Revenues Table 2-12 Estimated Gas Division Operating Results Existing Rates 2012 2013 2014 2015 2016 S14.665,954 S14.051.360 S14.620.662 S15.071,477 S15.996.302 12.974.313 11.677.790 12.115.377 12.572.212 14.477.217 S1.691.640 S2.373.570 S2.505.285 S2,499,265 S1,519,085 11.5% 16.9% 17.1% 16.6% 9.5% '-10 SAICL•nerey. hivironment & Inll'aStruCture. LLC iei.aG Combined Electric and Gas Results Presented below are the estimated operating" results and cash reselwes for tile combined electric acid ,as dix-isi(ros at existing rates ti)r bath ck—isioris. Table 2-14 Estimated Combined Electric and Gas Operating Results Existing Rates Year 2012 2013 2014 2015 2016 Estimated Revenues S42.095.023 ESTIMATED OPERATING RESULTS — EXISTING RATES $44.351,253 S46.644.952 Table 2-13 Estimated Revenue 39.449.060 38.969.729 Estimated Gas Division Cash Reserves 42.219.705 45.149.877 Requirements Existing Rates Year 2012 2013 2014 2015 2016 Beginning of Year $1,163.169 $1.326.760 S2.499,231 $4.524.342 S6,540.826 Cash Reserves of Operating 6.3% Plus Net Income 1.691.640 2,373.570 2.505.285 2,499.265 1.519,085 Plus Depreciation 1.050.000 1,101.102 1.141.175 1.156.720 1.171.037 Less Capital (1,533,050) (1.202.200) (466.350) (429.500) (429,500) Improvements Less Bond Principal1.0( 45.000)1.10( 0,000)1.1( 55.000)1.21( 0,000)1.27E 5.000) End of Year Cash $1,326.760 $2.499.231 S4,524,342 $6.540.826 $7,526.448 Reserves Combined Electric and Gas Results Presented below are the estimated operating" results and cash reselwes for tile combined electric acid ,as dix-isi(ros at existing rates ti)r bath ck—isioris. Table 2-14 Estimated Combined Electric and Gas Operating Results Existing Rates Year 2012 2013 2014 2015 2016 Estimated Revenues S42.095.023 S43.115.171 $44.351,253 S46.644.952 S47,936.024 Estimated Revenue 39.449.060 38.969.729 40.363.490 42.219.705 45.149.877 Requirements Net Income S2,645,963 S4,145.442 S3.987.763 $4,425.247 S2.786,147 Net Income as Percent of Operating 6.3% 9.6% 9.0% 9.5% 5.8% Revenues 111,4; SAIC Energy. Environment S Infrastructure. LLC 2-11 Section 2 2-I2' S:11C' I:ncrg�. Emir��nmrn� S Int�a;(ru�turr. I.LC 111«45 Table 2.15 Estimated Combined Electric and Gas Cash Reserves Existing Rates Year 2012 2013 2014 2015 2016 Beginning of Year 513.503.671 S8.067.934 S9.676.233 $8.281,776 S13,892.565 Cash Reserves Plus Net Income 2.645.963 4.145,442 3.987,763 4,425.247 2.786.147 Plus Depreciation 3.450.000 3.795,057 3.965.130 4,234.042 4.291,158 Less Capital (10.351.700) (5.102.200) (8.067.350) (1.713.500) (9.502.500) Improvements Less Bond Principal1.1( 80.000)1.2( 30.000)1.2( 80.000)1.3( 35.000)1.4( 00.000) End of Year Cash S8.067.934 $9.676,233 S8.281.776 513.892.565 S10.067,370 Reserves 2-I2' S:11C' I:ncrg�. Emir��nmrn� S Int�a;(ru�turr. I.LC 111«45 Hutchison lJtilut(!,, Mmne,ota Electric Division Operating Results r•istin;, Raty% Historical 2007 2008 200') 2010 2011 Operating Revenues Sales - rlectnc Energy Exhibit 2 -A Forera,t 7012 201; 201.1 ?015 7016 Residential 5,235.701 5,234.100 4.871.694 5,107,357 5.255,332 4,795.115 5,093,726 5.152,383 5,10,041 5.521,723 General SOVIC0 9,152,162 9.553.026 8.660.?81 8.970.977 x.075.510 8.610,136 9.199.665 4.313,231 9,920.693 10.0.10,235 Industrial 13,327,227 13.286,228 30,650.856 11.571,718 11,1;92.880 13,052.819 13940,310 1.1.113.141) 15.(13/.`I3/ 15.219,916 Strect Lighting; 128,933 1.11.58.1 154.259 15/,253 153.378 1.13,0011 145.860 148.777 151.757 15.1.788 Sales for Resale 2,085.512 2,293.769 935,577 986.386 1.7;5,255 600.000 •1.16.250 765.000 765.000 765.000 Total Energy Sales 29.923951 30,508,707 25,242,887 26,703,668 27,501,635 ?7,171.070 28,11:25,812 29,592,590 31.335,576 31,7U1.777 Other Operating Revenues Not Income From Other SourC.r's 254.645 255.359 282.915 290.572 295.586 270,000 220.000 220.000 220.000 770.000 SecurityLigl,ts 11,350 11.039 10.817 10,727 10.585 15,000 1r0nn 15,onn ls.nnn 15,000 Pole Rental 2.532 1.045 636 353 264 3,000 3.000 3.On0 3,000 3,000 Total Other Operating Revenues 268,130 270,441 295.513 301.652 306.4335 :38,()()(1 238.000 233.000 235.000 233.000 Total OperatiripRow-mrt, 30.147,3/1 30,679.150 25.557,305 27OU5,320 27,7113,120 2/:129.070 .'9,063,817 79,7;(1,5'::+0 .1,573.416 31939,/22 Operating; Expense, Production Operation Operation Supervision & Eng;rrleerinq 862:49.1 390,075 918.320 970,163 951.953 1113.100 966,243 995,230 1,025.037 1,055,850 Find & Transport Cost 3.222953 2.860.821 1.505.036 1.713.152 1.726.080 1.(13.'.776 2,189,379 2,397,951 2,731.728 3.209,650 Operatinq supplies & fxpenscs 85.305 75.511 79,193 51,3.19 79,822 105.650 108,820 112 .nR4 115,557 115.410 Total Production Operation 4,169,751 3.825.506 2,502,559 2,169.669 2,757,355 ?.675.521:, 3,265,551 3,505,256 3.922.261 5.35.1,500 Produrtron Marntunance 39.1.009 505.301 155.761 351.213 325,63.1 257.000 247,670 306.600 315.793 325.27? Other Power Supply I-xpen,c• Purchased Power 17.259.267 13.559,750 15.587,700 11,5.10.10.1 15:1-10922 15.091,192 15.793.102 15.135.367 16.318.571 16,801,233 System Control A Load Dispatch 337,373 275.498 275.968 259.309 327,269 315,000 324,450 334.155 355,209 354.535 Engineering Services ;.250 0 28,295 45.5.15 6,76.1 10.000 10.300 10.609 1n,927 11.755 Total OthUrPowr:rSupply Expense 17,599.590 15:835.1.13 15.371.9613 15.9/5,25:? 15,115.955 15.416,192 15.127.852 15.530.159 16,6/3.60/ 17,167,023 Transmission Expen%e Transmission Operation 2,270 11.1,81.1 120.8.18 132.051 129.826 151.000 145.230 147.587 155.075 158,697 Transmission Maintenance 4.610 17,558 12,072 25.153 17.598 45,1100 70,040 72,151 77,305 76,535 TotalTrammc,sron 6,880 132,372 1379:0 157.205 142,325 209.000 215.270 ?:1.723 _2;:.;30 235,231 Distribution Expense Di,tributron Operation 357.597 391,58(1 527,517 435,647 5223.083 49.1,000 508,820 525.085 539,807 556.001 Distribution Maintrnanr.r! 250.319 339.290 239.535 235.716 229,774 238.500 2.15.655 253,025 260,615 268.535 Total Distribution 588.51E 730,8/0 661,051 673,363 757.,362 732,5011 755.4''/5 777.109 800.523 8?5.435 P:\004712 Hutchinson\3153101010 Rate Study\Data Analysis\Flutchrnson rlectrrc Operating; Results and COS.xl,x\Ex 2-A Oper Results Exist Rates 1 P \004712 Hutchinson\3153101010 Rate Study\Data An.lysis\HUtrhin-,on Elortric Operating Rosult, and COSA,x\Ex 2 A Oper Results Exist Ratu, 2 Exhibit 2-A I lutchinson Utdules. Minnesota I.h•rtwic Divi -,ion Operating Rvuln Existing Rates Historical Iorrcn,t :007 ;008 2l1(1" e01u 2011 2012 ?013 ?013 21115 2016 Cu,tomcr Sarvlrc & Collartrnn Alelei Reading 58,800 6D n32 91)n32 100.516 93,822 30,250 31.154 32.092 33,055 33.047 Colle:rtinn Expense 99.717 107,238 76.527 ]08.9•]9 10?,472 115,115 119.3162 122.932 126,631 130:130 Rad Debts 17,3.16 18.143 16391 13.E-31 13.056 11.000 11,110 11,221 11.333 11.437 Customer Service •13.363 5.1.103 31.515 35.557 42.3138 43.350 1.1,%5.1 •16.091; 17.371) 35.903 Total CLI-,tomer Servrre• & Collection 219,226 239,526 231.365 269,203 ; 53.198 200,585 206.383 212.352 215.498 1?4.8?6 Sales Expert,a Supervision 10.611.1 5.250 6,166 3.671 3.2.83 6.2.10 6:1?7 6,,620 6.817 /.023 Misc. Sellink Expense 236.352 .'71.523 ?31,060 ?38,?67 167,491 199.425 205.308 211.570 217,017 ??•1,355 Total tial,••, Exllmw -IS7,%51 ?%li,//� ?39.9?6 ?4?.9 38, 17n,7(;•l ?05.665 211.535 218.170 223./316 231.475 Administrative & General Admini,trarm, & Gune:ral Lahor 328.317 351,211 381,607 390,3322 517,730 47.1,750 51!.7'11 553.735 598,048 635,392 Office Supplies & Expense; 159,580 156.396 199.398 232.385 235,372 2636.971 253,329 311.395 336.307 363.211 OutsiduServire-s 79,356 69.622 92,236 105.136 111.0:? 135.000 143,1100 152,135 159.752 167.730 Property Insurance 121.814 101.339 107,535 111.205 11/,323 117.150 120,665 12•1,29.1 128n1i 131,853 rnlployee Pension & BenJits 757,4n1) 953,557 924,276 1.170.323 1.236.253 1.185.75C 1.280,610 1.383.059 1,393.70.1 1.611.200 ItelulitoryExpense 23:173 16.36.1 26469 ?1,301 ?3.019 27.511.0 29.760 32.0/6 33.642 37,313 Misc. General rxpen,e 151,71f; 137.00 109.163 118.28.3 124,893 111,100 119,928 129.587 131.1.05.1 151.150 Maint of General Plant 35.118 43.510 45.557 56.036 59.168 47.63n 51 .440 55.5516 630.000 63.800 Total Administrative&General I,a59,UOS 1.7.17,159 I.S.S9,314 :.301,.0:0 2:1:3.8711 [.3168,551 2.538,362 2.73 1,550 2,950,320 3.175.230 De•prrciatu,n 1032.5.12 2,09•1.038 2.231,172 2.257,016 2.25.1,770 2.300.000 2.693,955 ?.82 3.955 3.077.322 3.120.122 Amorh:atinn of Dov,•Inpment Study 1.299,1!6 725,078 1.035.291 1.035.289 1.035.797 ?58.823 0 P.winuntinLieUefT.1•.. .?1.71.1 7 .1?. 2.1.1..157 9n5..ln7 7.1n•7;,l 742.1.3i" i;l.'1'. .!.3.299 :90.2., 8 17.59 1 Contribution to Cily-Roarhvay Lighter: 128,292 140,111 133.501 146.859 133.000 133,000 1.15.860 1.18.777 151.75.' 15.1.781+ Total Operatingrxpen,e ?7.677.279 ?9,19.1,675 ?5,L30,386 26.351.;2(, 26506.091 2,0171,257 2/,263,365 28,225.568 29.621,273 30.660,327 Operating Income ..52.0.09? 1,48•1.•175 4266.8111 652.993 1,7.02.021) 1.009.813 1.800,337 1.505.022 1,952,202 1.279,295 OthurInromc/(Expcn%o) Other Income -Net 3.1.308 •15.595 17,738 22•781 15.010 10,00) 10.000 10,000 10.000 10.000 Int:rest Income 1311.07-) 68.316 36,312 30,660 2/.86,% 20.000 16,353 179.13 9.39.1 18.377 Miscellaneous Income 767.065 779.679 170,388 588.081 28.6.'7 2n.000 20.000 20.000 20.000 20.000 Alisrcllnnvou., Exponse: (90,361) (125.SS5) 159,206) (31,0391 (29,715) (30.000) (30.000) (30.000) (30,000) (::0.0(10) Inte:re,l Expe:nse (7,133) (1,850) (1.350) (193.317) (202,3591 (50.390) (•15.•1:8) (•10:188) (35.613) (30.6,131 Gain (Loss) on Disposal 9,799 17,798 (190.6131 157,997 (25n00) 0 0 0 0 Total Other Income/(Expense) 852.937 775.734 730,650 216,453 (2.603) (55,390) (28.575) (72.5.15) (26•219) (12,133) Nutlneomm 3,373,039 2.260,309 1,207,399 569.347 1.199.426 95.1,3]3 1.771.872 1,482.477 1:125:)83 1,267,062 Not Income as '••, of Operating Revenue. l V.. T.- S".. 3", 40. .151. 6.1"- 5.0".• 6.1".. •].0"• Revenue Requirements 26.323.332 28.418,731 23.339.306 26,135,873 26.508,69.1 26;17•1,7.17 27,2111,1139 28.241.113 29,637.493 30,672,66C Cash Reserves Beginning of Year Cash Reserves $17.340,501 56.741.173 57,177,001 $3,757,433 57.351,733 Phis Not Income 954.323 1,771,872 1.482,477 1,925.933 1.267,n62 Plus Depreciation 7.300.000 2.693.955 2.823.955 3.077,322 3.120.122 Lo,s Capital Improvements (5.818.650) (3,900,000) (7,601,000) (1.28•1,000) (9.073 000) less Bond Principal (135,1)Un) (130,000) (125.000) (125.000) 1125.000) End of Year Cash Rese7rvc:, $12.340,501 $6.741,174 57.177.001 53.757,333 $7.351,70. 52,540.922 P \004712 Hutchinson\3153101010 Rate Study\Data An.lysis\HUtrhin-,on Elortric Operating Rosult, and COSA,x\Ex 2 A Oper Results Exist Ratu, 2 rje, Ir -:arse N.,.r Ir.corne a, Percent of Operating Revenue Rexen-je Requirement, Cash Reserves Beg:nnir.g,;f Year Cash Reserves Plus Net Income Plus Depieciat on Le.s Cap ta' lrnprcvernents Le!: Ewid Fiir.Lipal End of Year Cash Reserve,. 270.352 75 314 525.3 13 4-3.E1- 1.1FS.935 ..340 2.37--.570 2.505..M 2A59,2-5 1.519.05 I ?`F 0.41. 2 Z", 3.0".. 8 Z'o 115".. 16.9'. 17.1-'.. 16.6'. 9.5% 25.376.56-3 17.3-42.9-12 1,318,476 12.296.455 13.052,92-2 1:.974.3'.3 11.677,790 12.115.377 12,572.212 14,77.217 51.163,16�1 $1.326.760 S2.499,231 54,524,-42 5(-.540.826 1.69-'.640 1.37--.570 2.505.295 1,519.C55 1.05C.00C 1.141.175 1.156,720 1,171,037 (1533 c5c.) (1.20.1,200) (456.250) (429.5001 (429,5001 (I.C43,000) (1.155"000) (:.21C.0001 (1.275.000) 5IAE3,1-7P S2.499.231 S4.524,342 57,52M 44b F.\314712 Hut:hins-n\315310010 Rate tudy\Data Gas O.Deiat.-rg Re;uIrs and COS.-I,\E% 2-13 Opei Re;u.x,, Ext:! Rale. Exhibit Hu',crin;o,, Ut Qe, P.1innesota Nat,i a Gas Operating Results E,.ting F.ate, sz.,i,,al Foreas- Ocierat rg Re%enue: 20 20-0S 2009 Z1.10 Nil 2012 203 2014 2015 2016 Sales-Na'wal Gas-Retail 1 A.297.23! 9.503.933 7.-)55.961 2.154'.9517 9.E71.01r- !7.255 9.307.0,51 9.441.375 9.576.701 Sala; to Tramp-citation Customers 3,323,6(:7 4.51952.' .1..'4-3.760 -2.07E% 101 3.5-13.lz01 3.829,601 4.619.601 New Ulm Tran,,pc.r'3tir. 712.0.'9 72]5-:-' 719..7, 721.2I2 7-1-l.-',:7 744OCC 70C.'1(.C. 700.0.10 700.000 7CC.000 Tran,poization Electric D-vision 11''-71 CO.) 1.1'.1 A11-1 1 -1.u.:,". CC 3 -.100.0110 1.1:)" :000 1.1c..7 M) 14 - �10,oriu Toral OpeWir.g 14 F:4F.Fr-9 1.1.--i•:0: 14.221417 14.665 t5•t 14.05:.31'014.C'3.66.1 15':71.4/7 Pu-cha,,e,J Ga, Pu,zha,.ed Gas for Retail 11.47?.09: S 539.CS2 7.2-13A34 5.