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Unalaska Electric Rate Study 1985
Sy.07.do DAPI R.W.BECK AND ASSOCIATES ENGINEERS AND CONSULTANTS. ORLANDO,FLORIDA SACRAMENTO,CALIFORNIA SEATTLE,WASHINGTON COLUMBUS,NEBRASKA INDIANAPOLIS,INDIANA WELLESLEY,MASSACHUSETTS PHOENIX,ARIZONA DENVER,COLORADO AUSTIN,TEXAS MINNEAPOLIS,MINNESOTA This report has been prepared at the request of and for the use of the client,and the conclusions,observations and recommen- dations contained herein constitute only the opinions of R.W. Beck and Associates.To the extent that statements and books of record and accounts of the client,statements of independent public accountants and auditors employed by the client and in- formation prepared by others have been usedin the preparation of this report,R.W.Beck and Associates 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 and Associates makes no certification and gives no assurances except as explicitly set forth in this report. ELECTRIC RATE STUDY FOR >CITY OF UNALASKA- September1985 |- Nog "se "s 5 2Ee'a, oo te Af 7 i L eT 4 .Y pods i teaetLEoot R.W.BECK AND ASSOCIATES,INC ENGINEERS AND CONSULTANTS 0.X 681PO.BOX 2400 FOURTH &BLANCHARD BUILDING PO.BOX 6818 SITKA,ALASKA 2121 FOURTH AVENUE KETCHIKAN,ALASKA 99635 .SEATTLE,WASHINGTON 98121 1 206-441-7500 reno.SS-1987-ER1-AX ;September 20,1985 City of Unalaska Pouch 89 Unalaska,Alaska 99685 Pursuant to our agreement,.we.have completed an Electric Rate Study for the City.This report sets forth the results of our study and contains our conclusions and recommendations.We,appreciate the cooperation of Citypersonnelinprovidinginformationandmaterialnecessaryforthecompletion of this study.oe OO LS Respectfully submitted, SECTION SECTION SECTION SECTION SECTION SECTION SECTION SECTION SECTION It TIl VI VII VIII "Avoided Cost Rates*,> ELECTRIC RATE STUDY FOR CITY OF UNALASKA TABLE OF CONTENTS Introduction,Background and Summary of Conclusions and Recommendations a Bus Bar Generation Cost we ' Rate Requirements | a Be, Economics of System Expansion Economic Feasibility of a Waste HeatRecoveryHeatingSystem Load Forecast Privately-Owned Electrical Generation Proposal of Energy Systems,Inc. SECTION TI INTRODUCTION,BACKGROUND AND SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS - INTRODUCTION a € The City of Unalaska,Alaska (City),through the Electric Utility Division of the Department of Public Works owns,operates and maintains anelectricgenerationanddistributionsystemwhichprovideselectricservicetotheCity.The City consists of the adjacent communities of Unalaskaand DutchHarborandislocatedonUnalaskaIslandintheAleutianArchipelago.The City's present generators,which provide all its power requirements,consist of diesel generators located at two separate sites,one in Unalaska and one in Dutch Harbor.Construction of a 34.5-kVA primary distribution system has justbeencompletedwhichtheCityenergizedinJuly1985.coe . The City is also renovating a surplus'U.S.Navy powerhouse inwhichitisinstallinganew1.4-megawattdiesel”generator plus 600-kW and300-kW diesel generators.Installation is expected to be completed during fiscal year (FY)1985-86.When the new:facility becomes operational,allpowergenerationrequirementsoftheelectricsystemwillbetransferredto this new power facility and the two existing 600-kW diesel generators will be overhauled and moved to that facility.°> This study has been conducted byR.W.Beck and Associates,Inc., pursuant to the request of the City.The study was conducted using historical and projected data,as available from the City with respect to revenues, expenses,system additions,system loads and future plans.Basic data was obtained from the City's financial statements,budgets,operating reports, billing data and through discussions with Electric Division and City manage- ment and staff.Projections reflect historic trends,City policies and objec- tives,and economic and growth outlooks for the communities and area.The Unalaska/Dutch Harbor Reconnaissance Study Findings and Recommendations,pre- pared by the Alaska Power Authority,April 1985,was also used as a source of background information.Following is the Scope of Services which was the basis for our study and this report. 1.Project "Bus Bar"per kWh generation costs for new power facility. 2.Analyze and project future rate requirements for the new system based on a base load of 1.2 MW. 3.Analyze and project avoided cost rates based on new generation, transmission and distribution system with a base load of 1.2 MW. 4.Analyze and project economic feasibility of system expansion to the following areas or potential customers: The PROPERTY OF RV EPCK ANG ASS OTST ROT AS AILABLE FOR Guar ARE UNL AUTHAGRIIO SOCIATES . Area/Customer Type Unisea Area Commercial Pacific Pearl Commercial East Point Seafoods Commercial Panama Marine Commercial* APL Commercial _+ Chevron +Commercial Sea Alaska _CommercialMagoneMarine..»,Commercial Strawberry Hill "..Residential Ski Bowl oe Residential Margaret's Bay.oo Comercial /Tndustrial5.Analyze and project economic:potential .and feasibility for distri- bution and sales.of waste-heat from the new power facility.Sub-ject areas include .airport terminal,'Standard Oil Hill Housing orotherpotentialsiteswhichmay.be.identified during the course ofthisstudy.