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12-12-2005 HUCM Special Meeting December 12, 2005 Members present: President Craig Lenz; Vice President Donald Walser; Secretary David Wetterling; Commissioner Paul Ackland; Commissioner Steven Cook; General Manager Michael Kumm; Attorney Marc Sebora. President Lenz called the meeting to order at 3: 1 0 pm. Vice President Walser made a motion to close the meeting to discuss condemnation proceedings. Commissioner Ackland seconded the motion and it passed unanimously. The meeting was closed at 3:12 pm. Commissioner Cook made a motion to move from closed meeting back to open meeting. Secretary Wetterling seconded the motion and it passed unanimously. The meeting was reopened at 4:19 pm. President Lenz offered to table the discussion on 2006 budget, in light of the time it took to discuss the condemnation proceedings. Secretary Wetterling made a motion to table the discussion on 2006 budget. Commissioner Ackland seconded the motion and it passed unanimously. President Lenz announced there was no formal award regarding the condemnation hearings. There is nothing to report at this time. Dave Berg from R W Beck was welcomed to the meeting to discuss the cost of service study. Preliminary results have been presented to the board at the November meeting. This presentation is the final recommendation: . Develop Projected Operating Results at Existing Rates This is the most critical aspect. We need to bring in enough revenue to pay our bills. . Analyze Cost-of-Service If increase for a given class is necessary, the increase should represent the cost to service that class. . Unbundle Cost Categories Within each given class, how much should come from energy charge and how much should come from customer charge. Customer charge relates to all charges associated with that class, ie: number of fixed charges, the meter itself, the reading of the meters, etc. . Design New Rates Manager Kumm mentioned that the last electric increase was in 1988, and the last gas increase was in 1995. R W Beck's recommendation - electric Increase electric rate: . 9.0% residential . 6.5% small general service (smaller stores, convenience stores, etc.) . 8.1 large general service (Menards, hospital, Hutch Mfg., etc.) . 8.2 large industrial (3M and HTI) Redesign rates Redesign power cost adjustment . Simplify it . Collect more on base rate . Collect less on PCA Residential: . Monthly charge . All KWH/mo $6.50 $0.0872 Small General Service: Eliminate seasonal rates . Monthly charge . first 2000 KWH/mo . over 2000 KWH/mo $10 $0.0911 $0.0855 Large General Service . Demand per KWH/mo . All KWH/mo $6 $0.0737 Large Industrial . Demand per kva . All KWH/mo $7 $0.0675 R W Beck's recommendation - gas No overall rate increase for gas Redesign residential rates . Monthly charge . All MCF/mo $6.50 $9.08 Redesign commercial rates . Monthly charge . All MCF/mo $31 .50 $9.08 Lower large industrial rate 5% (HTI) . Demand per MCF $10 . All MCF/mo $8.54 Renegotiate expired 3M contract . 3M will pay their fair share Redesign fuel cost adjustment . We will zero it out . Collect more on base rate and not from fuel cost adjustment Because of the base load electric contract with Utilities Plus, 82% of the electric divisions energy needs are met. This contract has saved the electric customers of HUC millions of dollars in energy costs since June 2005. In addition, 62% of the base load for the natural gas division has been procured through various contracts. The blended contract price for this gas is $7.51, this compares to a daily market that was over $15 last week. The natural gas has been purchased through a model that was developed in September 2004, and implemented in October 2004. This purchasing model has save our community millions of dollars. Also, the natural gas transmission pipeline has saved our community millions of dollars in 2005, and will continue to do so. Other communities will continue to see increases in transportation costs from Northern Natural Gas; however, due to the pipeline, HUC's transportation costs are fixed. The pipeline has also helped out the communities of New Ulm and Fairfax. Commissioner Cook mentioned the Big Stone 2 Project, and the projected benefits to our community. Additional recommendations from R W Beck: . Establish operating reserve fund . Formulize transfer to City of Hutchinson o percent of plant in service · this is constant - grows with the City o fixed amount per unit (KHW or MCF) · this fluctuates more than in plant service Commissioner Walser read the ruling from the City Charter on the process for a rate change. It reads in part: Change made: added 'from the City Charter'. See 12-28-05 minutes Powers of the Commission: It shall regulate the distribution, use and sale of electricity and gas within and without the city limits, collect for services, and shall fix the rates for all such sales and services for public and private use, subject to right of the council to veto any proposed charge and rate by a four-fifths majority vote. Such veto power shall be exercised, if at all, within 30 days after the council has received notice of any proposed change in charge and rate. Commissioner Ackland commented on the fact that a proposed $6.50 monthly charge for customers who close up their homes and go south for the winter will experience a 100% increase in their bill. The overall assumption in the proposal is based on the fact that people are here all year round. This would be a one-time proposed rate with formal studies being done every five years, and less formal studies done every year. President Lenz asked if there was a recommendation to act on. Commissioner Cook made a motion to approve the rate adjustment for electric and gas after the authorization/development of a rate stabilization fund for the power cost and fuel cost adjustment clauses, and with favorable recommendation from City Council Vice President Walser seconded the motion but asked for an explanation of the stabilization fund. Manager Kumm explained that the stabilization will look at the base rate and will be used to control the swing of the power and fuel costs. The fund would counter these swings so as not to expose our customers to these costs. The adjustment clauses would be confined within a certain range. When the extreme happens, we could clip it and the difference would come out of the fund. We would also establish a cap on that fund balance. Manager Kumm will come back to the Board and present the development of the stabilization fund at the December 28 Commission meeting. Motion carried unanimously. President Lenz called for a closed meeting to discuss condemnation proceedings at the December 28 Commission meeting starting at 3:00 pm. Secretary Wetterling made a motion for a closed meeting on December 28, 2005 starting at 3:00 pm. Vice President Walser seconded the motion and it passed unanimously. Secretary Wetterling made a motion to adjourn the meeting at 6:25 pm. Commissioner Cook seconded the motion and it passed unanimously. David Wetterling, Secretary ATTEST: Craig Lenz, President 37 Special Meeting December 12, 2005 Members present: President Craig Lenz; Vice President Donald Walser; Secretary David Wetterling; Commissioner Paul Ackland; Commissioner Steven Cook; General Manager Michael Kumm; Attorney Marc Sebora. President Lenz called the meeting to order at 3:10 pm. Vice President Walser made a motion to close the meeting to discuss condemnation proceedings. Commissioner Ackland seconded the motion and it passed unanimously. The meeting was closed at 3:12 pm. Commissioner Cook made a motion to move from closed meeting back to open meeting. Secretary Wetterling seconded the motion and it passed unanimously. The meeting was reopened at 4:19 pm. President Lenz offered to table the discussion on 2006 budget, in light of the time it took to discuss the condemnation proceedings. Secretary Wetterling made a motion to table the discussion on 2006 budget. Commissioner Ackland seconded the motion and it passed unanimously. President Lenz announced there was no formal award regarding the condemnation hearings. There is nothing to report at this time. Dave Berg from R W Beck was welcomed to the meeting to discuss the cost of service study. Preliminary results have been presented to the board at the November meeting. This presentation is the final recommendation: • Develop Projected Operating Results at Existing Rates This is the most critical aspect. We need to bring in enough revenue to pay our bills. • Analyze Cost -of- Service If increase for a given class is necessary, the increase should represent the cost to service that class. • Unbundle Cost Categories Within each given class, how much should come from energy charge and how much should come from customer charge. Customer charge relates to all charges associated with that class, ie: number of fixed charges, the meter itself, the reading of the meters, etc. • Design New Rates 56 Manager Kumm mentioned that the last