(-34.22-0 5.513,657 4 47s:0-- 4.4-'0.990 4.538.774 5.605,783 Contrast Ga-. for Tia.%oo,t C6,-,zn,ei, 5.-'-'!.527 2.714.54- ...ES6,97 -2.M4.454 - 3.351 1110 3.670.340 4.462,240 Tc-M! Gas PLrchased _..473053 13,750.605 1-.057.E22 E-.5..---.771 9.028.7L'4 2.775.7..16 7.391.365 7.76-1.170 8,209.114 10,074,023 Transiri.s.ion F. peri,e Gas liansn,.i,;i-n Opera` on 39.611 10-1 144 91.49Q 10-1.000 iq".lzfl 11C.224 113.6-14 117.053 Gas Tr3r=.i;;i•:n Wsinte^arce 7.361 I.iF47 2-10 -.962 12.:00. 12.463 12.6-7 13.2122 13.619 lotal Tran:rn ;;io,, 95.972 10379: S-3.441 IC, E 441 ill ice 11'-.593 13.170 126.866 120,672 Di;tr F.ution bpense D..-.tr.bution Operation S-jpervisirr & Engineer.r.. !-7.811 1r. 3.1FE9 156.9:4 159.L2,1 154.8: 1 155.520 160 196 165.002 159 952 Mains & 11S-.'.34 .15? If, I CIS 500 1111,755 115.108 II5.561 122.118 \'e Leri 1:117. c:.308 A.-I-12 K4 '..5X 3.64'5 3.713 3.825 3.939 M.;-:e anec,;s 121.6-16 1-3 729 142.912 1-57,100 172.113 177.276 182.595 188,073 Tcta! or; Operanwi 405.854 4:2.:•1[' 4-'-;.9/2 .11 -I0I.554 430AU; 45 6. Z' -3 3 469,982 424081 D Aributior..V,intv,!3,;-:e Lines -Se•vice; & P03M. 32.E!5 64,x,0 E3.1-K .5955 122.275 10 2.3150 117.960' 1233,715 130.0559 MeLor, & F,:uie Regula-..:.-; 2.9?8 6.332 9,§5'? 11.920 15.000 15 75-1 16.5?2 17.3E4 .8.: 33 P.'..intenan:e 'Other P.drit -3.325 1 59.635 44.2?:' E-1.E37 55.00,11 57,750 60.:35 63.E.4.9 66353 .xal r, ;Wbljtion Klainte^an--e 4p 951 I,, e 177.000 ISS.M' 195.14 2V4.900 215.145 T,-.t,i' D stribution 4,-'19.237 .133 549.1-14 562 590.717 6C7. 1 C-.1 1528.853 651; 36 674.822 699,22-7 Customer -ervi.-, & CrIlecz.on Motel Rpading 39.20', 4) C21 E6.621 6:.211 H.215 24.750 25.955 27.2, 7 29.651 30,084 Celle-, on : per.si 6 -3.4 T, 71.4?Q 51.01S 72 f " 60"31.: Q.I.M 99.555 104,534 10-3.790 115.242 Eat De r.:s 10.925 9.254 9.00.) 9.090 9.181 9.273 9365 C:lj,t:m.er Servi:e 22.108 1.0 o65oe5 32.343 3L1."71 23.565 35.550 35 4C-7 315.265 3-7.E27 35.993 Torsi Cu:toqier Sery ce & CAecu;n 146.150 174.-!.' 168.7''2 1-:4.11F. 170.5:E- 177.266 I84,111 191.6-31 E 35,5 1.750 2.955 1.557 1.0-54 2.143 2.164 Wisc ..Aingll-pe-e S-1 25.1 77, 75.4 0£4/5 67.1-1-) 07,511 62,42-S 69.174 _:.2.. . 71-.Q750Z0 62.55 t?.241 159.9 AIX 71.339 Admin ;trat vo P, Ger.er31 Admin.;LraL ve & GneiA Labor 14C.75,q 151'.5:9 15.-.!A-S 12_.5:5 1 161.-15 10,936 17..295 Orrice Supplies & E%por,--e% CS.391 67.0?7 2,'- 4�? 52.09E- 5,--,768 M,99-" 90.77C 9-1.5e5 9-37 9(-.,326 Ou,Av �eivicet 4.023 -19.532 53-1 .236 27,04. 4 6.0-2C 453[:1 50.715 53.251 55.91- r,orl-ty in,ii-ance St-A(-(' 87.991 911.-?? 92.C-C7 15.5'.0 9E-.EC-'- 97.777 95,754 99.742 En.pi, vee ren,ion & B"ebis 3':5.610 3i-5.976 301.13- 395.25C 407.1f-S 419.321 43: °00 4.14.857 Rigulatc-,y L,ren;- I,-- 209 137-' 17,037 1.-.320 22.50C. 2,4300 26.244 28.344 30,611 P.'.c. General Expense 125,763 1 81--.528 90377 ?0.9cc 9.71S 94.572 96.464 92.34-3 r,'..InL of Ge,,era' P.ant Ze 733 35.55.5 :7.5-0 45.842 2.1%16.3- �,Q7C 40.139 41.3-13 42.554 -13.361 Tout Azln,.,n,,,t, & Ge,era 344.. 19-1 ,r_'?45 9 )1 751.123 712.74t S-2-7.710 961.5c�s C87.200 1.1313 SES- 1.04ri.5.Sis Depre:Mi--ri E 6 1;926 1 1:'37.7':7 1.04:.%171 1.O5;).00C 1.101,102, 1.:.11.175 1.156.70 1.171.037 F a, nient in L e-J Or Ta, et 355.471 :82.067 415.920 441 KZ 5(-4 -252 394.073 31.103 403.314 386.412 402.068 T-77al Operating E,pense 41.34.1 1c..21F 213 13.3' '.?32 12 %5 i;n? 1-I.J.3..7C- 12.112.3E4 11.315.664 11.2.22.606 13.731.053 Olovi 3ting. W.-ime 3.2116.577 1041.449 1.335.477 1.-£4.494 6.17 2,557.52 :..21,-:.0:4 3,304,993 -4-2,870 2.215.249 Otter In.-orne/(buen.e) S-*.251 1C2':t4 42.129 51.7-,-' 33.23F: 4C.CCC 40,000 41.30 40,000 -:0.000 Interest 1?9.07!- CS -11: 36.312 30,460 N,5V7 25 003 3.317 6,248 11.311 16.352 Mi--,,ellaneout Income 574 4.710 .1231 1.3:,1 1 coo 1.000 I.000 1.000 Gar, on D."Posal -.-=54 PdisceIlare-us E+pen:e (5.416) (.7.75-) (35.1771 (A.000) Kqc-c-) N'.000) (6.000) Intere;t E-Per..e 11.141.602; (1.083.999) (926.506) (956.999) 1421.5.111 13882.7611 (.40.961) (795,9-6) (7.7.516) Tota' Ot^ , (cQ4,73.': (SE1.949) (a44 444) (799,713) (744.605) (696.164) rje, Ir -:arse N.,.r Ir.corne a, Percent of Operating Revenue Rexen-je Requirement, Cash Reserves Beg:nnir.g,;f Year Cash Reserves Plus Net Income Plus Depieciat on Le.s Cap ta' lrnprcvernents Le!: Ewid Fiir.Lipal End of Year Cash Reserve,. 270.352 75 314 525.3 13 4-3.E1- 1.1FS.935 ..340 2.37--.570 2.505..M 2A59,2-5 1.519.05 I ?`F 0.41. 2 Z", 3.0".. 8 Z'o 115".. 16.9'. 17.1-'.. 16.6'. 9.5% 25.376.56-3 17.3-42.9-12 1,318,476 12.296.455 13.052,92-2 1:.974.3'.3 11.677,790 12.115.377 12,572.212 14,77.217 51.163,16�1 $1.326.760 S2.499,231 54,524,-42 5(-.540.826 1.69-'.640 1.37--.570 2.505.295 1,519.C55 1.05C.00C 1.141.175 1.156,720 1,171,037 (1533 c5c.) (1.20.1,200) (456.250) (429.5001 (429,5001 (I.C43,000) (1.155"000) (:.21C.0001 (1.275.000) 5IAE3,1-7P S2.499.231 S4.524,342 57,52M 44b F.\314712 Hut:hins-n\315310010 Rate tudy\Data Gas O.Deiat.-rg Re;uIrs and COS.-I,\E% 2-13 Opei Re;u.x,, Ext:! Rale. Section 3 COST -OF -SERVICE STUDY Electric Division In order to Compare reVCnucS to re%VIlLIe requirements by class for the Electric Division, we have performed an analysis of the cost to serve each customer classification based on adRINted ?1110 revenue rCClLIirCIllCI1tS ("Test Fear"). Ill the cost - of -service study. the filnctionalixed costs of providing service are first classified by cost component and then allocated to each class of service based upon certain specific service characteristics. The results of the Studly indicate the degree to which existing rates reC0VCr reVenucs fi-onl each customer classification oil a cost of service bads and are considered in designing new electric rates. The cost-ol=service analyses used in this study have been based on: • Test Year reported revenue requirements and revenues based on current rates, • total system and customer classification power and encroy requirements, • actual and LISSLInied CLIStorrier Service Characteristics. and • Information obtained from customer accounts and records. Classification of Costs As a basis for allocating costs to indi�•idual customer classifications, we have first classified the Electric Division's Test )'car IVVenue requirements to four specific cost components. These components and the type of costs assigned to each are described below. Demand Component - Those costs incurred to provide an electric system capable of meeting the total combined demands of CLISt011IC1'S. Demand costs ll1CILlde the portion 01'purchased power and generation costs. operating and maintenance expenses, capital expenditures and other costs which are generally fixed and do not vary materially with the amount of CICCtricity Consumed or which cannot be designated specifically as a customer or cner��y cost. Energy Component - These costs that var\' sllhslantially or directly With the amount of energy purchased or generatedl. Energy costs are those costs which could be expected to vary with electricity consumption. Customer Service Component - Those costs directly related to the number and type of customers, such as custonlcr sel-Vice. customer accountim, sales, billing and collection. Customer Facilities Component - "Those costs directly related to the number and sire of customers, such as the casts of meters and services and other equipment needed to provide service. Section 3 Other operating, revenues, other income and expenses and Payment In Lieu Of Taxes were divided between the blur cost col11pl rents described above based on each component's percentage of total reVenue requirements. Acffustnlents have been made to the: Test Year revenue requirements to snore aCCurately reflect Costs dtn•in,' the Study Period, in particular the cost of purchased power. These adjustments are shown on Exhibit +-A at the end of this report. The table below sun1111arireS the adjusted "fest Year revenue requirements of the Electric Di\-Ision by cost classification. Exhibit ;-13 details the classification of electric plant- u1-ser\,lcc. Table 3.1 Classification Of Electric Division Costs 2010 Test Year Cost Component Revenue Requirements Demand S11.106,682 Energy 12.826,049 Customer Service 921.478 Customer Facilities 771.825 Total $25.626.034 Allocation To Customer Classifications Based upon actual and assullle:d CUStonier service Characteristics, Nve have developed various factors for use in alluCatin�, the Electric Division's adjusted "fest Year revenue rCiluirCnlents to Ind1V7dUal customer classifications. These allocation factors reflect accepted ratenlaking principles and are based upon fully -distributed, embedded cost allocation procedures. The following sunlnlary describes the specific allocation tactors used in our Cost-ol=service analysis. Exhibit ;-C at the end of this report sets Birth the deN•clopnlent of each ol'these factors. Demand Allocations Coincident peak demands by customer class reflect the tnaxllllll111 1nontilly and annual demands on the system. We have estimated class monthly peak demands coincident with the system monthly peaks for Test Year 201 U. Non -coincident peak denlands reflect the: peak demand of customer classes whenever that play occur, they do not necessarily coincide with the overall system peak. Peak month and 12 -month coincident and non -coincident demand allocators have been developed liar this study. Demand allocators are based on the I ionthly nietered demand for the two demand billed classes — Large General Ser\ -ice and Lar, Industrial. Demand allocators were estimated liar the non -demand metered classes - Residential and Small General SerN•ice, based im the results of load research studies lin• other utilities and the experience of other utilities relatlw to the load characteristics of indWidual classes of service. 3-2 SAIC Enemy. hivironment & Inlrastructure. LLC 1111,45 COST -OF -SERVICE STUDY For customer class allocation pathoses. the annual coincident peak (I CP). the 12 - month coincident peak (12 Ch1, the annual non -Coincident peak (I NCP) and the 12- nwnth non -coincident peak (12 NC'P) Nvere used to allocate the Electric Division's fixed production. transmission and distribution costs. The allocater chosen depended Oil the utility function and specific demand cost items. Energy Allocations The costs related to generation and the energy component of purchased power have been allocated on the basis of each customer classification's annual encro.y requirements at the inlet to HL!'s electrical system for the Test fear. Customer Allocations C'ustonler Service related costs have been allocated anion- the customer classifications based on the CUStllnlCl• Service allocation factor. This tactor allocates customer related costs such as customer hillin-. customer service. sales and nater readin- in proportion to each classification's wei"hted number of customers. Such a•ei,,htin�ll tactors are developed to represent the (lifterence in service Conti�Ourations between Custonlcr classifications. Customer Facilities related costs have been allocated aman�(I the Custonlcr classifications based on the Customer Facilities allocation factor. This tactor allocates Customer facilities related costs in proportion to each classification's weighted number of custorn rs. The factor represents the difference in the cost of equipment used by different classifications. These two weighting factors were developed based oil the experience (if other utilities, as well as information obtained from HLI. Cost -of -Service Study Results Based upon the cost classifications and allocation methods described above. we have estimated the cost to serve each customer classification during the Test Year. Exhibit 3-A. Functionalization and Classification shows several adjustments to 2(10 recorded expenses. These adjustments \\-ere made to better reflect expenses during the Study Period. Sitynilicant adjustments were male to reflect the chan4Te in HLI's purchased power contract from NSP to MIRES, as well as expected changes in the levels of (Feneration and market purchases during the Slulh' Period, compared to 2010. Overall purchased power and generation costs for the Test )'ear are approximately $1 million lower than in ?OI O. The margin has been increased to compensate fir the decreased purchased power costs, in order tier unbundled revenue requirements to produce the sante revenue as the Current revenues. The results of this study are presented in detail in Exhibit 3-D at the end of this report. The table below compares our findings Irons Exhibit 3-D with revenues from each customer classification durin, the Test Year. 1x11;; SAW Energy. hivironmrnt & Inl'rasu•urture. LLC 3-3 Section 3 Table 3-2 Electric Division Comparison Of Revenues And Allocated Cost -Of -Service 2010 Test Year Customer Classification Total Allocated Costs Total Revenues Residential S5.224.240 55.107.357 Small General Service 1.725,538 1,637.967 Large General Service 7,616,237 7.408.962 Large Industrial 11.060.019 11.471.748 Total 525.626,034 $25.626.034 For purpoSCS 0i'determining the extent to which existintr rates match recox-ery of costs fir each class. we hax•e made a cornparlson of Test )'ear rex-enucs based on existing rates and the allocated cost-ol-service fir each customer classification. The results of this comparison are shown in the following table on a percentage basis. Also shown in the table are the approximate percentage increase -'(decrease) in each customer classification's rates necessary to produce rcVcnucS from each classification which are in accordance with the corresponding percell ta�IFe of total cost of service. The percentage increase or decrease shown in the table below docs not represent a recommended rate increase or decrease for these classes. 