°oe eeeQoBO6.Analyze .the 'service area and existing studies on demographics, economics and energy use forecasts to estimate loads and peak demands over the next five years.7.Analyze the service area's existing electrical generation systemstodeterminecogenerationpotential.Analyze the effect of theCity's cogeneration policy on the economicsof cogeneration and,ifappropriate,recommend revisions. 8.Analyze hydro power purchase proposal from Energy Stream,Inc.and advise on findings.If appropriate,suggest alternatives. 9.Provide the City with a written report presenting and discussing data obtained,analyses performed and conclusions reached in items 1 through 8. BACKGROUND The City has been making significant changes in its electric gener- ation and distribution system.The major changes in the distribution system have centered on the completion of approximately seven miles of underground 34.5-kVA primary distribution line.This system was designed to allow the City to serve both communities from one power production facility.This power facility,a renovated U.S.Navy powerhouse,will house all the City's diesel generators and will have room for additional units,By consolidating their resources,the City anticipates cost reductions mainly resulting from reduced fuel costs and increased operating efficiencies..,.,,\ Ty GF RO VW BECK AND MOT AVAILABLE FOR By reducing its costs the City anticipates attracting additional loads,thus more fully utilizing its installed capability.The loads it expects to attract are mostly large,industrial type loads.These loads are currently served by their own generation and include the major fish processingfacilities.ae SUMMARY OF CONCLUSIONS AND RECOMMENDATIONS +.x This report contains discussions,"summaries of analyses and our conclusions and recommendations with respect to the specific items included in the Scope of Services.Our conclusions and recommendations are summarized in this section.Sections Il through -IX.provide detailed discussions with respect to each item.Section II presents the projected generation cost forthenewpowerfacilityatthebusbar.:Section III provides-.a projection of rate requirements based on the new system and a base load of 1.2 megawatts.Section IV projects the avoided .cost ratesof the"new system on-line with1.2 megawatts.Section V provides an analysisof the economic feasibility ofsystemexpansionto'identified potential customers.|Section VI examines the potential and economic feasibility-of using waste heat recovery from the new power facility to heat the airport terminal building.Section VII provides afive-year load forecastfor the City's service area.Section VIII analyzestheCity's cogeneration policy and examines the service area to determine thecogenerationpotential.Section IX presentsan analysis of the Energy Stream,Inc.hydroelectric proposal presented to the City. Our analys¥6 show the cost of generation at the City's new gener- ation facility to be 20.56 cents per kilowatt hour for fiscal year 1985-1986, and 20.34 cents per kilowatt hour for fiscal year 1986-1987.Fuel costs of 7.20 cents per kWh represent approximately 352%of the bus bar costs.Sec- tion II shows detailed calculations of the bus bar costs, The City's customers should be grouped into five basic rate classes: (1)residential,(2)small general service (no demand meters),(3)large general service (demand meters),(4)industrial,and (5)street lighting. Residential and Small General Service rates would have no demand charge while the Large General Service and Industrial rates would have a demand charge. The Industrial rate would also contain a provision for interruptible service.All rate classes would have a basic customer charge and an energy charge. Recommended proposed rate levels and rate structures are shown in Section III along with further explanations of the rate classes. The city"/electric system's avoided cost rate with the system having a base load of 1.2 megawatts is 7.6 cents per kWh.The energy rate represents the costs the City could expect to avoid if load was served by generation other than the City's.Details of the calculation of avoided cost is shown in Section IV.oe Lmeaarp re emeryTheCity's service area contains "geveral industrial loads which have been identified as potential new large'loads.forthe system.The current generating capability of.the City's,system exceeds.the current load.Our GONLRALAELEAGT UNTic AUTHORIZED omen ee OAR AT ESEyRONbitRANDASSOCIATES. studies indicate that the addition of new loads to the system would reduce costs for all customers by spreading fixed costs over a larger sales base.Addition of new loads which could require added generation capacitymay causehighercostsforallcustomers,however.Section V contains details of thestudiesofpotentialnewlargeloads., The potential exists for the utilization of waste heat recovered at the new power facility to heat the airport terminal building and displace the existing oil-fired heating system.The economic feasibility is marginal how- ever.Capital costs would be recovered in approximately 6 to 11 years depend- ing upon the method of funding the required pipeline.Section VI contains details of our analyses of the _potential for waste heat usage for heatingpurposes.me le f co Tey nn >al io .: A five-year forecast of energy and peak