electric increase was in 1988, and the last gas increase was in 1995. R W Beck's recommendation - electric Increase electric rate: • 9.0% residential • 6.5% small general service (smaller stores, convenience stores, etc.) • 8.1 large general service (Menards, hospital, Hutch Mfg., etc.) • 8.2 large industrial (3M and HTI) Redesign rates Redesign power cost adjustment • Simplify it • Collect more on base rate • Collect less on PCA Residential: • Monthly charge $6.50 • All KWH /mo $0.0872 Small General Service: Eliminate seasonal rates • Monthly charge $10 • first 2000 KWH /mo $0.0911 • over 2000 KWH /mo $0.0855 Large General Service • Demand per KWH /mo $6 • All KWH /mo $0.0737 Large Industrial • Demand per kva $7 • All KWH /mo $0.0675 R W Beck's recommendation - gas No overall rate increase for gas Redesign residential rates • Monthly charge $6.50 • All MCF /mo $9.08 39' Redesign commercial rates • Monthly charge $31.50 • All MCF /mo $9.08 Lower large industrial rate 5% (HTI) • Demand per MCF $10 • All MCF /mo $8.54 Renegotiate expired 3M contract • 3M will pay their fair share Redesign fuel cost adjustment • We will zero it out • Collect more on base rate and not from fuel cost adjustment Because of the base load electric contract with Utilities Plus, 82% of the electric divisions energy needs are met. This contract has saved the electric customers of HUC millions of dollars in energy costs since June 2005. In addition, 62% of the base load for the natural gas division has been procured through various contracts. The blended contract price for this gas is $7.51, this compares to a daily market that was over $15 last week. The natural gas has been purchased through a model that was developed in September 2004, and implemented in October 2004. This purchasing model has save our community millions of dollars. Also, the natural gas transmission pipeline has saved our community millions of dollars in 2005, and will continue to do so. Other communities will continue to see increases in transportation costs from Northern Natural Gas; however, due to the pipeline, HUC's transportation costs are fixed. The pipeline has also helped out the communities of New Ulm and Fairfax. Commissioner Cook mentioned the Big Stone 2 Project, and the projected benefits to our community. Additional recommendations from R W Beck: • Establish operating reserve fund • Formulize transfer to City of Hutchinson • percent of plant in service ■ this is constant — grows with the City • fixed amount per unit (KHW or MCF) ■ this fluctuates more than in plant service Commissioner Walser read the rulina on the process for a rate change. It reads in part: Powers of the Commission: Change made added: from the City Charter See 12 -28 -05 minutes It shall regulate the distribution, use and sale of electricity and gas within and without the city limits, collect for services, and shall fix the rates for all such sales and services for public and private use, subject to right of the council to veto any proposed charge and rate by a four -fifths majority vote. Such veto power shall be exercised, if at all, within 30 days after the council has received notice of any proposed change in charge and rate. Commissioner Ackland commented on the fact that a proposed $6.50 monthly charge for customers who close up their homes and go south for the winter will experience a 100% increase in their bill. The overall assumption in the proposal is based on the fact that people are here all year round. This would be a one -time proposed rate with formal studies being done every five years, and less formal studies done every year. President Lenz asked if there was a recommendation to act on. Commissioner Cook made a motion to approve the rate adjustment for electric and gas after the authorization /development of a rate stabilization fund for the power cost and fuel cost adjustment clauses, and with favorable recommendation from City Council Vice President Walser seconded the motion but asked for an explanation of the stabilization fund. Manager Kumm explained that the stabilization will look at the base rate and will be used to control the swing of the power and fuel costs. The fund would counter these swings so as not to expose our customers to these costs. The adjustment clauses would be confined within a certain range. When the extreme happens, we could clip it and the difference would come out of the fund. We would also establish a cap on that fund balance. Manager Kumm will come back to the Board and present the development of the stabilization fund at the December 28 Commission meeting. Motion carried unanimously. President Lenz called for a closed meeting to discuss condemnation proceedings at the December 28 Commission meeting starting at 3:00 pm. Secretary Wetterling made a motion for a closed meeting on December 28, 2005 starting at 3:00 pm. Vice President Walser seconded the motion and it passed unanimously. Secretary Wetterling made a motion to adjourn the meeting at 6:25 pm. Commissioner Cook seconded the motion and it passed unanimously. avid We rlin , Secretary U t R V Y Y 3 CL - ■ �..�. 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(D M o �o s , i�t C � � O 0 m Q. fu �o o v, o o o CA ON 0 a 0 0 �S G CID O to ? +) O m n N O (p N F =. (D M o �o s , i�t O N � C � N a y E � U � � m � y m s O V � 3 2 O O O O O O O O O O O O 00 00 110 1- N 69 N - - 69 69 69 69 69 69 69 69 69 69 ($) ll!u xlgluow L- n M .-r b a� 0 Cs. O ja ~ L T U a k a fl u r- W) M 1 1 i� Monthly Bill($) b9 69 b9 69 ~ `�• `� N 69 N -4 ON 00 O N C� 00 O O O O O O O O O O C) O O O O O O O O O O O ±s; ujO O ty is D is O 3 o if n O C r n — n N -n .- N ' O O w 0 � 0 o s r 0 I I I December 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 determine 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. Vf I BECK, David'A. Berg, Principal and S4 01- 00293- IOIOMIOI 1070254 ( 004712 1 Hutchinson \Gas & Elec Rate Study\Repott\Electric rptltr 1380 Corporate Center Curve, Suite 305 St. Paul, MN 55121 Phone (651) 994 -8415 Fax(651)994-8396 0) ' Hutchinson Utilities Final Report Table of Contents Table of Contents List of Tables List of Figures Section1 Introduction ....................................................... ............................... ..l -1 Section 2 Estimated Operating Results — Existing Rates ...................................... 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 Debt Service ii Revenue Requirements ................................. ............................... 2 -6 Estimated Revenues — Existing Rates .......................... ............................2 -6 Estimated Operating Results ....................................... ............................2 -6 GasDivision ...................... ................................................................................. 2 -8 Estimated Gas Requirements ....................................... ............................2 -8 j Estimated Revenue Requirements ............................... ............................2 -8 jPurchased Gas Expenses .................................. ............................2 -8 Operating Expenses .......................................... ............................2 -9 Contributions to the City ...................................... ........................ 2 -9 Other Income and Expenses ....................................................... 2 -1 0 Capital Improvements ...................................... ...........................2 -10 Debt Service Revenue Requirements .................................... ...........................2 -10 Estimated Revenues — Existing Rates .............................. ...................... 2 -10 Estimated Operating Results ..................................... ............................2 -1 l Gas and Electric Combined Cash Reserves ................ :.............. ..................... 2 -1 l B1600 Table of Contents Section 3 Cost -of- Service Study .............................. Electric Division ................. ............................... Classification of Costs .............................. Allocation to Customer Classifications.... Demand Allocations ..................... Energy Allocations ....................... Customer Allocations ................... Revenue Allocations ..................... Cost -of- Service Study Results ................. GasDivision ........................ ............................... Classification of Costs .............................. Allocation to Customer Classifications...., Demand Allocations ...................... Commodity AIlocations ............... Customer Allocations .................... Revenue Al locations ...................... Cost -of- Service Study Results .................. ................. ............................... 3 -1 ................. ............................... 3 -1 ..... ........... ............................3 -1 ................. ............................... 3 -2 ........................ _ ....................3 -2 ................. ............................... 3 -3 ................................................ 3 -3 ................................................ 3 -3 ................................................ 3 -3 ................ ............................... 3 -5 ................ ............................... 3 -5 ............................................... 3 -6 ................ ............................... 3 -6 ................... ............................3 -7 ................ ............................... 3 -7 ................ ............................... 3 -7 ................ ............................... 3 -7 Section4 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 Contribution to the City ................................................ ............................4 -5 UnbundledGas Rates .............................. ................................................. 4 -5 Section 5 Proposed Rates ............................... Electric Division Rate Design ................................................ ............................5 -1 ProposedRates ............................................................ ............................5 -1 Power Cost 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 Proposed Rates ..:... ............................... -7 ..... ............................... ...............5 FuelCost Adjustment .................................................. ............................5 -7 Rate Comparison with Xcel Energy ............................. .........................:..5 -9 HU Gas Service Contract with 3M ............................... ............................5 -9 Additional Recommendations ..................................... ..........:................5 -10 H Bi600 Table of Contents Estimated Operating Results at Proposed Rates .......... ...........................5 -10 Gas and Electric Combined Cash Reserves ..................................................... 5 -10 Rate Comparisons ............ ............................... .............. 5 -11 .... ............................... Transfers to 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 ( MWh ) .............................. ..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 -g Estimated Wholesale Gas Commodity Rates Per MMBtu .............. ............................2 -9 Estimated Wholesale Gas Expense .................... 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 f of Service: 2004 Test Year Classification of Gas Division Costs: 2004 Test Year ............................................... ................ 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 UnbundledElectric Costs ................................ ............................... ............ .................4 -3 Unbundled Electric Rates ................................. ............................... .......4 -4 .................... UnbundledGas Costs ..................................... ............................... ............. ..................4 -6 UnbundledGas Rates ...................................................................... ............................4 -7 B1600 Ill Table of Contents Section 5 Current and Proposed Retail Electric Rates ................................ ............................... 5 -2 Street Lights Cost Analysis .......................................................... ............................... 5 -4 Average Monthly Bill Comparison ................................................. ............................5 -5 Electric Division:Estimated Annual Operating Results Proposed Rates ....... .............. 5 -6 Current and Proposed Retail Gas Rates ....................................... ............................... 5 -9 Average Monthly Bill Comparison ................................................. ............................5 -9 Gas Division: Estimated Annual Operating Results Proposed Rates ........................ 5 -10 Estimated Combined Cash Reservces Proposed Rates ................... ...........................5 -11 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 Test 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 -H: Demand Cost Allocation by Average- Excess Demand Exhibit 3 -I: 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 iv B1600 a � Q w w "f A 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. _ B1600 Copyright 2005 R. W. Beck, Inc. All rights reserved. v M Section 1 INTRODUCTION The City of Hutchinson, Minnesota through Hutchinson Utilities (HU), 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 y ` 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. R. W. Beck has performed a cost -of- service and rate design study for HU's Electric and Gas Divisions. The study included 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 our 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. 1 B 1600 W 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 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 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 - any amounts needed beyond CMMPA purchases and generation. In addition to providing electric service to its retail customers, HU sells to resale 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. B1600 Section 2 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, HU 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 Historical Electric Requirements (MWh) Street & Traffic 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, HU 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 & Total Annual Sales Lights & Utility Other (1) 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) Includes 9,673 MWh resale sales recorded as of October 2005 Year to Date. The "Estimated Purchases and Generation" table below reflects the new purchased power arrangement HU began in 2005. HU 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 HU wilI generate 5 percent of its requirements and will purchase the remainder of its requirements from the market. 2 -2 Hutchinson Utilities s1600 N 0 Estimated Operating Results - Existing Rates Estimated Revenue Requirements iA 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 Electric Purchases and Generation (MWh) Year CMMPA Generation Market Total Purchases Purchases 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 iA 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. B1600 R. W. Beck 2 -3 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. Cost of Electric Generation and Market Purchases 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 B1600 R. W. Beck 2 -3 Section 2 The following table shows the rate paid by HU for its purchases from Central 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 kW /month $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 Adj/kWh $0.01 $0:01 Resource Adj /kWh $0.000751 $0.000751 Consery Imprvmt 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 Transmission Gas Cost for Total Purchases and MISO Generation $3,460,256 Fees . $1,186,896 2005 $12,217,589 $3,006,544 $168,000 $1,687,621 $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 B1600 Estimated Operating Results - Existing Rates HU generation expenses other than the cost of natural gas are shown in the forecasted operating results in Exhibit 2 -A. Operating and Maintenance Expenses Operating and maintenance expenses s incurred 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 HU 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 i 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'tl 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 Iine item has been added for "Transmission Credit ", based on the assumption that HU will receive credits from MISO as a transmission owner. Other Expenses include the interest portion on HU'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 the 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 for 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 will be financed through a combination of current operating revenues and cash reserves. B1600 R. W. Beck 2 -5 Section 2 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. The 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 PCA 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 Revenues 9,090,093 8,860,442 8,136,251 7,609,642 7,102,615 Other Operating 1,175,050 639,750 639,750 639,750 639,750 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 N a Estimated Operating Results - Existing Rates 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 Revenues $26,153,704 $25,737,131 $25,306,572 $25,079,818 $24,879,008 Estimated Revenue 25,080,448 26,128,338 25,851,198 25,950,293 25,922,868 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 B 1600 R. W. Beck 2 -7 Section 2 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 Gas Requirements (MCF) Year Retail Sales Losses Total Annual Percent Change 2005 1,295,396 12,954 1,308,350 0.9% 2006 1,306,936 13,069 1,320,006 0.9% 2007 11320,006 13,200 1,333,206 1.0% 2008 1,333, 206 13,332 l,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 from 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 HU personnel. The assumptions used in these estimates are explained in detail below. Purchased Gas Expenses Projected capacity and commodity expenses for 2005 -2009 are based on forecasted rates and expenses developed through discussions with HU 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 B1600 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 I , 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 HU's other retail customers. Estimated Wholesale Gas Expense Year Capacity Cost Commodity Cost Total 2005 $8,147 $9,805,168 $9,813,315 2006 $6,000 $10,771,247 $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 Hutchinson 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. B1600 R. W. Beck 2 -9 Section 2 Other Income and Expenses f 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 -B. 