1teconunendations fir new rate designs will be presented in Section 5. 3-4 SAIL' Ener....•, Environment & Inli-astructure, 1.1.C' u1X45 COST -OF -SERVICE STUDY Table 3-3 Electric Division Percentage Comparison Of Revenues And Allocated Cost -Of -Service 2010 Test Year Customer Classification Percentage Allocated Costs Percentage Revenues Increase/ (Decrease)0) Residential 20.4% 19.9% 2.3% Small General Service 6.7% 6.4% 5.3% Large General Service 29.7% 28.9% 2.8% Large Industrial 43.2% 44.8%3t 6°/u) Total 100.0% 100.0% 0.0% (1) Adjustment represents Test Year data used for cost of service analysis and does not represent a proposed rate increase or decrease. As indicated by the above comparison. HU's existing electric rates are not exactly in line with the Cost to SCI-Ve each Customer Class. Cost based rates are one of' several (Foals in establishing rates. The relationship between allocated Costs and revenues for each Class should he Considered. in addition to other rate related goals, in deN-elopin" reco111111endell rates. Gas Division In order to compare revenues to revenue rel.luirernents by class for the Gas DIN-1sloll. Nve lizwe perlin•nled an analysis ol'the Cost to serve each Customer classification batted Oil adjusted 2010 NN-enue requirements ("Test Year"). In the cost-ol-senviCC study. the fianctionalired costs ol' proN-idinLg service are first Classified by cost component and then allocated to each class (if' service based upon certain specific service characteristics. The results of' the study indicate the degree to which existing rates recover revenues fi•onl each customer classification on a cost of service basis and are considered in desi�,nin�g new gas rates. The cost-ol=service anah-SCS used in this study haw been based on: • Test Year reported rex•enue requirenlents and reVenues based on existing, rates, ■ total system and CustonlCr classification conullodity and capacity reiluirenlCnts, • actual and assumed customer ser\ -ice characteristics, and ■ inlurnlation obtained li-onl customer acCounts and records. Classification of Costs As a basis liir allocating costs to indiVidual Customer classilications. we ha\•e first fiulctionalized and classified the Gas Division's Test Year revenue requirements to troll- Specific cost Components. These components and the type oC costs assigned to each are described below. 111.4i SAIC Friers\-. Environment & Infrastructure. LLC 3-5 Section 3 Capacity Component - Those casts incurred to pro\,icde a Visas system capable of rneehng the total combined demands ofcustomcrs. Capacity costs include the capacity portion of purchased gas costs. operating and maintenance expenses, capital expenditures and other costs which are generally fixed and do not \,ary materially with the amount of gas conSUmed or which cannot be designated specifically as a customer or eonunodity Cost. Commodity Component - Those costs that vary substantially or directly with the amount of gas purchased or sold or which can be attributed to gas purchase \,olutnes. Customer Service Component - Those costs direct[\, related to the number and tNile of custonurs, such as customer ser\,ice. Customer aCenu1ting, billing and collection. Customer Facilities Component - Those costs directly related to the number and type of customer facilities. such as the costs of meters and scr\,ices and other necessary equipment. Other operating revenues. other income and expenses and Payment In Lieu Of Taxes were di\,ided between the lour Cost components described abo\,e based on each component's percentage oftotal re\,enuC rCCfuirements. The table below SUnlmarizes the classification of Test )'car re\,enue requirements of the Gas Di\,ision. Exhibit 3-E at the end of this report shows the detailed classification of revenue requirements. Exhibit 3-F details the classification of Las plant -in -sen -ice. Table 3-4 Classification Of Gas Division Costs 2010 Test Year Cost Component Revenue Requirements Demand S911.046 Commodity 10.165.718 Customer Service 552.422 Customer Facilities 882.074 Total S12.511,259 Allocation To Customer Classifications Based upon actual and assumed Customer ser\,ice characteristics, we ha\,e developed \,arious factors fur use in allocatim, the Gas Di\,ision's adjusted Test fear re\,enue requirements to indi\,idual Customer classilications. These allocation factors reflect accepted ratemaking principles and are based upon fully -distributed, embedded cost allocation procedures. The following summary describes the specific allocation factors used in our Cost -of -ser\ -ice analysis. Exhibit 3-G at the end of this report shows the de\,elopment ol'each of these factors. 3-6 SAIC Energy. Environment & Infrastructure. Ll_C M%45 COST -OF -SERVICE STUDY Demand Allocations To allocate demand related I—CVenue requirements to individual Customer classifications. we have used two dliTcrent demand. allocation methods. These methods are the peal: responslbill ty method and the average'excess method. Under the pear responsibility method, demand costs are allocated to the customer classifications in proportion to their respective contributions to the Gas Division's peak demand. The peak responsibility method is used to allocate demand related purchased gas costs. It is based loll class consumption during the peak month ofthe Test Fear. January 2010. The average excess method is used to allocate the remainder of the system capacity related costs. It is a two part lurniula. One part of the li,rmula determines each class' share of the average use of the system. based on each class' annual consumption. The second part of the furnulla recognizes each class' share of the costs above the average use of the system (excess). This is done by determining the excess demand of each class on the system above their average demand. This part of the formula takes into account the class load factor. This capacity cost allocation method recognizes both the average gas requirements. as Nvell as the peak loads of each customer classification. Exhibit ;-H shows the development of this allocation factor in detail. We have used the peak month data our January 2010 as a measure of' peak period rCCfuirements. as IIt.) does not haVe sof lClent data available to determine actual peak day usage by the various customer classifications. Commodity Allocations Commodity related costs have been allocated to each class of service based on recorded gas sales fur the 2010 Test Year. Due to the different conlnlodity rate for purchased gas between the retail lull service customers and the gas transport customers. commodity related costs fir retail customers have been allocated based on class sales. Commodity related costs for the transport customers have been directly assigned to the customers. Customer Allocations C'uStCnler Service related Costs have been allocated among the customer classifications based on the CIIStolllel' Service allocation factor. This tactor allocates customer related Costs Such as customer billin", customer service, sales and meter reading in proportion to each classification's weighted number of customers. Such weighting tactors are developed to represent the d111erence in service confi-gurations between customer classifications. Customer Facilities related costs have been allocated among the customer classifications based on the Customer Facilities allocation tactor. This factor allocates customer facilities related costs in proportion to each classification's weighted number of customers. The weighting tactor represents the difference in the cost of equipment used by different classifications. These two weighting factors were developed based on the experience of other utilities. as well as information obtained from HU. BIN -15 SMC Enerov. Environment & infrastructurC' e. IL3-7 Section 3 Cost -of -Service Study Results Based upon the cost classifications and allocation methods described abox-c. Nve have estimated the cost to serve each customer classification during the Test 1'ear. The results of this Study are presented in detail in Exhibit 3-I at the end of this report. The table below compares our findings iron) Exhibit 34 with the re'•enues from each customer classification during the Test fear. The Industrial class had only one Customer in 2010 for 4 months. This customer then became a transport customer for the: remaining 8 ninths ot'2010 and currentiv remains a transport customer. Table 3.5 Gas Division Comparison Of Revenues And Allocated Cost -Of -Service 2010 Test Year Customer Classification Residential Commercial Industrial 3M Total Allocated Costs Total Revenues S4.010.510 53.979.581 3.513,868 3.638,751 399,850 371.349 4,258.686 4.213.609 HTI 328.345 306.313 Total S12.511,259 512.509,603 For purlioses ofdeternlining the extent to which existing rates match recovery ofcosts for each class. we hax-e made a comparison of "fest )'car rc\-enues based on current rates and the allocated cost-of-serx-ice fir each Custon)Cr classification. The results of this ci rnparison are shown in the lullowing table on a percentage basis. Also shown in the table are the approximate percentage increase (decrease) in each customer classification's rates necessary to produce 1•eVCnuCS from each classification which are in accordance 11'lth the Clll'1'CSpoll(Iing percentage of total cost of seri ice. 3-8 SAIC Eneruy. Liwirtinment & Infrastructure. I.I.0 It 1,4'1 COST -OF -SERVICE STUDY Table 3-6 Gas Division Percentage Comparison Of Revenues And Allocated Cost -Of -Service 2010 Test Year Customer Percentage Percentage Increase/ Classification Allocated Costs Revenues (Decrease)(1) Residential 32.1% 31.8% 0.8% Commercial 28.1% 29.1% (3.4%) Industrial 3.2% 3.0% 7.7% 3M 34.0% 33.7% 1.1% HT1 2.6% 2.4% 7.2% Total 100.0% 100.0% 0.0% t1 t Adjustment represents percent increase needed to match revenues to revenue requirements by class and dces not represent a proposed rate increase or decrease The table above indicates that the HLYs existing Las rates are within an acecptable range of the cost to serve each customer class. The hlchlstrial class /luring 2010 consisted of only 01le CLIStolller Ior 4 months. C0115ClIUC1ltl\', the analysis results are not as accurate as lur a 11111 year of a Customer. Cost based rates are one of sex-eral ,,gals in establishing rates. The relationship between allocated costs and revenues for each class should be considered. in addition to other rale relatedgoals. in dex-eloping, reConlnlrncled rates. I11%45 SAW Lnergy. Environment be IntraslruCture. LLC 3-9 P \110471: Hutd.ins3n\315510101ri Fate St: AA:)a:a A• aly,i;\Hutchirsan E ectric Operating 8e.;ult: and COS •1s•\k• 3-A Fun: -C -ass f 1 E.hibit 3 A Hutchinson Utilities. Minnesota Elettnc Divi ion Funclionalization & Classification Test Year 2010 2011] Ad;uamerd, Test Year Demand knerl;v Cuat Sery Cust Facil Baas fnr Classification Operating E.pen;es Prc•r'rr::r;an Operat on; Supervmcn and Enginee•ing 5:e x•54 576.954 ?!_.45.1 10-1 Demard Other Emp!o ee Eene= is _ ,__� 9?.214 . 