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 for 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 lcate 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 B1600 0 r Estimated Operating Results - Existing Rates Estimated Gas Annual Sales Revenues Existing Rates Year 2005 2006 2007 2008 2009 Retail Sales Before FCA $4,322,125 $4,422,686 $4,467,608 $4,512,992 $4,558,845 FCA Revenues 4,307,993 4,592,318 4,259,401 3,544,274 2,773,910 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 Revenues - Total Operating $12,384,358 $15,030,813 $14,140,900 $13,115,879 $12,094,074 Revenues 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. 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% Gas and Electric Combined Cash Reserves Combined cash reserves for the Electric and Gas Divisions are presented below. Reserves at existing rates are estimated to be ($364,481) by the end of 2009. 131600 R. W. Beck 2 -11 =2 Section 2 2 -12 Hutchinson Utilities B1600 Estimated Combined Cash Reserves Existing Rates Year 2005 2006 2007 2008 2009 Beginning of Year Cash in Bank $1,900,000 $2,933,851 $1,525,142 $1,313,250 $1,176,330 Plus Electric Net Income 1,073,256 391 ( 207 ) 544,626 ( } (870,476) (1,Q43,860) Plus Gas Net Income 378,196 1,059,732 1,022,999 999,771 951,648 Plus Big Stone Expense Reimbursement 200,000 0 0 0 0 Less Electric Capital Improvements 900,000 ( ) ( 1,635,395 ) (1,819,500) (1,947,000) (3,385,500) Less Gas Capita! Improvements ( 1,700,000 ) (2,514,735) (1,062,000) (576,500) (374,500) 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 Bank $2,933,851 $1,525,142 $1,313,250 $1,176,330 ($364,481) 2 -12 Hutchinson Utilities B1600 G Operating Revenue Sales- Electric Energy Sales for Resale Net Inc Other Sources Security Lights Other Income Other - Net ` Transmission Credit Interest Income Miscellaneous Income Gain on Disposal Loss on isposal I oral Other Income Other Expenses Exhibit 2 -A Hutchinson Utilities, Minnesota Electric Operating Results Existing Rates Pole Rental Historical Total Operating Revenue Operating Expenses 2,000,997 Production Operation 870,488 Production Maintenance 914,556 Pwr Generation Pipeline 2000 Purch Gas - Generation 2002 Purchased Gas - Resale 2004 Purch Power- lntemal Use 2006 Sys Cntl & Engineering Transmission Payment 2008 Transmission Operation $18,017,720 Transmission Maint $14,976,382 Distribution Operation $19,994,766 Distribution Maintenance $25,097,381 Cust Acctg & Collecting $24,440,068 Sales Expense 906,827 Administrative & General 753,612 Depreciation - Electric 278,352 Total Operating Expenses 500,000 Operating Income Other Income Other - Net ` Transmission Credit Interest Income Miscellaneous Income Gain on Disposal Loss on isposal I oral Other Income Other Expenses Exhibit 2 -A Hutchinson Utilities, Minnesota Electric Operating Results Existing Rates 1,175,497 845,162 Historical 2,982,388 2,000,997 843,406 870,488 Forecast 914,556 937,420 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 $18,017,720 $17,722,698 $14,976,382 $19,627,120 $19,994,766 $24,978,654 $25,097,381 $24,666,822 $24,440,068 $24,239,258 906,827 2,756,490 753,612 583,613 278,352 1,022569 500,000 500,000 500,000 500,000 76,565 87,956 94,821 110,063 111,810 138,481 125,750 125,750 125,750 125,750 12,045 11,796 11,580 10,558 11,054 12,000 12,000 12,000 12,000 12,000 2 265 2.244 1 901 1 649 1 737 2 000 2 000 2 000 2 000 2 000 19,015,422 20,581,184 14,838,296 20,333,002 20,397,718 26,153,704 25,737,131 25,306,572 25,079,818 24,879,008 1,175,497 845,162 1,062,542 2,982,388 2,000,997 843,406 870,488 892,250 914,556 937,420 506,768 479,385 428,672 420,346 303,084 351,500 423,000 433,575 444,414 455,525 568,284 588,280 617,680 649,180 Non- Operating Inc/ (Expu) (892,520) 1,100,000 1,100,000 1,100,000 1,100,000 4,936,201 3,257,484 2,003,224 0 0 1,090,749 1,613,717 1,344,777 1,186,896 1,054,104 4.4% Net Income % of Net Assets 25,851,198 25,950,293 25,922,868 596,873 455,000 455,000 455,000 455,000 6,457,241 9,906,199 6,477,243 10,561,643 11,812,650 15,752,962 15,695,443 15,487,032 15,357,469 15,226,229 462,696 397,000 406,925 417,098 427,526 0 1,545,500 1,545,500 1,545,500 1,545,500 1,400 251 155 1,730 783 100 2,000 2,050 2,101 2,154 49,945 57,934 150,720 210,815 52,068 8,570 6,000 6,150 6,304 6,461 355,404 358,496 415,061 462,028 388,795 297,000 312,500 320,313 328,320 336,528 183,165 158,857 174,839 178,708 123,186 151,335 167,500 171,688 175,980 180,379 165,379 282,534 306,867 297,067 304,367 228,608 238,178 244,132 250,236 256,492 26,287 193,128 196,991 366,601 363,589 1,206,820 1,781,592 1,753,044 1,433,773 1,523,807 1,819,812 1,982,772 2,032,341 2,083,150 2,135,229 1.669.407 178_, 7.231 1,841,415 2,056,153 2,108.122 2,164.573 2,138.649 2J911 2,253,812 2318.712 16,707,227 18,915,125 14,613,782 18,604,650 18,617,859 23,794,471 27,140,875 26,831,886 26,887,438 26,800,848 2,308,195 1,666,059 1,224,514 1,728,352 1,779,859 2,359,233 (1,403,744) (1,525,313) (1,807,621) (1,921,840) 84,487 120,209 61,102 27,642 44,570 26,054 20,000 20,000 20,000 20,000 0 1,598,200 1,598,200 1,598,200 1,598,200 236,594 232,670 40,808 116,764 56,408 35,000 109,849 113,771 107,787 88,059 45,794 235,504 71,761 190,027 71,611 2,000 0 0 0 0 0 490 0 901,931 21,749 0 0 0 0 0 (20,473 0 0 0 0 0 0 0 0 0 346,402 588,873 173,671 1,236,364 194,338 63,054 1,728,049 1,731,971 1,725,987 1,706,259 Miscellaneous Expenses 74,671 94,930 126,195 105,691 65,385 Interest Expense 471.671 576.834 421.932 206394 650.854 Total Other Expenses 546,342 671,764 548,127 312,484 716,239 Contribution to the City 692,580 568,284 588,280 617,680 649,180 Non- Operating Inc/ (Expu) (892,520) (651,175) (962,736) 306,199 (1,171,081) Net Income 1,415,675 1,014,884 261,778 2,034,551 608,779 Oper Income as % of Net Assets -1.4% -2.2% -2.5% 4.4% Net Income % of Net Assets 25,851,198 25,950,293 25,922,868 1.5% Revenue Requirements 17,599,747 19,566,300 15,576,518 18,298,451 19,788,939 P: \004712 Hutchinson \Gas & Elec Rate Study\Elec oper results'existing rates \oper results 78,160 100 100 100 100 589.52 0 0 0 0 667,686 100 100 100 100 681,345 715,412 751,183 788,742 828,179 (1,285,977) 1,012,537 980,688 937,145 877,980 1,073,256 (391,207) (544,626) (870,476) (1,043,860) 6.0% -3.5% -3.8% 4.5% 4.6% 2.7% -1.0% -1.4% -2.2% -2.5% 25,080,448 26,128,338 25,851,198 25,950,293 25,922,868 Exhibit 2 -B Forecast 2005 2006 2007 2008 2009 $8,630,118 39,015,004 $8,727,009 $8,057,266 $7,332,755 $3,1047240 $3,765,810 $3,163,891 $2,808,613 $2,511,319 $650,000 $1,150,000 $1,150,000 $1.150,000 $1,150,000 $1,100,000 $1,100,000 $1,100,000 $1,100,000 0 0 0 0 0 12,384,358 15,030,813 14,140,900 13,1 15,879 12,094,074 0 0 .0 0 0 0 0 0 0 0 6,957,627 7,284,362 Hutchinson Utilities, Minnesota 5,550,143 2,855,688 3,492,885 2,888331 2,531,196 Gas Operating Results 85,000 87,550 90,177 92,882 2,500 Existing Rates 2,500 2,575 49,000 310,000 Historical 322,832 332,517 342,492 98,500 2000 2001 2002 2003 2004 59,737 Operating Revenue 63,375 65,276 8,800 64,376 59,454 54,329 Sales -Gas $8.146,245 $8,605,478 $8,070,500 $9,855,698 $10,258,242 787,826 Sales -3M 993,073 1,028,473 1,047,689 11,289,586 12,534,777 11,685,763 New Lnm Transportation 9,732,912 1,094,772 2,496,036 2,455,136 $550,257 2,361,162 Electric Div Transportation 25,000 25,000 25,000 25,000 35,000 0 Net Income from Other Sources 18.829 17,677 19,053 22105 22,542 5,000 Total Operating Revenue 8,165,074 8,623,155 8,089,553 9,877,903 10,831,041 0 Operating Expenses 0 0 0 0 0 0 MFG Gas Production Operation 638 119 0 0 0 30,000 MFG Production Maintenance 3,527 844 0 0 0 Purchased Gas Expense - Retail 6,922,703 7,445,306 6,898,141 8,770,088 8,058,319 Purchased Gas Expense -3M Transmission Operation 0 0 0 211 36,296 Transmission Maintenance 0 0 0 0 3,455 Distribution Operation 263,993 267,458 413,765 402,967 446,417 Distribution Maintenance 79,150 86,432 103,485 101,689 68,575 Cust Accounting & Collecting 110,252 70,633 76,717 74,267 76,092 Sales Expense 0 0 0 0 0 f Administrative & General 471,810 381,980 112,774 87,864 93,932 Depreciation -Gas 179,671 199,612 198,403 269,311 818,869 Total Operating Expenses 8,031,743 8,452,384 7,803,284 9,706,396 9,601,954 Operating Income 133,331 170,771 286,269 171,507 1,229,087 Other Income Other - Net 45,493 24,621 15,276 93,115 22,929 Interest Income 127,397 58,167 75,787 116,764 56,408 Miscellaneous Income 26,176 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 0 Misc Income - Gas Wells 443,286 395,281 155,001 1 285 f89,375 Total Other Income 628,703 506,449 255,219 352,451 (2,149) Other Expenses Depletion - Gas Wells 57 371 40 74 Exhibit 2 -B Forecast 2005 2006 2007 2008 2009 $8,630,118 39,015,004 $8,727,009 $8,057,266 $7,332,755 $3,1047240 $3,765,810 $3,163,891 $2,808,613 $2,511,319 $650,000 $1,150,000 $1,150,000 $1.150,000 $1,150,000 $1,100,000 $1,100,000 $1,100,000 $1,100,000 0 0 0 0 0 12,384,358 15,030,813 14,140,900 13,1 15,879 12,094,074 0 0 .0 0 0 0 0 0 0 0 6,957,627 7,284,362 6,982,992 6,294,391 5,550,143 2,855,688 3,492,885 2,888331 2,531,196 2,231,622 74,000 85,000 87,550 90,177 92,882 2,500 47,000 2,500 2,575 49,000 310,000 313,429 322,832 332,517 342,492 98,500 129,500 133,385 137,387 141,508 57,997 59,737 61,529 63,375 65,276 8,800 64,376 59,454 54,329 49,220 13 6,64 8 149,240 153,717 158,329 163,079 787,826 909,248 993,073 1,028,473 1,047,689 11,289,586 12,534,777 11,685,763 10,692,748 9,732,912 1,094,772 2,496,036 2,455,136 2,423,131 2,361,162 136,000 25,000 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 0 0 0 0 176,000 30,000 30,000 30,000 30,000 Miscellaneous Expenses 37,493 7 16,961 34,48A 10,519 0 4,049 0 1,380 0 11,000 0 0 0 0 0 Interest Expense Total Other Expenses 983 95,847 1.056 58,764 1 001 123. 004 649.149 589.526 1.159.652 0 1,140,152 0 1,115,27 6 0 1,084.526 45,999 127,053 650,529 600,526 1,159,652 1,140,152 1,115,276 1,084,526 Contribution to the City 296,820 232,116 252,120 264,720 278,220 292,050 306,653 321,985 , 338,084 354,989 Non- Operating lncome /(Expense: 236,036 215,569 (42,900) (39,322) (930,898) (716,576) (1,436,305) (1,432,137) (1,423,360) (1,409,515) Net Income 369,367 386,340 243,369 132,185 298,189 378,196 1,059,732 1,022,999 999,771 951,648 Oiler Income as % of Net Assets Net Income as % ofNet Assets 3.6 °/. 8.0% 8.3 % - 8.3% 8.2% 1.0% 1.2% 3.4% 3.5% 3 -4% 3.3% Revenue Requirements 7,795,707 8,236,814 7,846,184 9,745,718 10,532,852 12,006,162 13,971,082 13,117,900 12,116,109 11,142,426 r P: \004712 Hutchinson \Gras & Elec Rate Study \Gas oiler results existing tates\oper results 1 Ll U I, t 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 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 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 - 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 size of customers, such as the costs of meters and services and other equipment needed to provide service. B1600 R I W1�f Oi M Section 3 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 Test Year revenue requirements of 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 -B details the classification of electric plant -in- service. 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 m 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 Ioad characteristics of individual classes of services. 3 -2 Hutchinson Utilities B1600 Cost of Service Study r 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 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 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. Exhibit 3 -A, CIassification 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. B1600 R. W. Beck 3 -3 S. , Section 3 Electric Division 1 Comparison Of Revenues And Allocated Cost -Of- Service 2004 Test Year Customer Classification Total Allocated Costs Total Revenues = 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 9,332,646 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) n► 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 anatysis 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 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. 10- 3 -4 Hutchinson Utilities B1600 0 Cost of Service Study 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 the 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. B1600 R. W. Beck 3 -5 Section 3 The table below summarizes the classification of Test Year revenue requirements of the Gas Division. 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- service. Classification Of Gas Division Costs 2004 Test Year Cost Revenue Component Requirements Demand $948,676 Commodity 5,427,584 Customer Service 157,262 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. The following summary describes the specific allocation factors used in our cost -of- service analysis. Exhibit 3 -G 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 Test 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 B1600 Cost of Service Study 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 -I at the end of this Section. The table below compares our findings from Exhibit 3 -I with the revenues from each customer classification during the Test Year. B1600 R. W. Beck 3 -7 account the class load factor. This capacity cost allocation method recognizes both the average gas requirements, as well as the peak loads of each customer classification. Exhibit 3 -H 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. Commodity Allocations Commodity related costs have been allocated to each class of service based on recorded gas sales for the 2004 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 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 -I at the end of this Section. The table below compares our findings from Exhibit 3 -I with the revenues from each customer classification during the Test Year. B1600 R. W. Beck 3 -7 Section 3 Gas Division Comparison Of Revenues And Allocated Cost -Of- Service 2004 Test Year Customer Classification Total Allocated Costs Total Revenues 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 each 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 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) (t) 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 class and does not represent a proposed 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 B1600 v Operating Expenses Production Operation Production Maintenance Pwr Generation Pipeline Purchased Gas- Generation Purch Power - Internal Use Sys Cntl & Engineering Transmission Operation Transmission Maintenance Distribution Operation Distribution Maintenance Cost Acctg & Collecting C Sales Expense Administrative & General Depreciation-Electric k Total Operating Expenses M A� M M N N 0 Other (Income) Exhibit 3 -A Other - Net Hutchinson Utilities, Minnesota (44,570) Classification of Electric Test Year Revenue Requirements (44,570) 100% Revenue Interest Income (56,408) 2004 Test Year Total Adjusted 100% Revenue Demand Energy Cust Sery Cust Facil Revenue Basis for Classification 2,000,997 1,204,000 (1) 1,204,000 100% Revenue 100% Demand 303,084 303,084 (19,571) 303,084 (2,178) 100% Demand Total Plant 1,100,000 (2) 1,100,000 0 100% Demand s t 0 1,139,349 (3) 1,139,349 (194,338) 100% Energy . 11,812,650 14,969,403 (4) 1,359,000 13,610,102 300 (5) 298,011 (6) 298,011 1.00% Demand 783 783 65,385 783 52,964 100% Demand 52,068 52,068 (8) 52,068 650,854 100% Demand 388,795 388,795 0 234,137 154,658 Distribution Plant 123,186 123,186 52,964 74,184 49,002 Distribution Plant' 304,367 304,367 649,180 304,367 100% Cust Service 299,921 (7) Revenue on Resale Sales (278,352) • 2997921 100% Revenue 1,523,807 1,523,807 1,234,334 173,428 116,045 (8) 2,108,122 2,108,122 1,896,981 211,141 Total Plant 18,617,859 23,814,896 19,385,986 7,756,582 14,749,451 478,096 530,845 299,921 Other (Income) Other - Net (44,570) (44,570) (44,570) 100% Revenue Interest Income (56,408) (56,408) (56,408) 100% Revenue Miscellaneous Income (71,611) (71,611) (71,6)1) 100% Revenue Gain on Disposal (21,749) (21,749) (19,571) (2,178) Total Plant Loss on Disposal 0 0 0 0 Total Plant Total Other Income (194,338) (194,338) (19,571) (2,179) (172,589) Other Expenses Miscellaneous Expenses 65,385 65,385 52,964 7,442 4,979 (8) Interest Expense 650,854 0 u 0 0 Total Plant Total Other Expenses 716,239 65,385 52,964 7,442 4,979 0 Contribution to the 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 Oper Rev 124 601 12( 4.601) (124,601 100% Revenue Subtotal Revenue Requiremc 19,385,986 24,077,304 7,789,975 14,749,451 485,537 533,646 518,695 Margin 0 Total Revenue Requirement- 19,385,986 24,077,304 7,789,975 14,749,451 485,537 533,646 518,695 Percentage Rev Reqmts 100% 32% 61% 2% 2% 2% (1) Separated natural gas and fuel oil costs into another line - "Purchased Gas - Generation." (2)Elec Division payment to Gas Division for pipeline transportation will replace Electric Division's 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 CMMPA 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 higher costs from 2004 in the years going forward. (7) Sales expense was begun in 2005 to reflect required expenditures of 1.5 percent of revenue from 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 half