3.: 14 1•W Demand Fuel. -,':!7 ?2.707 32.707 10;'-: Cn.rgy S tat ar. /1,57? 70.573 70.5:3 100" Demand Ga: rcr Generation 5S5.44n 161.734 7-7,250-• 1 747,230 100" Erergy Tra•::portati,r• 1.1'I:.N.; 1.100.0.1: 1.::}:.000 1CC"- Energv O'he! :.776 10.776 10.7/] 00" Demand Tc tat Operat.cns 2. /6S.F7: 1•:1.7:: -.''.1.45.1 1.C51.517 1.279.9.;7 0 0 Ma r:enance S1ru;cure; 3,1'_7 3.117 ?.117 100'. Demand Generating Jn•t; -._.-._ 265.34.1 255.?43 100 ..Demand Other E4uiprimr.t 5;..7-9 26,749 5??49 100.Demand Total.Va-menar:ce 35;,14 0 _5/,2;� 357,2= 0 C 0 Teta; Pnductior 3,1N.OF4 M.73.1 3,2d5.695 1.405 731 1.875-.937 C 0 F aver Cost. Purchases P•:•v.er 14.643.1041:.:•'•1,360; 1?,41-5.:44 - -.v: 1:1 8:3rs4•;21 Whcle:ale Fewer Edi Olhe• F,-er Sopp'l• Supo.rvi::on and Ger-al Sa'arie; -5.,223 .:+3.223 -64.:2? 100. Demand Training -'.13: 2 •1:== 2 i8c 100 .. Demand Prore:siorol Seni:e: Pr_ 445 P;.4-5 E5145 100" Demand Total Caher F'oasr Snpply 3-11.154 C348.1.`•1 54-AS4 0 0 0 Trarsmi:nDri C'per atlLn: .'tat �n 13'.0!•1 1_':.051 1'.'2,1151 1301. Demand Mlaiwenar.e Pian; and E•gaiprn+nt -S,15a :t-js5 2C;Ac�? Tranvi. Flan! Tata'Tr3n:m.s:i7n i57.2C•1 0 _57.20- 157,20- 0 0 0 C�clr kuOan Operations Sapervmon and Frgireerirg .=2.nc: -.-.. .19..4-9 10: 153 Direst Dictributicn Casts L:re ?6,71' ?--.717 15.35'• 15.?5� Pale:, Twwerc and Fi.tui es P.an' Mleter 1G 3__ 115.'_'26 16.?25 F.'eter: Plant Other Go 953 S.?.95 59.555 83,093 Custribut.on P.an: ia:ol C:perat:l•r ....-c -32.6-: 266,7:2 !: 0 172.?35 f.la rtenarice Sat.- Cluipmerl �..1 a`• S.lar. 5 155 .9 La L-on F Iant I lncerground Ln?; 91-023 94•.C::3 a ;,0:: 4.'.012 Llndergrcund Pon', Line: Trancformers 2_._54 : 1 3S1 2:.854 Tran;farmer Plant Svev- L:gl : rig 73.026 75.0.'= 73.0-:: 1C.3". Deman.i Other Ejuicrier.t S5.F" 3!.=!S 21.5"1 14,097 D:rtnkntirn Plar.t Total ": a raer.ann,i '34.71, 0 2?4.71: 172.:637 0 62.1113 T•:•ta D;tributicn 473.3[•.' 0 15:5.363 -1i".?20 0 0 2'50.13 Cu:t:�mer A:cora:s E•perse Meter Fe3 Jing ::C.2l KE, E, 100.? 15 10:0'„ Cl.:t•x• ser Sen. ce C.-Te.-tion 9 .70= 49.70-' 92.70: 104'0: C:l.`.torner Service O:•rer Employee Ee,elas ,.--.. 7,26:7 7,2:0 100 Customer Service Unco:lectible Acecunts 1?."81 13.551 1?,831 10C .: Cu:t7mer Service Custorne• Service; 45.557 45,557 15.557 100. Customer Servi:e Cthe- 1.979 1.97- 979 100": Crr;:on.er Service Tf ta' Cu:t}mer Account; brF .r::e N9,202 C -r..202 0 0 261,202 0 Sa'e; E.Ferre Sa 3rie: •1::.:45 4-:.0-15 4;;.6:5 1110 •• Cu;' omer Service Con:ema:lar 190.:..' 196,:9. 1'...92 1'.'.0'. Custcnler Somice Total Saly -F-r -r-e 24'.93, tl P \110471: Hutd.ins3n\315510101ri Fate St: AA:)a:a A• aly,i;\Hutchirsan E ectric Operating 8e.;ult: and COS •1s•\k• 3-A Fun: -C -ass f 1 E%hibit 3-A Hiit,hinscin UtillUes. klinnescita Electric Elri;ion Fun(tionalization & Classification Tett Year 2010 3 AA,w!e-J Aclpist,id t,, relle--t po-e.er wrl-ly C-WIUA. t, dk,rine the Stul; Fen -A C.a.ri'Mc ;0 on of Al:eL: h3: : Leon zidji.:'od t, 0 t, re!le:t a t,ra' 4 c3oacn, ;ale t.,, :.rx.'PA a....; a, cne'g-; Ae S 3-2_t Lie'it re%enL,e is al'a-.'at,.d ;r p-r 0 or :a co,L; related to Ci.f.1 , ereq;. P %C04112 Rare Stud,\[ata Anilv-;;:'.Hut:hin:�-n Ehc;,: Cporating Fosuh ar,l CO -I-,-'.E- !-A Fun ,_Cla , of 2010 Adjustments Test 'T eai Demand Energy Cu3t Sery Cust Facil Baal, for Classification Adinir.,!rati,e 3rd General Eupe"i ard Gerera' 3313rie:. .15•:•3?? 4c.." c, -,q 79.555 3 1.e70 S,joto', Rev Rej les, Puic Pwr Offic. SUrr.l e; 2523 55 37.70.: Sjo'.ot' Rev Foe le-,-, Pur.. P,r 41-, •-e: - 17.0'3 S.IIV SAW,, Rev Req le;-, Ptji-- P.vr Pr,oert, I ,trce ..C5? 14.555 Tela' Electric Plant Wea cal I Z12 F5.oK 59.325 47,051 S-ihtml Rei Req le;; Pur: Pr. i Emplo-,,ee =z 1_' tc 5zz35 55S 4-s.06, 9C 636 4-91A Sdotozz. Re, Rej le:.- PL,c P -�v r Regula tol .11 SOL 21 .,jl 3.5?7 1.05 Subt,tl R- Req lets Pur: P%% r ]31ario: _5.075 JF 175 11.4.:1 2.4.:t 1.158 S-jbto-: Rev Reel to:-, Pur: Pwr Tra,elS. 5 =S 5.385 i.K? 7`1 Subtod Rev Pq,l 1.s, Pur.. Pwr E.ren:e 4 7 C. AC. 15.072 7,1 ?i S-ihtntl Rev Req less Pur. Pwr 'iinter.3r Ge,- I V' t FA.c. 5 4n.5!0 7,455 T-tal Ele--tri--- Pla-.t T -Aa: Acm n -.r3-. %e and Ci.,ri-imi ?.506'_.7'21.?:: ?4a.??0 I56,25.1 NV". I., x)5,3,12 T. -.',a' Ele.-tri., Plant C-mriLluti, r; t..% C or -l;,,&.n_-cn Pa, i, _leu c' Ta e: 8?5..JC7 !95.4 MI 51-I.A150 N.M, 11,73: Subtot' Re, Req indu& sur: Pv.-r Rc.,ma, L Cl, r -Z 5E.C64 .4.?-)-- 4.065 1,9:S_SLI;totl Rev Req ird,do PUIE Pwr 'to- .jl ron'.-it 1:3 Ci-; �f FL.Uhr-�r 1 042 266 2:0.F 1 i 9 65 22,.S50 13.660 T3 -.;sl Cpo,a',r-1; t IS: I 2.F71-'-; -.A-,4 11.14 n. 3210 11 . i2l 6 557.959 730.34%1 Ime-e;- 'r%wne 30.660 17.705 S4 9 .102 Subtc,. Rem Req mch,cle Pure ;I,r Nl,r- hipJ..e and C,r.v3-_-. V,,, -I, tw i1.. (45=i M51 Subt3tl Re, Reel include F,-j,c Pw, 1, c,"W Bm" %92 16.27S 7.7'-' 2 5-ibW-.: Rei Re ct in:lude Pur.: P Cam Kxsl .-.r. D po� it -%f kseits 15:.:,15 0 3 Banc Ser.i.o F-.- t.8W:I T.tA E: -0r--: P13r.t Am.:irti:zti,n o StuJ. 11,:55'. L76I 1.21-.9. 1"1;:) 0: Exhibit 3-B Hutchinson Utilities, Minnesota Classification of Electric Division Plant -in -Service 2010 Test Year Accumulated System Net Description Gross Plant Depreciation Plant -in -Service Demand Customer Basis of Classification Electric Generation Plant Land & Land Rights $153,900 $0 $153,900 $153,900 100% Demand Structures & Improvements 3,186,663 $1,228,495.80 1,953,167 1,958,167 100% Demand Fuel Holders/ Producers 243,783 $20,226.46 223,562 223,562 100:x, Demand Generation & Prime Movers 36,138,510 $20,105,676.61 16,082,833 16,082,833 100% Demand Accessory Electric Eqpt 1,046,243 $394.078.67 652,164 652,164 100% Demand Misc Power Plant Eqpt 533,677 $170,238.01 368,439 368,439 100% Demand Total Generation Plant 41,357,781 21,913,716 19,439,065 19,439,065 Transmission Plant Land & Land Rights 224,862 0 224,962 224,862 100% Demand Structures & Improvements 622,509 $158,172.21 464,337 464,337 100% Demand Station Equipment 4,443,864 $1,759,772.65 2,689,091 2,689,091 1009 Demand Towers & Fixtures 1,119,298 $277,600.21 341,698 841,698 100% Demand Poles & Fixtures 1,329,161 $402,224.78 926,936 926,936 100" Demand Overhead Conductors 569,796 $194,664.41 375,132 375,132 100% Demand Underground Conduit & Manholes 102,424 $33,394.83 69,029 69,029 100% Demand Underground Conductors 71,569 $22,396.41 49,173 49,173 100% Demand Total Transmission Plant 8,483,483 2,848,226 5,640,258 5,640,253 Distribution Plant Land & Land Rights 123,361 0 123,361 123,361 100% Demand Structures & Improvements 425,169 $136,278.32 233,891 233,391 100% Demand Station Equipment 2.561.448 $1,265,203.64 1,296,239 1,296.239 100"0 Demand Poles, Towers & Fixtures 236.409 $71,498.23 164,911 82,455 82,455 50% Dmd/ 50% Cust Overhead Conductors 130.638 $75,454.16 55,184 27,592 27,592 50% Dmd/ 50% Cust Underground Conduit & Manholes 725,178 $433,024.02 287,154 143,577 143,577 50% Dmd/ 50%Cust Underground Conductors 9,983,084 $2.940,292.32 7,042,792 3,521,396 3,521,396 50% Dmd/ 50% Cust Transformers 3,363,424 $1,238,413.92 2,030.005 2,080,005 100% Demand Meters 1,763,467 $630,487.95 1,132,979 1,132,979 100%Customer Security Lights 0 0 0 (1) Street & Signal Lighting 0 0 0 (1) Total Distribution Plant 19,317,178 6,895,663 12,421,515 7,513,516 4,907,999 Total Electric Plant $69,163,442 $31,662,604 $37,500,833 $32,592,839 $4,907,999 Transmission Plant Percent 100°0 09" Distribution Plant Percent 60% 40% Total Electric Plant Percent 37". 13% (1) Security lights not included in cost -of -service analysis. P:\004712 Hutchinson\3153101010 Rate Study\Data Analysis\Hutchinson Electric Operating Results and COS.xlsx\Ex 3-B Plant in Service Test Year 2010 Cost of Service Allocators Demand Allocators r..., -11 Fl - I p A I I, P I P I P P. -I, .:III V TS 4.) --un .,r r.1 I. :'-nan-N -I M I- 'I. -r P P -v-1 RQ Energy Allocators P— A' I I Customer Allocators P— I I Vj . ..... Ior %i -.l 7—lar It—. W-Jdu.w. .. ........ r, I -t:1 d w d it Mi r I I. I--, ind. L ri-m.v 3nd -'I -I A I- P I -A 4.) RQ Ior 5 - Inn P '.004 ? 1 .' HIM, 111 31 r, 311: 11) 1 :) 'M - - '.W. W. W I . -: - 1 %I' Hu 1. hu. - .. - L 1r, I rk 5: -.: : 1, - .111-f I :.' 7. - I:.'. F• ; -' a!1:•. r I. I. -, .. Z J 4 7- Zk ul d: 4 Demand Component Production Operation Production Maintenance Purchased Power Other Power Supply Transmission Operations Transmission Maintenance Distribution Operations Distribution Maintenance Exhibit 3-D Hutchinson Utilities, Minnesota Allocation of Electric Revenue Requirements Test Year 2010 Total Residential Sm Gen Sery Lg Gen Sery LF Industrial Basis of Allocation $1,051,517 $185,357$70,724 347,678 $362,457 357,214 62,908 24,026 123,131 4,661,420 821,698 313,521 1,606,789 348.154 61,371 23,416 120,009 132,051 33,990 8,105 37,121 25,153 6,474 1,544 7,071 265,712 70,837 16,829 76,923 172,607 46,016 10,932 49,969 $432,978 12 CP 147,088 12 CP 1,919,412 12 CP 143,358 12 CP 52,835 ICP 10,064 ICP 101,123 1 NCP 65,690 1 NCP Administrative & General 1,772,976 347,678 121,000 596,304 707,995 12 NCP Depreciation 1,961,624 384,671 133,875 059,751 783,327 12 NCP Contribution to City 397,891 78,026 27,155 133,822 158,868 12 NCP Non Operating (RPv)/Expns (60,226) (11,810) (4,110) (20,256) (24,050) 12 NCP Credit Resale Revenues (600,000) (117,659) (40,948) (201,797) (239,595) 12 NCP Credit Street Light Revenue (73,026) (14,320) (4.984) (24,561) (29,161) 12 NCP Credit Other Oper Revenues (115,157) (22,582) (7,859) (38,731) (45,985) 12 NCP Margin 808,771 158,599 55,196 272,013 322,963 12 NCP Total Demand 11,106,682 2,091,313 748,422 3,760,017 4,506,930 32,794 8,774 1009., 19"0 71'� 34"0 41°5 3,151 Energy Component 29,034 Wtd Cust Facil Administrative & General 186,254 35,320 9,450 54,417 Production -Fuel Related 1,879,937 340,057 111,342 522,127 906,411 Annual kWh Purchased Power 8,804,324 1,592,592 521,449 2,445,282 4,245,000 Annual kWh Contribution to City 601,865 108,870 35,646 167,160 290,189 Annual kWh Non Operating (Rev)/Expns 951,346 172,087 56,345 264,224 458,691 Annual kWh Credit for Resale Revenue (38G,386) (69,892) (22,884) (107,314) (186,296) Annual kWh Credit Other Oper Revenue (174,191) (31,509) (10,317) (48.379) (83,986) Annual kWh Margin 1.223,377 221,293 72,456 339,776 589,850 Annual kWh Credit Street Light Revenue. (74,222) (13,426) (4,396) (20,614) (35,786) Annual kWh Total Energy 12,826,049 2,320,071 759,642 3,562,263 6,184,073 100"1-a 19.9%, 100°,. 18"o 6% 28%' 4895 2.3% Customer Service Component Customer Accounts 269,202 194,710 52,093 19,999 2,400 Wtd Cust Sery Sales 242,937 175,713 47,011 18,048 2,166 Wtd ClaSt Sery Administrative & General 346,870 250,886 67,123 25,769 3,092 Wtd Cust Sery Contribution to City 28,850 20,867 5,583 2,143 257 Wtd Cust Sery Non -Operating (Rev)/Expns (iG,673) (12,059) (3,226) (1,239) (149) Wtd Cust Sery Credit Other Oper Revenues (8,350) (6,039) (1,616) (620) (74) Wld Cust Sery Margin 58,641 42,414 11,348 4,356 523 Wtd Cust Sery Total Customer Service 921,478 666,491 178,315 68,456 8,215 100"0 ; 72", 19s", 795 1% Customer Facilities Component Distribution Operations 172,935 32,794 8,774 50,525 80,841 Wtd Cust Facil Distribution Maintenance 62,109 11,778 3,151 18,146 29,034 Wtd Cust Facil Administrative & General 186,254 35,320 9,450 54,417 87,067 Wtd Cust Facil Depreciation 295,392 56,017 14,987 86,303 138,085 Wtd Cust Facil Contribution to City 13,660 2.590 693 3,991 6,386 Wtd Cust Facil Non -Operating (R(,.v)/Expns 17,663 3,350 896 5,161 8,257 Wtd Cust Facil Credit Other Oper Revenues (3,954) (750) (201) (1,155) (1,848) Wtd Cust Facil Margin 27,767 5,266 1,409 8,112 12,980 Wtd Cust Facil Total Customer Facilities 771,825 146,365 39,159 225,501 360,801 1009 19*11 5°,. 29% 471; Total Revenue Requirements $25,626,034 $5,224,240 $1,725,538 $7,616,237 $11,060,019 Total Revenue $25,626.034 $5,107,357 $1,637,967 $7,408,962 $11,471,7480 Revenue Requirement Percent 1001 20.4% 6.7% 29.79.0 43.29;; Revenue Percent 100"1-a 19.9%, 6.4% 28.9% 44.8% Percent Change 2.3% 5.3% 2.8% -3.6% P:\004712 Hutchinson\3153101010 Rate Study\Data Analysis\Hutchinson Electric Operating Results and COS.xlsx\Ex 3-D Alloc of Rev Req E-nibit 3-E I A-111, I f..r ;..v ....,jp.- 11:1 du 1:, 1, 1 11-, ov! -n-, In Jwor kali .1 Av.--t- •1l: L•'•:•', ad,:,- 1..I 1 . :; 1, .11,I. - Di%tnb-,l.-,-i , -por % Ma ol _,1 Hxr.hinsenUtimes W IlAltjr� Ga; Di, 1"4 3::3'.4 1..: 33': Fun, ltion3h.z t -.-.n & Clas;ificano- N.-cl.TN;. i.Jjn.irrhp-. 1. 71S --,3 V ?13.1]' :.{•.: V; 36.1 31.-1 le;z 'fear 2010 NU Adjust-ents Te;t Ye Drri.arid cwnw.3d'it, Cust Ser, Cum Fact Basis F:.%r Class f.cati3n FuI, h.., .111,11.11' C.... P. -i. -..l Y --07- G %VhI les.Ye f.r. hill. R.r. hill. Mit-jr- Fill Tr... -•n --1r:. •-porIl 4--A.. VN. Istel ................ .. 1-j vw I I A77 r.1.11 .,!I V +17:.1 111•+': 1 '1:-:1 SF.', nt %--1 1% 6-_-o L:i;1rihjli5 : -1-or 4 lt'.im I.I.-ur, ar.1 161.2 62.614 F.1 ; F. P1 o%l .1 V.q .1,14A n 4.44., M,Avl, Mr.: .,I Se' ,e qLi I- Lu:lrilulini, near P. Maim. 5tai 11-1111L.N4.1% I k; 41% IN 1: 141: ? m,., n.: .-Y 5d 9% S? ;,I Oj.6u-, Lbir.s & S<rwe% Milli. u- Serote M. -to., f, .;lA K- -:I'1,%, in %.: , Up -I ; 4.1 'ti ol st Ni unl I.I.I.Wonar- I%.' 1- 9 I.A..1 3._-: KA . 7 11 1 Lr, -P1.., ....... f F. tir., .11 til.b. sq, mor d.- - F•I'.••1•.'• Sel- T--.-.1 .,I-% Lq Y.1 0 p.::1 A -1 -ii n.-Iril- ii,a rV i4l.- N i6a 4.' 81:. li-ml. Vil.i. t pul-.1% ON- 5-viv., I.... IU `61 pf"Llix., D,T. ft.l.l.r.op"I hg. - .,4 re purch pt Fr.%por: , --r%imn I -'-I al -.. 1. P.-fi, . .,.. r . j 1 . ..... I•.. I on,-. 01- L-4 I, -r-i I U'!r OjL n" P'J1 -t- b" 17.-;. A.) �•I P i. r, en.. r.• , t. On,. .., pdrrh cv. n 11'.. .1 - I I P-J T,,-1 b l. 0, 1. n.. p. -I. p - T, . 0 [-r. Cu, I. no I -. 1, g Ml,-- -. E - p- n- r. J, Prod Tran:. Di.t. Or I. n,- Pilo, p; n•,: -r.1•..... N l.; . ...... 1 4.11"). Hant Adrim 1-i- 0 11'1, n,,- /41 I 'tal W: Plan: imi 6"f N,J T . ....... [:.,l. c., 9.11 10,1 OF •• I - p- I 'Y-: 3.; 1 43k; I V.. J, In-, to 0 144 iji Pr. -.:I I m.r., 1w.1. Ct,-.1 uW M.orrh irdi- ind -'Wra Nol 4, 1'1 1^ - 1 N. -d Tien. r;--.'. Curt. - -.- L.,- .... I V..N.1 3c.i r, ,i Han;. rim omi irr' r-1-1. 1% (b , .: - --i I p -f :"•1 Ain it I Rap:: -A I•.alanr••:., .1•. 1: •'.: •.?; 1. .,1a1 1.'. V-1: 1.- 77.1 Tst.l G- Plant i..w.-r F., c., I r (710: NW -t F-im- I..-T a ri. r: 11 Ciedil Vl-O N. 11 1) M -w .1 W 91.1 a 1.- 14.1 1,...1 D. -A. Cwt. no P.1rn1 gv. TWA R -len- Requiruenh 12.508,905 2.354 12.S1I.25q 0 911,046 30,165,718 552.422 882.074 0 I' .. e :11. 11-3 I A-111, I f..r ;..v ....,jp.- 11:1 du 1:, 1, 1 11-, ov! -n-, In Jwor kali .1 Av.--t- •1l: L•'•:•', ad,:,- 1..I 1 . :; 1, .11,I. - Di%tnb-,l.-,-i , -por % Ma ol _,1 0 W N,J 1, .,%: L --,t 92- Ehn 1"4 3::3'.4 1..: 33': N.-cl.TN;. i.Jjn.irrhp-. 1. 71S --,3 V ?13.1]' :.{•.: V; 36.1 31.-1 r.50:'.1/12 1 mwm,,cr;,.s 153 :L• IL-JU Pale Stl,dv'Djt. All n.11 W; flin.,, -.1 , Co, -N.'L. 3-1, -Jpc tbs: I Hutchinson Utilities, Minnesota Classification of Gas Plant -in -Service 2010 Test Year Accumulated System Net Description Gross Plant Depreciation Plant -in -Service Exhibit 3-F Demand Cust Facilities Basis of Classification Gas Transmission Plant Rights of Way $3,815,718 $0 $3,815,718 $3,815,718 1004 Demand Transmission Mains 26,659,032 3,567,356 23,091,676 23,091,676 100% Demand M&R Station Equipment -H369 1,804,761 259,149 1,545,612 1.545,612 100% Demand Communication Equipment -H370 278,337 149,887 128,449 128,449 100° Customer Pipeline Loca+tor 6,468 431 6,037 6,037 1009s Customer Total Gas Transmission Plant 32,564,317 3,976,824 28.587,492 28,453,006 134,487 Gas Distribution Plant Mains 3,701,008 1,335,516 2,365,492 1,182,746 1,182,746 50% Dmd/ 50% Cust M&R Station Equipment Gen H378 709,548 179,023 530,525 530,525 1009; Demand M&R Station Equipment -City #379 67,334 45,711 21,623 21,623 100.'; Demand Services #380 935,105 250,274 684,831 684,831 100"; Customer Meters & all Fittings 1,487,601 379,498 1,108,103 1,108,103 1009; Customer House Regulators & All Fittings 98,810 38,278 60,533 60,533 100% Customer Industrial M&R Station Equipment 95,747 49,516 46,231 46,231 1009„ Demand Other Equip (CO tester, Gas Analyzer) 77,991 58,563 19,427 9,714 9,714 509.", Dmd/ 50'o Cust Gas Distribution Plant 7,173,144 2,336,380 4,836,764 1,790,838 3,045,926 Total Gas Plant $39,737,461 $6,313,204 $33,424,256 $30,243,844 $3,180,413 Gas Transmission Plant Percent 100" 100"0 09; Gas Distribution Plant Percent 100% 37°; 639'. Total Gas Plant Percent 100% 901; 10% Mains & Services 4,636,113 1,585,791 3,050,323 1,182,746 1,867,577 39"; 61% Meter 1,487,601 379,498 1,108,103 0 1,108,103 0.:. 100% P:\004712 Hutchinson\3153101010 Rate Study\Data Analysis\Hutchinson Gas Operating Results and COS.xlsx\Ex 3-F Plant in Service Exhibit 3-G Hutchinson Utilities, Minnesota Gas Demand, Commodity and Customer Allocation Factors 2010 Test Year Total Res Coml Indus 3M HTI Demand Allocation Factor Peak Period Sales (MCF) - Jan 2010 255,370 82,844 68,782 14,294 89,450 0 Peak Demand Factor 100'% 32% 27% 6"r% 35% 0% Peak Period Sales (MCF) - w/o Transport 165,920 82,844 68,782 14,294 Peak Demand w/o Transport Factor 100.% 50% 41% 9% Average/Excess Dmd (MCF) 255,370 78,325 65,451 13,310 86,857 11,426 Average/Excess Dmd Factor 100%, 31% 26% 5% 34% 4% Retail Commodity Allocation Factor Retail Commodity Allocation Factor 863,608 417,391 400,222 45,995 Annual Retail Commodity Factor 100% 48% 46%, 5% Transport Commodity Allocation Factor Transport Commodity Allocation Factor 798,444 742,444 56,000 Annual Transport Commodity Factor 100% 93% 7% All Customers Commodity Allocation Factor Retail Commodity Allocation Factor 1,662,052 417,391 400,222 45,995 742,444 56,000 Annual All Cust Commodity Factor 100% 25% 24%, 3% 45% 3% Customer Service Allocation Factor Average Number of Customers 5,445 4,918 525 0.33 1 0.67 Service Weighting Factor 1 2.5 10 50 50 Weighted Number of Customers 6,317 4918 1313 3 50 33 Customer Service Factor 100% 78% 21% 0% 1% 1% Customer Facilities Allocation Factor Average Number of Customers 5,445 4,918 525 0.33 1 0.67 Facilities Weighting Factor 1 9 1000 5000 1000 Weighted Number of Customers 15,643 4918 4725 333 5000 667 Customer Facilities Factor 100°% 31% 30% 2% 32% 4% (1) See Exhibit 3-1) for developemtn of Average/Excess Demand. (2) 3M and HTI commodity costs directly assigned. Average gas use per customer month 7 64 11499 61870 7000 ratio to Res 1 9 1626 8748 990 Exhibit 3-H Hutchinson Utilities, Minnesota Demand Cost Allocation by Average -Excess Demand (1) Total annual consumption by class. (2) System peak month consumption (January 2010). (3) Individual class maximum monthly demands, whenever they occur during the year. (4) Total annual consumption by class, divided by 12 months. (5) Class maximum demand (col 3), less class average demand (col 4). (6) System peak month demand (col 2) less the total system average demand (col 4). (7) Ratio of each line to the total for the Process Demand Alloc Basis (col 5), times the System Excess Demand (col 6) (8) Sum of columns 4 and 7. (9) Ratio of each line to the total for column 8. P:\004712 Hutchinson\3153101010 Rate Study\Data Analysis\Hutchinson Gas Operating Results and COS.xlsx\Ex 3-H Avg_Excess Demand Class Max Class Avg Process System Avg & Percent 2010 Sys Peak Demand Demand Dmd Alloc Excess Excess Excess Avg & Annual Use Month Month per Month Basis Demand Demand Demand Excess Class of Service (MCF) (MCF) (NCP) (MCF) (MCF/month) (MCF) (MCF/month) (MCF) Demand (1) (2) (3) (4) (5) (6) (7) (8) (9) Residential 417,391 N/A 82,844 34,783 48,061 N/A 43,543 78,325 31% Commercial 400,222 N/A 68,782 33,352 35,430 N/A 32,099 65,451 26% Industrial 45,995 N/A 14,294 3,833 10,461 N/A 9,478 13,310 5% 3M -Transport 742,444 N/A 89,450 61,870 27,580 N/A 24,987 86,857 34% HTI-Transport 56,000 N/A 12,128 4,667 7,461 N/A 6,760 11,426 4% Total 1,662,052 255,370 267,498 138,504 128,994 116,866 116,866 255,370 100% (1) Total annual consumption by class. (2) System peak month consumption (January 2010). (3) Individual class maximum monthly demands, whenever they occur during the year. (4) Total annual consumption by class, divided by 12 months. (5) Class maximum demand (col 3), less class average demand (col 4). (6) System peak month demand (col 2) less the total system average demand (col 4). (7) Ratio of each line to the total for the Process Demand Alloc Basis (col 5), times the System Excess Demand (col 6) (8) Sum of columns 4 and 7. (9) Ratio of each line to the total for column 8. P:\004712 Hutchinson\3153101010 Rate Study\Data Analysis\Hutchinson Gas Operating Results and COS.xlsx\Ex 3-H Avg_Excess Demand P:\004712 Hutchinson\3153101010 Rate Study\Data Analysis\Hutchinson Gas Operating Results and COS.xlsx\Fx 3-1 Alloc of Rev Rey Exhibit 3.1 Hutchinson Utilities. Minnesc:td Natural Gas Division Allocation of Gas Revenue Requirements Test Year 2010 Total Residential Commercial Industrial 3M Transport HTI Transport Allocation Demand Component Purchased Gas Expense-Retail $5.9.14 $2.968 $2,464 $512 Pk Dmd w/o Transport Purchased Gas-3M 0 $0 Direct Assignment Purchased Gas-I Ill 0 $0 Direct Assignment Transmission Operation 93.159 30.107 25,158 5,116 33.386 4.392 Average Excess Transmission Maintenance 2.209 678 566 115 751 99 Average Excess Distribution Operation 151,412 46.440 33.807 7,892 51.499 6.775 Average Excess Distribution Maintenance 54,403 16.686 13.943 2,836 18.504 2,434 Average Excess Administrative & General 36,721 100.209 83.738 17,029 111,125 14,619 Average Excess Depieciation-Gas 938.966 2£7.992 740,656 48.941 319,363 42,014 Average Excess Payment in lieu of1axes 12.822 3,933 3.286 668 4,361 574 Average Excess Non-Oper (Rev)/Expns 998.713 306.317 255,969 52.055 339,684 44.687 Average Excess Credit for New Ulm Transport Rev (721,218) (22].206) (184.847) (37,591) (245,307) (32.271) Average Excess Cre.ditfor Elec Div Transport Rev (1.100,000) (337.383) (281,929) (57,334) (374,134) (49,219) Average Excess Margin 1.12.914 43.833 36,629 7.449 48,608 6.395 Average Excess Total Demand 911.0.16 280.573 734.440 47.688 307.845 40.499 Commodity Component Purchased Gas Expense-Ret l 6.064.250 2,930.919 .-RD1.355 322.977 0 0 Annual Retail Sales Purchased Gas for I ITI 235.645 235.045 Direct Assignment Purchased Gas fur 3M 3,561.532 3.501,532 Direct Assignment Pdymeirt iii I ieu of Taxes 40:.615 101.109 915.950 11,142 179,850 13.565 Annual All Cust Sales Nun-Oper (Rev)/Expns (37,725) (9.474) (9,OS4) (1,044) (16.852) (1,271) Annual All CLISt Sales Total Commodity 10.165,718 3.022.55.1 2.598.220 333.074 3,x 64,530 247,339 Customer Services Component Cust Accounting & Collecting 179.470 139,720 37,288 95 1,420 947 Customer Service Sales 80.979 63,043 16,825 43 641 427 Customer Service Administiative & General 17:,013 133.+14 35.739 91 1,361 904 Customer Service Payment in Lieu of Taxes 10,699 8.3:'9 7.223 6 85 56 Custumel Service Non-Opel (Rev)/Expns (12.306) (9,581) (2,557) (6) (97) (65) Customer Service Margin 121.567 94.641 25.255 G4 962 641 Customer Service 'total Customer Services 552.422 430.Ou£ 114,775 291 4,372 2,915 Customer Facilities Component DistrihutionOpPratinrr :63.6:92 82.'4165 /4+./69 5,623 84.3.18 11,?46 Custumer Facilities Distribution Maintenance 98.463 30,956 79.741 2,093 31,472 4.196 Customer Facilities Administrative & General 252.409 79,355 76.2.11 5,379 40,675 10,757 Customer Facilities Deoreciation-Gas 94.741 31,043 29.8_25 2.104 31.561 4.203 Customer Facilities Payment in Lieu of Taxes 14.£85 4.68(1 •1.496 317 4,758 63.1 Custumer Facilities Non-Oper (Rev)/Expns (15.4.17) (4.856) (•1,666) (329) (4.937) (658) Customer Facilities Margin 1119,132 53,113 51,087 3.604 54.060 7.20£ Customer Facilities Total Customer Facilities 852.074 277,315 266.432 18,796 281.939 37,592 Revenue Requirements $12.511.259 54.010.510 53.513.£158 $399,350 5.-1.258,686 $323.345 Total Revenues $17..509,603 $3,979.581 $3,638,751 $371.3.19 $4.213,669 $306.313 Percent Rev Requirements 100": 32 V. 28.1', 3.2'n 34.0".. 2.6'. Percent Revenues 1(1011 31.8,n 29.1°, 3 0% 33.7' :. 2.4'. Percent Change 08'-.• 3.4'. 