the interest expense on the gas pipeline has been eliminated. (10) Included only net margin because cost of resale sales was removed from the analysis. P: \004712 Hutchinson \Gas & Elec Rate Study\Electric Cost of Service\Classification Exhibit 3 -13 Hutchinson Utilities, Minnesota Classification of Electric Plant -in- Sery ice 2004 Test Year Accumulated System Net Iscription Gross Plant Depreciation Plant -in- Service Demand Customer Basis of Classification lectric [ neration Plant and & Land Rights $1,453,900 $0 $1,453,900 $1,453,900 100% - Demand Structures & Improvements 2,526,567 795,553 1,731,014 1,731,014 100% Demand fuel Holders/ Producers 178,532 177,254 1,278 1,278 100% Demand 'eneration & Prime Movers 35,066,851 14,949,227 20,1 17,624 20,117,624 100% Demand 4ccessory Electric Eqpt 668,945 274,208 394,737 394,737 100% Demand risc Power Plant Eqpt 234,919 93,560 141,359 141,359 100% Demand t al Generation Plant 40,129,714 16,289,802 23,839,912 23,839,912 pinsmission Plant and & Land Rights 223,318 0 223,318 223,318 100% Demand structures & Improvements 589,226 69,647 519,579 519,579 100% Demand ?tationEquipment 4,354,666 1,138,316 3,216,350 3,216,350 100% Demand rowers & Fixtures 1,019,523 120,474 899,049 899,049 100% Demand 'oles & Fixtures 1,169,097 234,130 934,967 934,967 100% Demand 3verhead Conductors 616,245 192,795 423,450 423,450 100% Demand Inderground Conduit & Manholes 101,078 18,587 82,491 82,491 100% Demand ) nderground Conductors 71,569 12,172 59,397 59,397 100% Demand )tal Transmission Plant 8,144,722 1,786,121 6,358,601 6,358,601 stribution Plant .and & Land Rights 23,360 0 123,360 123,360 100% Demand tructures & Improvements 424,401 146,842P 277,559 277,559 100% Demand tation Equipment 2,868,972 1,346,373 1,522,599 1,522,599 100% Demand oles, Towers & Fixtures 123,813 97,701 26,112 13,056 13,056 50% Dmd/ 50% Cust iverhead Conductors 170,651 129,333 41,318 20,659 20,659 50% Dmd/ 50% Cust + nderground Conduit & Manholes 728,950 347,326 381,624 190,812 190,812 50% Dmd/ 50% Cust Inderground Conductors 6,631,963 I,773,850 4,858,113 2,429,057 2,429,057 50% Dmd/ 50% Cust iimsformers 2,517,432 974,776 1,542,656 1,542,656 100% Demand ervices 933,302 361,243 572,059 572,059 100% Customer leters 1,266,008 449,286 816,722 816,722 100% Customer ecurity Lights 0 l tal Distribution Plant 15,788,852 5,626,730 10,162,122 6,1 I9,758 4,042,365' tat Electric Plant $64,063,288 $23,702,653 $40,360,635 $36,318,271 $4,042,365 Aribution Plant Percent 60% 40% A Electric Plant Percent 90% 10% Security lights not included in cost -of- service analysis. P: \004712 Hutchinson\Gas & Elec Rate StudyTlectric Cost of Service\Plant in Service Exhibit 3 -C Hutchinson Utilities, Minnesota Electric Demand, Energy and Customer Allocation Factors 2004 Test Year Total Res /All Elec SGS LGS Lg Ind Demand Allocation Factors Coincident Peak Demand (kW) 61,004 12,135 3,686 18,541 26,642 Allocation Factor - CoincDmd 100% 20% 6% 30% 44% s Non - Coincident Peak Dmd (kW) 62,702 12,336 6 3,718 19,736 26,911 Allocation Factor - NonCoincDmd 100% 20% 6% 31% 43% Energy Allocation Factor Annual Energy Reqmts (kWh) (1) 290,843,204 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 of 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 Number of Customers 6,792 5,875 797 118 2 Facilities Weighting Factor 1 2 50 1,000 e Number of Customers 15,369 5,875 1,594 5,900 2,000 Al low location Factor - CustFacil 100% 38% 10% 38% 13.0% 1) Excludes street lights and security lights and resale sales. Non - Coincident Demand Analysis e Class Peak Month Billing Demand 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 Analysis 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% 'Coincident Demand 61,004 12,135 3,686 18,541 26,642 Coincidence w /Sys Pk Factor 79% 90% 95 % 99% Coincident Load Factor 57% 64% Recorded System Peak 61,000 P: \004712 Hutchinson \Gas & Elec Rate Study\Electric Cost of ServiceWloc Factors �I (1) Based on demand, energy, customer service and customer facilities allocations. (2) Revenues for LGS include revenues of $15,560 which is the amount given as primary discount in 2004 P:1004712 Hutchinson \Gas & Elec Rate Study0ectric Cost of ServiceWloc of Rev Req Exhibit 3 -D Hutchinson Utilities, Minnesota Allocation of Electric Revenue Requirements Test Year 2004 Total Res / A11 Elec SGS LGS Lg Ind Basis of Allocation Demand Component Production Operation $1,204.000 239,494 72,758 365,934 525,814 CoincDmd Production Maintenance 303;084 60,288 18,315 92,117 132,364 CoincDmd Pwr Generation Pipeline 1,100,000 218,807 66,473 334,325 480,395 CoincDmd Purch Power- Internal Use 1,359,000 270,326 82,125 4137043 593,506 , CoincDmd Sys Cntl & Engineering 298,011 58,633 17,673 93,802 127,902 NonCoincDmd Transmission Operation 783 156 47 238 342 CoincDmd Transmission Maintenance 52,068 10,357 3,146 15,825 22,739 CoincDmd Distribution Operation 234;137 46,066 13,885 73.697 100,489 NonCoincDmd Distribution Maintenance 74,184 14,596 4,399 .23,350 31,839 NonCoincDmd Administrative & General 1,234;334 242.853 73;201 388,520 529,760 NonCoincDmd Depreciation- Electric 1,896,981 373,227 1127499 597,096 814,159 NonCoincDmd Other (Income) (19,571) (3,851) (1,161) (6,160) (8,400) NonCoincDmd Other Expenses 52,964 10,421 3,141 16,671 22,731 NonCoincDmd Total Demand 7,789,975 1,541,373 466,504 2,408,459 3,373,639 Energy Component Purchased Gas - Generation 1,139,349 190,504 74,011 293,903 580,931 Energy Purch Power - Internal Use 13,610,102 2,275,672 884,097 3,510,820 6,939,513 Energy Total Energy 14,749,451 2,466,177 958,108 3,804,723 7,520,443 Cust Service Component 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 CustSery Other Expenses 7,442 5,692 1,158 572 19 CustSery Total Customer Service 485,537 371,399 75,576 37,298 1,264 Cust Facilities Component a Distribution Operation 154,658 59,120 16,040 59,372 20,126 CustFacil 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 CustFacil Depreciation- Electric 211,141 80,712 21,899 81,055 27,476 CustFacil Other (Income) (2,178) (833) (226) (836) (283) CustFacil Other Expenses 4,979 1,903 516 1,912 648 CustFacil Total Customer Facilities 5337646 2031,993 55,347 204,861 69,445 Revenue Component Sales Expense 299;921 58,345 19,803 82,182 139,591 (1) Other (income) (172,589) (33,574) (11,396) (47,291) (80 ;327) (1) Contribution to the City 649,180 126,287 427864 177,883 3027145 (1) Revenue on Resale Sales (133,217) (25,915) (8,796) (36,503) (62,003) (1) Credit for Other Oper Rev f 124,601 24 239 8( ,227) 3( 4.142) 57 993 (1) Total Revenue 518,695 100;904 34,249 142,129 241,414 Total Revenue Reqmts $24,077,304 $4,683,846 $1,589,783 $6,597,470 $11,206,206 Total Revenues (2) $20,009,882 $3,702,238 $1,437,418 $5,537,580 $9,3327646 Revenue Regmts Percent 100.0% 19.5% 6.6% 27.4% 46.5% Revenue Percent 100.0% 18.5% 7.2% 27.7% 46.6% Percent Change 5.1% -8.1% -1.0% -0.2% (1) Based on demand, energy, customer service and customer facilities allocations. (2) Revenues for LGS include revenues of $15,560 which is the amount given as primary discount in 2004 P:1004712 Hutchinson \Gas & Elec Rate Study0ectric Cost of ServiceWloc of Rev Req Hutchinson Utilities, Minnesota Exhibit 3-E Revenue Direct Basis for Classification Per wholesale gas bills 2,230,676 (2) 100% Demand 100% Demand Distribution Plant Distribution Plant 100% Cust Service 51,291 100% Revenue Distribution Plant 51,291 2,230,676 (22,929) (56,408) (2,049) 0 (81,386) 0 0 0 0 278,220 o evenue equtrem- $9,982,595 9,393,514 705,616 5,427,584 87,588 693,924 248,125 asst rca on o as est ear Revenue Requirements 551,992 ta l Revenue Requirements $9,982,595 $10,258,240 $948,676 $5,427,584 $157,262 $1,245,916 $248,125 2004 Test Year 7% 3% Split cost of gas for 3M from retail total cost of gas. Total Adjusted Demand Commodity Cust Sery Cust Facil ?perating Expenses Based on transmission, distribution, customer service and customer facilities expenses. Income from gas wells varies widely. It is usually not a net loss, as in the 2004 test year Purchased Gas Expense- Retail $8,058,319 $5,827,643 (1) $400,059 $5,427,584 Purchased Gas Expense -3M 0 2,230,676 (1) Transmission Operation 36,296 36,296 36,296 Transmission Maintenance 3,455 3,455 3,455 Distribution Operation 446,417 446,417 226,063 220,354 Distribution Maintenance 68,575 68,575 34,726 33,849 Cust Accounting & Collecting 76,092 76,092 76,092 Sales Expense 0 51,291 (3) Administrative & General 93,932 93,932 44,751 11,330 37,851 Depreciation -Gas 818,869 818,869 414,671 404,197 Total Operating Expenses 9,601,954 9,653,246 1,160,022 5,427,584 87,422 696,251 k,her her (Income) - Net (22,929) (22,929) Interest Income (56,408) (56,408) Income (2,049) (2,049) OMiscellaneous Gain on Disposal (5,840) (5,840) (2,957) (2,883) Loss on Disposal 0 0 0 0 Misc Income - Gas Wells 89.375 0 (5) total Other Income 2,149 (87,226) (2,957) 0 0 (2,883) her Expenses Depletion - Gas Wells 0 0 Expenses 1,380 1,380 658 167 556 VMiscellaneous interest Expense 649,149 1,198,151 (6) 1,198.151 Expenses 650,529 1,199,532 1,198,809 0 167 556 ASher bution to the City 278,220 278,220 medit--Elec Div Transport Rev 0 (1,10000) (7) (1,100,000) Credit -New Ulm Transport Rev ht .