7.7'.. ].1".: 7.2% (1) Based on Demand, Commodity. Customer Services. Customer Facilities and Duect expenses. (2) Direst assignment to 3M P:\004712 Hutchinson\3153101010 Rate Study\Data Analysis\Hutchinson Gas Operating Results and COS.xlsx\Fx 3-1 Alloc of Rev Rey Section 4 UNBUNDLED RATES Based on the results of the Cost of Sel-VIcc study presented in Section 3 of this report. electric and gas unbundled rates have been developed to equal Test Year rex-cnuc requirements. Electric Rate Components Htf's electric rates have been unbundled into four components: wholesale power. transmission. distribution and customer. Each of these components is described belonv. Wholesale Power The wholesale power component consists of power generation, liiel and purchased power charges. For retail classes billed on the basis of demand and energy, the retail demand portion of the wholesale power component represents wholesale demand charges and the energy portion represents wholesale encroy charges. For retail classes billed on the basis of ener(Ty only, the retail energy charge represents the combined total ot'wholesale demand and energy char`ues. Transmission 'I'hc transmission component represents transmission operations and maintenance charges. The transmission charge is a dcnland related charge. This is shown as a retail dcnland charge for retail demand and enemy billed classes and as an cner�,y charge ler energy only retail classes. Distribution The majority of HU's local electric revenue requirements are rellccted in the distribution portion of the unbundled retail rates. It includes a portion of the O&M expenses on the distribution system, the majority of the depreciation expenses. certain ALG and non-operating expenses, and a credit for non-operatim, income. These casts are shown as a retail demand charge for retail demand and ener-v billed classes and as an energy charge liar enern, only retail classes. Customer The customer char�-e reflects both customer service and Customer facilities expenses, including accounting and collection charges. sales, certain A&G expenses. O&M and depreciation on the customer portion ill' the system. and a credit for note -operating income. The customer charge is a monthly per customer charge. 141%.15 SA IE« Section 4 Unbundled Electric Rates Unbundled electric costa and resulting retail rates for the Residential. Small General Service, Large General Service and Laroe Industrial classes are shoxvil in the tables bolo\\-. The individual unbundled components have been summed to sho\y a total unbundled rate. Note that the follo\ying rates are not necessarily the proposed rates recommended by SA1C as a result of this study. The folloNvinv, unbundled rates: • Generate the same NVenues as the adjusted 1'est Year 2010 reyenuc requirenunts. ■ Reflect the results of the cost -of -service analysis. 'I'he cost to serve each customer class is different. The cost depends on the combination of demand needs, the timing.; and amount energy use compared to demand and the cost of customer lacilities and services. ■ Reflect the results of the unhundlin- of electric utility services. Table 4-1 Unbundled Electric Costs 4-'_ SAIC Fneruy. Environment & Infrastructure. LLC nIS3; Nvo4.docx 5 24 1-' Rate Class Unbundled Rate Res Sm Gen Sery Lge Gen Sery Large Indus Total Rate Component Wholesale Purch Pwr S883,069 5336.937 51.726,798 S2.062.770 55,009.574 Power Demand Purch Pwr 1.592,592 521.449 2.445.282 4.245.000 8,804.324 Energy Gen Demand 248.326 94,749 485.589 580.067 1,408.731 Gen Energy 340.057 111,342 522,127 906.411 1,879.937 Trans Demand 40,464 9,649 44.192 62.899 157.204 Energy Dist Demand 919.454 307.086 1,503,438 1.801.194 $4.531.173 Energy 387.423 126.851 594.853 1.032.662 2.141,788 Cust Customer 812.856 217.474 293.957 369.016 1.693.303 Total S5,224.240 S1,725.538 S7.616,237 511,060.019 525.626.034 4-'_ SAIC Fneruy. Environment & Infrastructure. LLC nIS3; Nvo4.docx 5 24 1-' UNBUNDLED RATES Gas Rate Components I Il1's `,as rates have been unbundled into lour components: purchased Leas ProduCtion. transmission, distribution and Customer. Each of these components is described beloxv. Purchased Gas/ Production The purchased gaa' procluCtion component represents the cost of' x%-holesale -as deli%-ered to the CitN- and certain production expenses. It is expressed as both a demand and cimunodin• component based on consumption. Transmission The transmission component represents transmission operations and maintenance charges. The transmission charge is a demand related charLge. it is expressed as a demand component based on Consumption. 81445 SAIC Energy, Environment & Inlirastrurture. LLC' 4-3 Table 4-2 Unbundled Electric Rates Rate Class Unbundled Rate Rate Component Res Small Large Large General General Industrial Service Service Purch Pwr Demand S7.39 S7.52 Wholesale Power (S/kW) Purch Pwr Energy (S/kWh) 0.0466 0.0494 0.0300 0.0300 Gen Demand (S/kW) 2.08 2.11 Gen Energy (S/kWh) 0.0111 0.0119 0.0064 0.0064 Transmission Demand (S/kW) 0.19 0.23 Energy (S/kWh) 0.0008 0.0006 Distribution Demand (S/kW) 6.44 6.57 Energy (S/kWh) 0.0246 0.0250 Customer Customer (S/mo) 11.13 22.26 195.97 10250.44 Total Customer (S/mo) $11.13 $22.26 $195.97 $10,250.44 Demand (S/kW) $16.10 $16.43 Energy (S/kWh) $0.0831 $0.0868 $0.0437 $0.0437 Existing Rate Customer ($/mo) $6.50 $10.00 Demand ($/kW) $6.00 $7.00 Energy ($/kWh)-blk 1 $0.0872 $0.0911 $0.0737 $0.0675 Energy ($/kWh)-blk 2 $0.0855 Gas Rate Components I Il1's `,as rates have been unbundled into lour components: purchased Leas ProduCtion. transmission, distribution and Customer. Each of these components is described beloxv. Purchased Gas/ Production The purchased gaa' procluCtion component represents the cost of' x%-holesale -as deli%-ered to the CitN- and certain production expenses. It is expressed as both a demand and cimunodin• component based on consumption. Transmission The transmission component represents transmission operations and maintenance charges. The transmission charge is a demand related charLge. it is expressed as a demand component based on Consumption. 81445 SAIC Energy, Environment & Inlirastrurture. LLC' 4-3 Section 4 Distribution The distribution portion of the unbundled rate represents O&M expenses on the distribution system, depreciation, certain A&Ci expenses, a credit liar 11011-0peratin" income plus retained earnings requirements. It is expressed as both a demand and con1111odity component based on consumption. Customer The customer char�,,e reflects both CLIst0111Cr service and customer facilities expenses, includinw accounting and collectin,, chai-es, sales. certain A&(; expenses, O&M and depreciation 011 the customer portion of' the system and a credit for non-operating income. Tile customer charge is a monthly per customer charge. Unbundled Gas Rates Linbundled natural uas casts an(1 resultino retail rates for the Residential. Commercial and Industrial rate classes are shown in the tables below. Casts associated with 3W and HTI have been eliminated 11.0111 the UnbUndlC(I analysis, due to the Iact that 3M and IITI have contract rates. The individual unbundled components have been Sunlnied to show I total unbundled rate. Note that the following rate are 1101 necessarily the proposed rates recoinniended by SAIL' as a result al' this study. The following unbundled rates: ■ Generate NVCnuC equal t0 the adjusted 2010 Test Year revenue requirements. ■ Reflect the results ol'the cost-ol-service analysis. The cost t0 serve each customer class is different. Tile cast depends on the anl0unt and timing of natural gas use an(I the cost 01'Custonler Facilities and services. ■ Reflect the results ol'the unbundling oCuaS utility SCI -Vices. Table 4-3 Unbundled Gas Costs Rate Class Unbundled Rate Residential Commercial Industrial Total Rate Component Purchase/ Demand S2.968 $2.464 S512 S5,944 Production Commodity 2.930.919 2.810.355 322.977 6.064,250 Transmission Demand 30.784 25.724 5.231 61.740 Demand 246.822 206.252 41.945 495.019 Distribution Commodity S101.109 S96.950 $11.142 $209.200 Customer Customer 707,383 381.207 19.087 1.107.678 Total $4.019,984 $3,522,953 S400.894 S7.943.830 4-4 STC' Energy, Fil ironment & lnfirastructure. 1.1.0 It1K4 S,-,14.,1„�r 5 24 12 UNBUNDLED RATES Table 4.4 Unbundled Gas Rates t+IN44; SAIC P.ncrn-. Environment & infrastrurturr. I.I.C' 4-5 Rate Class Unbundled Rate Rate Component Residential Commercial Industrial Purchase/ Demand (S/Mcf) $0.01 $0.01 S0.01 Production Commodity ($/Mcf) $7.02 S7.02 57.02 Transmission Demand (S/Mcf) S0.07 S0.06 $0.11 Distribution Demand ($/Mcf) $0.59 S0.52 S0.91 Commodity ($/Mcf) S0.24 S0.24 $0.24 Customer Customer (S/mo) S11.99 S60.51 $4.771.86 Total Customer ($Imo) $11.99 $60.51 $4,771.86 Commodity ($IMcf) $7.94 $7.85 $8.30 Existing Rate Customer ($/mo) $6.50 $31.50 Commodity ($/Mcf) $9.08 $9.08 $8.54 Demand per MCF $10.00 t+IN44; SAIC P.ncrn-. Environment & infrastrurturr. I.I.C' 4-5 Section 5 PROPOSED RATES Retail rate adjustments are generally made in response to revenue requirements and cost -of' service. In Section ? of this report, the Electric and Gas Divisions' estimated annual operating results liar the Study Period were presented. These two sets of operating results were developed utilizing IiU's existing rates. Section 3 of this report summarizes the results of' the cost of service analysis fir both Divisions. Section 4 presents all analysis of unbundled rates fir birth Divisions. All ol• these factors have been considered in the development of the recommendations presented below for Electric and Gas rates. Electric Division Rate Design Forecasted revenues at current rates are adequate to cover forecasted revenue requirements during the Study Period while maintaining reasonable cash reserves in the near term. The cost -of -service analysis has shown that current rates are generally in line \\•ith the cost to serve each of the rate classes. The unbundled rate analysis indicates that some ralcsign ofcurrcnt rate structures may he justified. We are not recommending any increase in Electric Division revellueti through a retail rate adjustment at this time. The only specific rate change we are recommending is in regard to the Small General Service classification. Presented below are the proposed rates and some recommendations fin• iilture rate considerations. Proposed Rates I . No change in Residential rates has been proposed. ?. The Small General Service class currently has a two-tier energy rate design. Customers pay one rate for all 111olltllll' energv up to 2000 MI and a sli�,,htly lower rate for all monthly energy over 2000 kWh. We have proposed moving this Class to a single energy charge for all monthly cncr�IIy usage. This change is revenue neutral for the class as a whole, however, smaller users will sec a slight decrease in their monthly bill and larger users Will see a sli,,ht increase in their monthly bill. 3. No change in Large General Service rates has been proposed. 4. No change in Large Industrial rates has been proposed. 111.1'4'; SAIC, Section 5 Table 5-1 Current And Proposed Retail Electric Rates Class Rate Component Current Rate Proposed Rate Residential Monthly Charge 6.50 No change All kWh/mo 0.0872 No change Small General Service Monthly Charge 10.00 No change First 2000 0.0911 n/a kWh/mo Over 2000 0.0855 n/a kWh/mo All kWh n/a 0.0886 Large General Service Demand per kW/mo 6.00 No change All kWh/mo 0.0737 No change Large Industrial Demand per 7.00 No change kW/mo All kWh/mo 0.0675 No change Power Cost Adjustment The Electric Division currently has in place a Power Cost Adjustment (PCA) to adjust for differences between its actual fuel and pUrchascd power casts and the cost included Ill the Customer ratC sChalulCs. The Electric DIVIS1011 uses the PCA as needed to adjust for fluctuations in its fuel and purchased power costs. We recotlllllend that the Electric Di\-ision Continue to monitor its PCA rates compared with its actual power supply related costs and Use the PCA as needed. General Rate Recommendations Presented below are sonic general rate reconlnlendatiotls for HU's consideration regarding its Electric Di\-ision rates. 1. As rate adjustments are made in the Future, consideration of higher customer charges Fur the ltesidcntial and Small C.icncral ScrVicc classes is justilicd. As shrnVn in the unbundled analysis in Section 4 of this report, the total unbundled Customer related cost lin• these classes is higher than the existing monthly customer charges Fur these classes. '_. The retail demand charges Fur the Large General Scr\-ice and large Industrial classes are tib and S7 per M -month resl)ecti\•el\•. Changes in HU's power supply program, while not raising costs rnerall. ha�•e nu►\-ecl costs ti•onl energy related to more fixed demand related costs. Total revenues from these classes are generally in line with cost-ol-ser\•ice. Flowex•er. when rate adjustments are made. it is warranted to consider increasing retail demand Char -es while decreasing retail enen,x chari-,cs for these two classes. 5-2 SAK' Energy. Fnvironment & Inh•astructure. 11C It11A4 PROPOSED RATES 3. As shown In Section 2 Of' this report, the Electric Division forecasted revenues during the Study Period are estimated to exceed revenue requirements. However. rash reserves are estimated to decline during the Study Period. This is primarily due to planned capital improvements. HU may wish tO giVr some consideration to bonding fir some of the capital improvements to spread the financial impact over more operating years. 4. HU has indicated it may be interested in dc\-cloping or participating in a local. dispatchable. green generatin" resource at same point in the future. If they Were to pursue this Option, they have indicated they may wish to consider an optional green rate for retail customers to choose to Support the local green generation endeavor. The concept Would be to have local customers pay same extra amount per kXVh to help pay capital and Operating casts for the new generation in excess of HLJ's standard power supply costa. For example. the estimated 2013 production O&M and other power supply expenses for HU were $18,689.963 as shown in Section 2 of this report. Total estimated retail sales for 2013 are 324,899,0111 kWh. Average power supply costs per retail k\Vh in 2013 are estimated to be S0.0575 per kWh. If the cost of a local green resource exceeded this amount per kWh. HU could implement an Optional green rate \\-here customers pay an additional anwunt equal to the differential between HU's normal power supply costs and the ne\\' green resource. This amount could be applied to fixed amounts of energy that customers Could subscribe to. For instance, It' the green resource cost 50.02 per kWh more than the current resources. a Customer COuld agree to pay, S2 per month extra for a 100 k\Vh block of the ne\%• resource. HU could market monthly blocks of the neR' resourCe up to the expected monthly output of the unit. Estimated Operating Results at Proposed Rates The Only rate adjuStmCnt for the Electric Division recommended is in the Small General Service classification. This change is designed to he revenue neutral. As Such, the estimated Electric Division operating results and cash reserves tier the Study Period incorporating the proposed rates are unchanged from the results at existing rates as presented in Section 2 ofthis Report Rate Comparisons Exhibit 5-A graphically shows the effect of the proposed rates on the Electric Division's monthly hills for the Small General Service customer class based on a ranee of monthly Consumption. Month1v bills for customers with l0\V usage are slightly less and ninthly bills for customers with hi,,h usage are slightly higher. Gas Division Rate Design As stated in Section 2. lorecasted revenues at existing rates are expected to be sufficient to adequately comer forecasted reVenuC requirements during the Study Period. Additionally. Cash reserves for the Gas Division are estimated to increase 11184; SAIC Enerp% Ynvironment S Intl'a5lRiCtUre. LLC 5-3 Section 5 during" the study period. No changes are currently recommended fir the Gas Division's retail rates. Fuel Cost Adjustment The Cias Division currently has in place a Fuel Cost Adjustment (FCA) to adiust for differences between its natural gas purchases iimr retail customers and the cost included III the customer rate schedules. XVc recommend that the Gas Division continue to monitor its FCA rates compared with its actual natural gas costs anis use the FCA as needed. General Rate Recommendations Presented below are some general rate recommendations l'or HU's consideration regarding, ifs (ias Uig inion rates. 1. As rate adjustments are made in the future. consideration of higher customer charges fur the Residential and Commercial classes is justilied. As shown in the unbundled analysis in Section 4 of this report. the total unbundled customer related cost for these classes is hi,her than the existing monthly customer char�_es lOr these classes. 5-4 SAIC Energy. l:miroil ment & InFr8SlrLICtUre. LLC 111\41 $1,000 ctann $800 $700 $600 Monthly Bill $500 $400 $300 $200 $100 $O . ... . ............. 0 ............... .. ...... . . .... . .. .. ......... ..... .... ... . .... ..... . .. . .. .............. ... . .. . .. ... . 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 Monthly kWh -—Current Rate —Proposed Rate ....... . . . . . .. . . .......... . . .......... . . ..... ANALYSIS OF RESIDENTIAL CUSTOMER CHARGES Zoi7 Q4 Customer �[ Charge .r,q q - Madison, SD $ 20.90 Marshall $ 20.00 Hillsboro $ 16.00 Riverdale $ 16.00 Harlan $ 15.86 Valley City $ 15.57 6.75 Luverne $ 15.00 Northwood $ 15.00 Lake View $ 15.00 Rochester $ 14.90 Ortonville $ 14.41 Burke $ 14.00 Adrian $ 14.00 Hawarden $ 13.65 Barnesville $ 13.50 Beresford S 13.35 7S - Brainerd S 13.25 Brookings $ 13.25 Lake Park, IA $ 13.00 Primghar $ 13.00 Shelby $ 13.00 It St. Peter $ 12.95 /Y oo Detroit Lakes $ 12.50 Winner $ 12.30 Staples $ 12.00 Paullina $ 12.00 Lake Park. MN $ 12.00 Breckenridge $ 12.00 Lakota $ 12.00 Faith $ 11.60 Cavalier $ 11.50 Flandreau $ 11.44 Sibley $ 11.30 Spencer $ 11.25 Milford $ 11.17 //0,- St. James $ 11.00 Elbow Lake $ 11.00 Westbrook $ 11.00 Rock Rapids $ 11.00 Springfield $ 11.00 Alton $ 11.00 Sanborn $ 11.00 Kimballton $ 11.00 Y/3 l oo- Austin $ 11.00 s�y� &10 , Moorhead $ 10.70 Pickstown $ 1ON- .7040 6 0- Worthington $ 10.50 f/0.3.5" "Willmar $ 10.35 Kasson $ 10.03 Benson $ 10.00 Melrose Watertown $ Customer Granite Falls $ Cha e - Elk River $ 10.00 Manilla $ 10.00 Pierre $ 10.00 Alexandria $ 10.00 Jackson $ 10.00 Melrose Watertown $ 10.00 Granite Falls $ 9.50 Hartley $ 9.50 Blue Earth $ 9.00 Fairfax $ 9.00 Ft. Pierre $ 9.00 - Glencoe $ 9.00 - New Ulm $ 9.00 Pella $ 9.00 Sioux Center $ 9.00 Truman $ 9.00 Vermillion $ 9.00 Wadena $ 9.00 Sauk Centre $ 9.00 - Litchfield $ 8.83 Denison $ 8.50 Atlantic $ 8.45 Remsen $ 8.40 8.00 8.00 8.00 8.00 8.00 6.25 6.00 5.42 5.25 MRES Member Avg. $ 11.40 Median - All $ 10.43 Avera e - All $ 10.62 ZcW7 A?,�, I& -S 3." 13.40 q . s•fl V. $3 o� Q•9.00(•• 5, 1.40 -- S-39 vp 8'- 75 East Grand Forks $ 7.75 Hdtc^hinson $ :6.50 Mountain Lake $ 5.00 6.25 6.00 5.42 5.25 MRES Member Avg. $ 11.40 Median - All $ 10.43 Avera e - All $ 10.62 ZcW7 A?,�, I& -S 3." 13.40 q . s•fl V. $3 o� Q•9.00(•• 5, 1.40 -- S-39 vp 8'- 75 REQUEST FOR PROPOSAL COST OF SERVICE AND RATE DESIGN STUDY Hutchinson Utilities Commission Hutchinson, MN Hutchinson Utilities Commission 225 Michi-an Street SE Hutchinson. MN 55350-1905 TABLE OF CONTENTS PROJECTSUMMARY................................................................................................2 PROJECT BACKGROUND.........................................................................................2 SCOPEOF WORK.....................................................................................................3 COST OF SERVICE STUDY......................................................................................3 RATE DESIGN STUDY.............................................................................................4 PROJECTTIMELINE.................................................................................................6 CONSULTANT SELECTION PROCESS......................................................................7 STATEMENTS OF QUALIFICATIONS.......................................................................7 SUBMITTAL INSTRUCTIONS AND DEADLINE........................................................9 SELECTION CRITERIA.............................................................................................9 PROPOSER'S COSTS...............................................................................................9 INQUIRIES.............................................................................................................10 KEYPERSONNEL....................................................................................................10 APPENDIX A: 2017 RATE SCHEDULE..................................................................11 1 PROJECT SUMMARY The Hutchinson Utilities Commission (HUC) is soliciting a Request for Proposals from consulting firms to conduct a Cost of Service and Rate Study for the Electric Utilities and Gas Utilities. Firms should quote the Electric and Gas study separately. If a single firm can provide both Utility study's a combined cost should also be provided. This Request for Proposal will consider the following: • Existing electric and gas rates • Existing operations and maintenance costs • Existing bond debt service costs • Existing depreciation costs and calculations • Reviewing and evaluating future 0&M costs • Current and future Capital Improvement Plans • Reviewing future bonding costs • Recommending alternative rate structures to fund necessary expenditures • Functionalization of costs into unbundled cost categories • Provide comparison of rates to like communities • Timeline for potential rate implementation PROJECT BACKGROUND The Electric and Gas cost of service study followed with a rate study analysis will consist of a comprehensive evaluation of the current operation and maintenance costs, capital improvement costs, existing debt service costs, depreciation as well as future 0&M, and future capital and debt service costs for the Utility. It will evaluate the existing rates and rate structures by customer class and propose the addition or modification of fees to gain full cost recovery for services and establish fair and equitable rates to ensure revenue sufficiency, stability, and sustainability. It will also review customer classifications and make any recommendations for redefining customer classifications or modifying the rates or rate structures between the Electric and Gas Divisions. The goal of the study is to provide for a rate structure to meet the financial requirements of the Utility while maintaining competitive rates for our residential, commercial, and industrial customer classes. At the end of 2016, the Utility had 7,030 electric customers and 5,543 gas customers. The most recent Electric & Gas study was completed in 2012 based on 2010 test data. 2 SCOPE OF WORK The Hutchinson Utilities Commission currently relies on load forecast to develop HUC's forecast of sales and revenue. The Cost of Service and Rate Study analysis will serve as a guide for the Hutchinson Utilities Commission (HUC) in establishing adequate cash flow and reserves to fund the Electric and Gas Divisions over the next five years. The selected firm(s) will be asked to work closely with HUC staff to complete the following general categories of tasks. It is expected that the results of the Cost of Service/Rate Study will form the basis of a potential on-going rate structure plan for the Electric and Gas Divisions. COST OF SERVICE STUDY HUC desires to ensure, to the extent practical, recovery from each customer the cost of providing service to that customer. The cost of service includes recovery of all operating costs and amounts necessary to maintain reasonable operating reserves after funding operations, debt service, and capital projects. Furthermore, HUC desires to ensure that customer classifications are appropriate. The cost of service study will define and separate fixed and variable costs. The study should identify costs to be allocated across all customer classes and those costs that are specific to a class. In determining actual cost of providing electric and gas service to each customer class, traditional cost of service and rate setting principles and approaches should be employed such that HUC can ensure that class rate requirements are equitable. Planning Criteria (Tasks): a. Review financial history, including revenues and expenses, depreciation, and current rate and fee structure b. Review proposed five year capital improvement plan and total projected project costs c. Develop requisite Revenue Requirement analysis of test period system revenue and expenses as the foundation of the cost of service class analysis d. Identify annual and peak requirements and usage by customer class e. Identify current electric and gas load and project future loads based on anticipated changes in the community f. Examine customer database and review current customer classifications g. Identify largest users and determine if users are being charged under the appropriate rate schedule h. Review current transmission delivery and gas and