*a] R R (550,257) (550,257) (550,257) Exhibit 3-E Revenue Direct Basis for Classification Per wholesale gas bills 2,230,676 (2) 100% Demand 100% Demand Distribution Plant Distribution Plant 100% Cust Service 51,291 100% Revenue Distribution Plant 51,291 2,230,676 (22,929) (56,408) (2,049) 0 (81,386) 0 0 0 0 278,220 o evenue equtrem- $9,982,595 9,393,514 705,616 5,427,584 87,588 693,924 248,125 argin 864,726 243,060 69,673 V 551,992 ta l Revenue Requirements $9,982,595 $10,258,240 $948,676 $5,427,584 $157,262 $1,245,916 $248,125 Revenue Requirements Percent 8% 58% 1 % 7% 3% Split cost of gas for 3M from retail total 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. It is usually not a net loss, as in the 2004 test 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. r P: \004712 Hutchinson \Gas & E)ec Rate Study \Gas Cost of Service \Classification 2,230,676 $2,230,676 24% 100% Revenue 100% Revenue 100% Revenue Distribution Plant Distribution Plant 100% Revenue 100% Revenue (4) 100% Demand 100% Revenue 100% Demand 100% Demand (8) escription Gas Distribution Mains M &R Station Equipment -Gen M &R Station Equipment -City Services Meters & all Fittings House Regulators & All Fittings Industrial M &R Station Equipment Other Equip (CO tester, Gas Analy2 Total Gas Plant total Gas Plant Percent Hutchinson Utilities, Minnesota Classification of Gas Plant -in- Service 2004 Test Year Accumulated System Net Gross Plant Depreciation Plant -in- Service 28,71 1,445 1,656,813 1,317,577 135,143 360,284 81,723 726,782 272,226 913,197 291,689 85,866 30,569 95,685 45,023 76,147 41,382 $32,286,983 $2,554,568 Exhibit 3 -F Demand --ust Facilities Basis of Classification 27,054,632 13,527,316 13,527,316 50% Dmd/ 50% Cust 1,182,434 1,182,434 100% Demand 278,561 278,561 100% Demand 454,556 454,556 100% Customer 621,508 621,508 100% Customer 55,297 55,297 100% Customer 50,662 50,662 100% Demand 34,765 17,383 17,383 50% Dmd/ 50% Cust $29,732,415 $15,056,356 $14,676,060 51% 49% J P: \004712 Hutchinson \Gas & Elec Rate Study \Gas Cost of Service\Plant in Service Exhibit 3 -G Hutchinson Utilities, Minnesota Gas Demand, Commodity and Customer Allocation Factors 2004 Test Year Lge Indus Total Residential --oml /Interrupt HTI 3M Demand Allocation Factor Peak Period Sales (MCF) -Jan 04 201,528 91,368 67,161 11,083 31,916 Allocation Factor - Dem -1 100% 45% 33% 5% 16% Average/Excess Demand (MCF) (1) 201,528 81,823 61,604 10,916 47,285 Allocation Factor Dem -2 100% 41% 31% 5% 23% Commodity Allocation Factor Annual Sales w/o 3M (MCF) (2) 918,750 448,368 382,785 87,597 Allocation Factor Comm 100% 49% 42% 10% 0% Customer Service Allocation Factor Average Number of Customers 5,058 4,557 499 1 1 Service Weighting Factor 1.0 2.5 10.0 15 Weighted Number of Customers 5,830 4,557 1,248 10 15 Allocation Factor CustSery 100% 78% 21% 0.2% 0.3% Customer Facilities Allocation Factor Average Number of Customers 5,058 4,557 499 1 1 Facilities Weighting Factor 1.0 7.0 500 750 Weighted Number of Customers 9,300 4,557 3,493 500 750 Allocation Factor CustFacil 100% 49% 38% 5.4% 8.1% (1) See Exhibit 3 -H for development ofAverage/Excess Demand. (2) 3M commodity costs directly assigned. P: \004712 Hutchinson \Gas & Elec Rate Study \Gas Cost of Service\Alloc Factors x Y W .d Cd a� Q _C,3 a O U X W bbo a� N Q O to) O d +o x0 b v r -F o � � � �olo U OD U 0, V M N O U a Q W Q T3 �X u00 oh 00 'D vo Q b C U E V N M X W q U zzzzi W Q � rn 00 O O O O N d ONO O QI •� v h � d O cn 'c7 �Qaau to 'ot .� �OM --i O t1M 1 lh a 00 M Vj Ci E" r- C) cl M M M O U p W T3 O0 �+ n !r � ��o++ �.. Q1 00 N U N 00 �� QQ�¢I a oUNzzzzvN, to _ 00 cn n � N 0� ^' o0 N h V1 M 00 00 \c o0 G V M M N U � 0 x� U 0 S S cd ,�, cla U �VmcE0 v N Q N U X W' v V) w O 0 U C�7 UO 0 U _N W ca to C O c S Y x N h O O a 0 U "t7 cd N Q a� U X W U m S a� N OD v � � v E o U O m CU N v Y vi � _� E Q > o � O N C � N � 3 C �. > Q o .a o C'S ID C13 �a o 00 E U � C,3 w y vi N N .Y cri Y m V •� U M v . W o y O .. ctl O O y Y cci C OOC O C U OU G U �l M (C C's C6 M _ :3 C o - o 0 Rt —V > W id V O - O � � — � N o >, O >, [- •vnSHUc�wv�a: N M 'd' V7 \O h 00 01 v N Q N U X W' v V) w O 0 U C�7 UO 0 U _N W ca to C O c S Y x N h O O a Exhibit 3 -1 P: \004712 Hutchinson \Gas & Elec Rate Study \Gas Cost of Service\Allocation Unbundled M Hutchinson Utilities, Minnesota Allocation of Gas Revenue Requirements 2004 Test Year Lgelndus Total Residential Commercial HT] 3M Allocation Demand Component Purchased Gas Expense- Retail $400,059 $181;377 $133.323 $22.001 $63,357 Dem -1 Transmission Operation 36,296 14.737 1 1.095 1.948 8,516 Dem -2 Transmission Maintenance 3,455 1.403 1,056 185 811 Dem -Z Distribution Operation 226,063 91.785 69.104 12.133 53,042 Dem -2 Distribution Maintenance 34,726 14;099 107615 1,864 8,148 Dem -2 Administrative &General 44,751 18;169 13,680 2,402 10;500 Dem -2 Depreciation -Gas 414,671 168,362 126,758 22,256 97,296 Dem -2 Other Income (2,957) (1,201 (904) (159) (694) Dem -2 Other Expenses 1,198,809 486;732 366.455 64,340 281,281 Dem -2 Credit for Elec Div Transport Rev (1,100,000) (446,614) (336,251) (59,037) (258,098) Dem -2 I Credit for New Ulm Transport Rev (550,257) (223,412) (168,204) (29,532) (129,109) Dem -2 Margin 243,060 98,686 74,299 13,045 57,030 Dem -2 Total Demand 948,676 404,123 301,026 51,446 192,082 ICommodity Component Purchased Gas Expense - Retail 5,427,584 2,648,767 2,261,331 517,486 0 Comm Total Commodity 5,427,584 2,648,767 2,261,331 517,486 0 ' Customer Services Component Cust Accounting & Collecting 76,092 59,482 16,283 131 196 CustSery Administrative & General 11,330 8,857 2,425 19 29 CustSery Other Expenses 167 130 36 0 0 CustSery Margin 69,673 54,465 14,910 120 179 CustSery Total Customer Services 157,262 122,934 33,654 270 405 1 Customer Facilities Component Distribution Operation 220,354 107,973 82,763 11,847 17,770 CustFacil Distribution Maintenance 33,849 16,586 12,713 1,820 2,730 CustFacil Administrative & General 37,851 18,547 14,216 2,035 3,052 CustFacil Depreciation -Gas 404,197 198,057 151,813 21,731 32,597 CustFacil Other (Income) (2,883) (1,412) (1,083) (155) (232) CustFacil Other Expenses 556 273 209 30 45 CustFacil Margin 551,992 270,476 207,323 29,677 44,515 CustFacil Total Customer Facilities 1,245,916 610,499 467,955 66,985 100,477 Revenue Component Sales Expense 51,291 19,401 15,700 3,260 12,931 (1) Other(hicome) (81,386) (30,784) (24,911) (5,172) (20,518) (1) Contribution to the City 278,220 105,237 85,160 17,682 70,142 (1) Total Revenue 248,125 93,853 75,948 15,769 62,555 Direct Component Purchased Gas Expense -3M 2,230,676 2,230,676 (2) t Total Direct 2,230,676 0 0 0 2,230,676, Revenue Requirements $10,258,240 $3,880,177 $3,139,914 $651,955 $2,586,194 Total Revenues $10,255,238 $3,867,185 $3,197,363 $751,024 $2,439,666 Percent Rev Requirements ° 100% 3T8% 30.6% 6.4% 25.2% Percent Revenues 100% 37.7% 31.2% 7.3% 23.8% Percent Change 0.3% -1.8 %° - 13.2% 6.0% (1) Based 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 Service\Allocation Unbundled M 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 Fuel Cost Adjustment revenues collected in the 2004 Test Year. Due to the adjustments made to the Electric Division's 2004 Test :Year revenue requirements to better reflect costs during the Study Period, the unbundled electric rates represent a revenue increase of 20 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 power component consists of purchased power and generation demand and energy charges. For retail classes billed on the basis of demand and energy, the retail demand portion of the wholesale component represents wholesale demand 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 demand 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 demand 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. B1600 RAV! 1 Section 4 I Customer The customer charge reflects both customer service and customer facilities expenses, including accounting and collecting charges, certain A &G expenses, O &M and I depreciation on the customer portion of the system, and a credit ,for non - operating income. The customer charge is a monthly per customer charge. Contribution tribution 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. The 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. 