electric charges i. Review current fixed and variable energy and demand charges 3 j. Review the existing and future debt service requirements to determine the level of cash flow needed to meet all current and future bonding requirements k. If applicable, review and recommend adjustments to the power cost adjustment (pca) or fuel cost adjustment (fca) factor(s) Reporting: The consultant is to present the findings and conclusions of each task and resulting recommendations in the cost of service final report in a clear and concise manner. A written report is required and periodic presentation to management. A summary presentation to the Board of Commissioners will be requested during a scheduled meeting or workshop. RATE DESIGN STUDY HUC seeks to ensure utility rate(s) cover the true cost of providing electrical and gas service to customers. This includes but is not limited to: commodity and transmission purchases, 0 & M and equipment repair and replacement costs; maintaining appropriate working capital and cash balances as well as meeting debt service requirements, and capital improvement needs. In doing so, the proposed rate/fee structure shall ensure an equitable treatment of all charges on the current and future users. Rate Design Investigation: Utility rate modeling, and associated long-range forecasting of revenue and expenses, necessitates careful scrutiny of available data upon which a study is predicated so that the model can be implemented with confidence and with reasonable certainty of fairness and equity. Evaluation of accepted policies, practices and procedures to ensure model reliability, predictability and rate stability over the long term is essential for model usefulness. Accordingly, the Consultant shall meet with HUC staff to review and discuss available documentation including, but not limited to, Utility Billing records, historical budget documents and audit reports, resolutions, policies, operation and maintenance practices. Evaluation: Specifically, the Consultant shall review, analyze, validate the reasonableness, and recommend changes where appropriate for the following: • Methodologies of fee structure, rates and charges • Utility Repair/Replacement Funding Methodology, considering long-term capital improvement needs, debt service opportunities and associated funding sources/levels Rate Design Study to Include: a. Analyze and discuss impact of existing and future capital improvements b. Assess revenue needs for the next five year planning period (2018-2022), to include adequate coverage for operations and maintenance, capital projects and program activities and debt service 5! c. Analyze existing rate and fee structure and recommend alternatives based on findings d. Examine current user classes and current rate approaches e. Consultant will advise HUC on industry -accepted methodologies for allocating costs to various customer classes and provide a breakdown of these expenses and show how they relate to providing electric and gas services f. Evaluate existing rate structure with regard to changing patterns of consumption, changes in customer base, annual revenue from rates, price elasticity of consumption, demands on rate revenue (from Cost of Service Study) and the effects of conservation on annual revenues and future power resource needs g. Evaluate current Natural Gas transportation rates across HUC's transmission and distribution system for appropriate cost recovery and make recommendations for modifications, if appropriate h. Examine adequacy of reserves for operating revenues and capital projects to determine sufficient levels to offset low consumption/revenue years while also reducing spikes in annual rate increases i. Examine HUC's use of Debt financing for capital improvements and make recommendations related to its uses and limitations relative to maintaining a proper balance for debt coverage and rate stabilization over this 5 year period j. Consultant shall review and if applicable propose rate schedules on the basic premise that each customer should be classified and served under a schedule that will cover all costs of that customer's service plus return a reasonable margin for proper operating reserves, capital improvements, debt service coverage, adequate inventories, and contributions to general city government. New rate schedules must classify each customer into the fewest possible reasonable classifications. k. For proposed rate schedules, Consultant shall provide sampling of a minimum of three (3) customers per classification showing the difference of charges between existing and proposed rates. The Consultant shall show a sampling of data for one calendar year by month for each customer. I. Consultant shall provide a comparison of current and alternative HUC rates to similar size communities m. Any preferences in long-term versus short-term rate benefits Reporting: The Consultant is to present the findings and conclusions of the tasks in the rate study final report in a clear and concise manner. The report should include: • detailed recommendations for changes, if any, to current practices and/or procedures • a schedule for timely and coordinated execution of all essential aspects of the report • a written report supporting the recommendations is required and presentation to management 5 • a summary presentation to the Board of Commissioners will be requested during a scheduled meeting or workshop • material to support HUC rate hearings Deliverables The Consultant shall prepare a draft technical document for HUC to review summarizing study process, explaining methodologies used, final results, and recommendations. After draft review by Utility staff, the Consultant will submit the final technical document to staff and present to the Commission. The Consultant shall provide an editable excel worksheet file to assist Hutchinson Utilities in determining future rate adjustments. The Consultant either via attendance or conference call will attend one kickoff meeting and at least one interim meeting with staff to discuss the data collection requirements and preliminary rate structure. The Consultant will present the final rate structure at one Commission meeting. If requested, the Consultant shall be prepared to assist HUC in implementing any new or revised rate schedules, to include attendance at several anticipated rate hearings. PROJECT TIMELINE Development of the Electric & Gas Cost of Service and Rate Study is intended to begin shortly after the consulting firm(s) is selected. It is anticipated that the assessment will proceed through the summer and conclude by fall of 2017. Anticipated Consultant Selection Schedule: Distribute Request for Proposal April 3rd, 2017 Request for Proposal Response Due May 1st, 2017 Proposal Awarded by HUC May 17th, 2017 Start of Cost of Service & Rate Study June 5th, 2017 Initial Kick Off meeting for data collection June 5th _ 9th, 2017 Completion of Study and Staff Review October 6th, 2017 Final Report Submitted October 16th, 2017 Board Presentation October 25th, 2017 CONSULTANT SELECTION PROCESS The Hutchinson Utilities Commission has established a sub -committee of utility management staff and commissioners that will be involved throughout the entire selection process. HUC shall be the sole and exclusive judge of quality and compliance with Proposal specifications in any of the matters pertaining to this RFP. HUC reserves the right to award the contract in any manner it deems to be in the best interest of the Utilities. All Proposal information will be evaluated according to the criteria listed herein, and the firm(s) selected will be chosen on their apparent ability to best meet the overall expectations of the Hutchinson Utilities Commission. By submitting an RFP submission and participating in the process as outlined in this document, Respondents expressly agree that no contract of any kind is formed under, or arises from, this RFP and that no legal obligations will arise. HUC will have no obligation to enter into negotiations, or to contract, with a Respondent, even though one or all of the Respondents are determined to be responsible and qualified, and the proposals are determined to be responsive. If HUC proceeds to request a more detailed Proposal from Respondents, who are determined to be qualified under the RFP process, HUC will have no obligation to award a Contract where: (a) One submission is received; or (b) In the judgement of HUC, the interests of HUC would best be served by not entering into a Contract. Once a contract has been approved by the Hutchinson Utilities Commission, an authorization to proceed will be issued for the project. No work may begin until an authorization to proceed has been issued. Note that all materials received by Hutchinson Utilities Commission become "public records" and will be made available for review to any person upon request. STATEMENT OF QUALIFICATIONS CONTENTS The Statement of Qualifications (SOQs) will form the basis of selecting the firms that will be reviewed by the sub -committee. The Statement of Qualifications should include the following components. When submitting their SOQ, firms are asked to provide the materials in the order listed below. SUBMITTING FIRMS ARE RESPONSIBLE FOR REVIEWING AND UNDERSTANDING THE REQUIREMENTS OF THIS SOLICITATION. Careful attention must be given to ensure that all requested items contained in this RFP are included in the submittal and sections comply with applicable page limits. 7 1. Cover Letter. A cover letter is required, stating the firm's interest in being considered specifically for either the Electric or Gas project or a combined project of both utilities. The letter should clearly identify the main point of contact for the submitting firm, address, telephone number, fax number, and email address 2. General Profile. A one-page general profile of the firm is required. The profile should describe the general nature of services provided by the firm, the location of main and branch offices and the number of years the firm has provided services similar to those requested by this RFP. Any sub -consultants or partnering firms which are proposed to be a part of the project team must be identified. 3. Key Personnel. A one-page summary is required that includes the names of the key personnel to be involved in preparing the Cost of Service/Rate Study, along with a brief summary of their areas of expertise and their intended role in the project. (Resumes may be appended to the submittal but cannot substitute for the required summary page.) Please indicate those persons possessing the licenses and certifications necessary to perform the type of work being requested. 4. References. A listing of three to five references, including contact names and telephone numbers for projects of similar size and scope performed by the key personnel listed above. In addition, provide a current client list including jurisdiction name, contact name and telephone number, and length of engagement. Ideally, this list will include public utility electric & gas operations and will include projects that involved an evaluation of existing rates, capital plans, debt service coverage, long range capital funding, O&M cost review and evaluation, and equitable cost of service cost allocations. Particular emphasis should be placed on innovative, cost effective rate making solutions. 5. Multiple Firms. For Statements of Qualifications that involve multiple firms submitting as a single project team, provide a maximum two-page summary of the roles each firm will play and the project management approach that will be used to provide seamless delivery of the end product. 6. Estimate of Resources. Based on the firm's understanding of the scope of work required, provide a maximum two-page preliminary estimate of the firm's resources that could be dedicated to the project. This can be in a form of the firm's choosing but should clearly convey a sense of the amount of effort and resources the firm believes will be required for the data assessment phase of the project. A statement of availability should also be included that confirms that these resources can be committed to allow the work to progress within the Project Timeline described earlier. If a different timeline is needed, please specify. Submitting a fee nronosai is required at this sten. 0