4 -2 Hutchinson Utilities B1600 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 Purch Pwr 2,275,672 884,097 3,510,820 6,939,513 13,610,102 Wholesale > Energy 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 $24,077,304 Section 4 Unbundled Electric Rates 4 -4 Hutchinson Utilities s1600 Rate Class Unbundled Rate Rate Component Res/ Small Large Large All Elec General General Industrial Service Service 0.0106 Purch Pwr Customer Customer ($Imo) Demand ($/kW) 13.34 166.44 $2.12 $2.49 Wholesale Power Energy ($/kWh) 0.0026 0.0023 0.0024 Purch Pwr Energy Customer ($ /mo) $8.00 ($ /kWh) $0.0536 $0.0521 0.0468 0.0468 Gen Demand $9.96 $11.44 ($ /kW) Energy ($/kWh) 3.32 3.93 Gen Energy $0.0528 ($ /kWh) 0.0146 0.0123 0.0039 0.0039 Demand ($ /kW) 0.07 0.08 Transmission Energy ($ /kWh) 0.0002 0.0002 4 -4 Hutchinson Utilities s1600 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 ($ /mo) $8.00 $13.34 $166.44 $2,831.60 Total Demand ($IkW) $9.96 $11.44 Energy ($/kWh) $0.0847 $0.0774 $0.0531 $0.0528 4 -4 Hutchinson Utilities s1600 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 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 demand and commodity component based on consumption. Transmission 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 The 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. Customer 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 charge. Contribution to the City The Utility contributes cash to the City. The cost of this contribution is expressed as a consumption charge. Unbundled Gas Rates Unbundled natural gas costs and resulting retail rates for the Residential, Commercial and Large Industrial rate classes are shown in the tables below. Costs associated with 3M have been eliminated from the unbundled analysis, due to the fact that 3M has contract rates. 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 individual unbundled components have been summed to show 131600 R. W. Beck 4 -5 C� Section 4 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 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 of 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/ Demand $181,377 $133,323 $22,001 $336,702 Production Commodity 2,648,767 2,261,331 517,486 5,427,584 Transmission Demand 16,140 12,151 2,133 30,424 Distribution Demand 204,104 153,371 26,759 384,234 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 $7,672,046 4 -6 Hutchinson Utilities B1600 Unbundled Rates Unbundled Gas Rates Rate Class Unbundled Rate Component Residential Commercial Large Industrial Rate Purchase/ Demand ($ /Mcf) $0.40 $0.35 _ $0.25 Production Commodity ($ /Mcf) 5.91 5.91 5.91 Transmission Demand ($ /Mcf) 0.04 0.03 0.02 Distribution Demand ($ /Mcf) 0.46 0.40 0.31 Commodity ($ /Mcf) Customer Customer ($ /mo) 13.25 82.59 5,491.19 City Commodity ($ /Mcf) 0.23 0.22 0.20- Total Customer ($Imo) $13.25 82.59 $5,491.19 Commodity ($/Mcf) $7.04 $6.91 $6.69 ry B1600 R. W. Beck 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 y 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 I. 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. B1600 H I W�E[li 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 Eliminate Res Including PCA (1) Rate Residential Monthly Charge None None $6.50 First 300 kWh /mo $0.0714 $0.0999 Over 300 kWh /mo 0.0514 0.0799 All kWh /mo Over 800 kWh /mo 0.0459 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 kWh /mo 0.0911 Over 2000 kWh /mo 0.0855 Large General Demand per kW /mo 3.65 3.65 6.00 Service First 2000 kWhlmo 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 (') Current rates include forecasted 2006. PCA of $0.0285 per kWh. Proposed rates assume aPCA of $0.00 5 -2 Hutchinson Utilities B1600 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 1: 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, B1600 R. W. Beck 5 -3 Section 5 when to apply a PCA charge or credit, as appropriate, in order to keep the balance in 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 and installing street lights in the future. Hutchinson Utilities 4tront 1 inhtn Cnct Analysis Description Wattage Number of Fixtures Capital Cost (1) per unit Annual Carrying Cost per unit Annual Energy Cost per unit Annual Demand Cost per unit Annual O &M Cost per unit Annual Cost per Unit Monthly Cost per Unit I Total Annual Cost City Owned Carry Cost/Caphal 10.00% O &M per year $ 48,000 150 W HPS 150 1,283 $39.63 $2 -44 $32.30 $74.37 $6.20 $95,421 250 W HPS 250 113 66.05 4.07 $32.30 $102.42 8.54 $11,574 400 W HPS 400 5 105.68 6.51 $32.30 $144.49 12.04 $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 4.07 $32.30 $102.42 8.54 $4,097 400 W MV 400 9 105.68 6.51 $32.30 $144.49 12.04 $1,300 HU Owned $0 150 W HPS 150 20 $2,000 $200 39.63 2.44 $32.30 $274.37 22.86 $5.487 Total 1,486 1 $119,904 Assumptions (teen Value Percent On 50% Months on Peak 3 Losses 18% Wholesale Dmd Cost $4.60 rn Wholesale Energy Cost $0.0511 (3) Carry Cost/Caphal 10.00% O &M per year $ 48,000 (1) The City purchased and installed all street lights under the heading "City Owned " - No capital costs are associated with these lights. (2) 2006 Xcel non- summer demand cost per kW, including 6.9% rate increase for 2006. (3) 2006 average energy cast per kWh, including purchases and generation. 5 -4 Hutchinson Utilities s(600 1 r-1 t N Proposed Rates Rate Comparison with Xcel Energy Xcel Energy is an investor owned utility and is the largest provider of retail electric service in Minnesota. Shown below is a comparison of typical monthly bills for residential, small general service and large general service customers. The comparison is shown for HU's 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 MISO 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 (4) Residential (5) $67 $72 $64 $69 Small General Service (6) 188 192 165 178 Large General Service (1) 4753 5030 3596 3885 (1) Includes a PCA charge of 3.05 cents /kWh average 2005 PCA. (2) Includes a PCA charge of 0 cents/kWh (3) Includes applicable Xcel rate adjustments, including average 2005 FCA of 0.779 cents/kWh. (4) Assuming 8.05% increase (5) Assuming 750 kWh and average annual rate for Xcel. (6) Assuming 2,000 kWh and average annual rate for Xcel and HU. (7) Assuming 175 kW and 54,000 kWh and average annual rate 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. B 160 R. W. Beck 5 -5 Section 5 Electric Division Estimated Annual Operating Results Proposed Rates Year 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 Percent of Net Assets 6.0% 1.7% 1.7% 1.2% 1.1% Net Income as Percent of Net Assets 2.7% 4.2% 4.3% 3,9% 3.8% 5 -6 Hutchinson Utilities B1600 JV� 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 evenues 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. The 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, 131600 R. W. Beck 5 -7 Section 5 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 customers. 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 1: 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 D 1 A 1 A M M M Proposed Rates Hutchinson Utilities Current And Proposed Retail Gas Rates Class Rate Component Current Rate Current Rate Proposed Including FCA Rate (1) Residential Monthly Charge (Includes $3.32 $5.30 first 400 cf /mo Next 3600 cf /mo per MCF 5.05 10.00 Over 4000 cf /mo per MCF 4.58 9.53 Monthly Charge $6.50 All MCF /mo 9.08 Commercial Monthly Charge (Includes 3.32 5.30 first 400 cf /mo Next 3600 cf /mo per MCF 5.05 10.00 Over 4000 cf /mo per MCF 4.58 9.53 Monthly Charge 31.50 All MCF /mo 9.08 Large Demand per MCF 4.31 4.31 10.00 Industrial All MCF /mo 4.33 9.28 8.54 (') Current rates 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 HU Rates (1) Xcel Rates a► Residential (3) $94 $99 Commercial (4) 535 536 (1) Includes a FCA charge of $6.501MCF (2) Includes applicable Xce) rate 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 81600 R. W. Beck 5 -9 94 Section 5 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 R. W. Beck recommends that HU establish a reserve fund to hold at least 1 'f2 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. Operating Income as 3.6 /0 8.1 /0 8.4 /a 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 s1600 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 /0 8.1 /0 8.4 /a 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 s1600 Proposed Rates Estimated Combined Casks 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 Plus Big Stone Expense Reimbursement Less. Electric Capital Improvements Less Gas Capital Improvements Less Debt Service Principal Plus Depreciation End of Year Cash in Bank 378,196 1,072,393 1,039,855 1,015,627 965,831 200,000 (900,000) (1,635,395) (1,819,500) (1,947,000) (3,385,500) (1,700,000) (2,514,735) (1,062,000) (576,500) (374,500) (970,000) (975,000) (995,000) (1,025,000) (1,055,000) 2,952,399 3,047,897 3.186,235 3.282,285 3,366,401 $2,933,851 $3,602,473 $5,671,812 $7,976,809 $9,077,576 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 ra hs the average g p h 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. B1600 R. W. Beck 5 -11 Section 5 Exhibit 5 -E graphs the average monthly gas bill under the current and proposed rate 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. 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 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 amounf 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 131600 r M 0 0 N O O O O O O .0 *1 y cu a• b W) 0 . CL o 0 E 0 o 1 T W o O Y +r Cc m U C C :E C o = o 0 0 O W) 0 0 M O O O N O N O - 00 O k0 o It O N O O O 69 O O 6Q9 660! 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