demands was prepared.The forecast yielded a range of results depending upon assumptions with respect to the addition of new large loads and recovery of the fishing industry in the area.The lower band of the forecast:reaches a peak demand of 1,124 kW andenergyrequirementsof4,035,601 kWh by fiscal year 1989-1990.The upper band of the forecast reaches a peak demand of 2,685 kW and energy requirements of 8,702,111 kWh by fiscal year +1989-1990.Details of the forecast are containedinSectionVII.ar oo oe Cogeneration potential and the City's cogeneration policy are examined in Section VIII.Certain revisions to the cogeneration policy are appropriate as set forth in Section VIII. An evaluation of the proposal of Energy Stream,Inc.to the City to develop the Pyramid Creek Hydroelectric Project and sell its electrical output to the City was made.The results of this evaluation were forwarded to the City in a letter dated August 1,1985.Based upon our evaluation,the poten- tial savings in fixed and variable costs of the City do not support the mini- mum contract rate of 18 cents per kWh offered by ESI.Section IX provides details of our analysis of the ESI proposal. RECOMMENDATIONS Based on the studies and analyses outlined in this report and subject to the amplifications and qualifications included in the report,our recommendations are as follows: 1.The City should adopt rates which would distinguish between five groups of customers:Residential,Small General Service,Large General Service,Industrial,and Street Lighting. 2.The City's electric rates should have a basic customer charge and energy charge,and for the Large General Service and Industrial customers,a demand charge."The Industrial Rate should include an optional interruptible feature."£208 AnD 3.The City should proceed with programs to attempt to add additional load,at least to a level supportableby existing generation capa-bility.\The City should determine if grant-funds”or low-cost loan funds areavailableforinstallationofpiping'to use?waste heat for heatingpurposesattheairportterminalbuilding.aNTheCityshouldmakecertain,Fevisions.to its'cogeneration policy.Seer ocdTheCityshouldreject the proposal advanced by Energy Stream,Inc.The City should.attempt .to negotiate with ESI an acceptablepriceandtermsfor'purchase 'of fhe.output of a potential hydro-electric facility.SSASS 7,nAayON|7 |ar THIS PRELIMINARY DRAFT iS SOLELY THE PROPERTY OF R.W.BECK AND ASSOCIATES.NOT AVAILABLE FOR GENCRAL RELEASE UNTIL AUTHORIZED ey R.W.BECK AND ASSOCIATES . POUCH 89 oe .'LETTER OF TRANSMITTAL UNALASKA,ALASKA 99685 ATI BNO."FE Of2 235 °ATTENTION ;meECETVEDVFROM:ADMINISTRATION L PARKS,CULTURE &va L__]FROM:PUBLIC SAFETY LJ PUBLIC WORKS RE TO aye wee poreen puuTemTy GENTLEMEN:WE ARE SENDING YOU 1 snoches [J Under separate cover via __the following items: 0 Shop Drawings OO)Prints OC Plans CJ Samples OO Specifications C Copy of letter (0 Change order O COPIES DATE NO.DESCRIPTION THESE ARE TRANSMITTED as checked below: oO For Approval OC Approved as submitted OO)Resubmit___-copies for approval For your use CO Approved as noted C)Submit copies for distributionwksrequested.CO)Returned for corrections CO)Return corrected prints OO For review and comment Oo 0 FOR BIDS DUE CJ PRINTS RETURNED AFTER LOAN TO USREMARKSArcs26"WEVA,Lief beg "Bleck -Lo Chte go AL!YeaeelLad2che.LYEL Li Gorter ee en.Ht pth.Lael alee.Lt Lh en COPY TO _SIGNE LLLLa If enclosures are not as noted,kindly notify us at once. SECTION IT BUS BAR GENERATION COSTS INTRODUCTION AYTheCityiscurrentlyintheprocess of \transferring all of itspowergenerationcapabilitiestoanewpower/facility."The new power facilitylocatedinthecommunityofDutchHarboris«a \yenovated U.S.Navy powerhouseinwhichtheCity's diesel generation "equipment...is being installed.ThebuildingwillhouseanewCaterpillar,3516 'diesel generator rated at 1,430kilowattswhichhasbeenprovidedtotheCity'by "the Caterpillar Company for atwo-year test period,a 600-kW diesel'-generator and a 300-kW diesel gener-ator.The City plans to overhaul and move the City's two other 600-kW dieselgeneratorsfromtheircurrentlocationsin,'the community of Unalaska as soon asthenewpowerfacilityising.,*.*,e new po yi operating au,aanON.|The pur pose of *'this,'section of thé study,'is to determine the fullyallocatedgenerationcostsof»the”"new power"facility..Included in this sec-tion is a detailed breakdown «of ,the City's”generation costs for fiscal years1985-1986 and 1986-1987.a y”'sy YY >ceeay?',ae :a ™7 a e*..: ;6 an mow £wy %SOae woosMETHODOLOGY...." 'Ne 8 AN ss So----ee a a,*,%;a fr a,NN *A an ""ay An.¢Ae .Generation costs at the,bus'bar include all costs associated withtheactualproductionofelectricpowerandsupplyingittothetransmission or distribution 'system.The largest single expense of the City relative to power generation is fuel.A significant reason for the City deciding to move its\power generation facility from the community of Unalaska to the community of Dutch Harbor was that the new facility will have a lower fuel supply cost.This lower supply cost will result from being closer to the supply dock and amorecompetitiveenvironment.:°For the past year,fiscal year 1984-1985,thepricepergallonofdieselfuelhasbeenbetween$1.02 and $1.05.At the new facility the City expects to be able to purchase diesel fuel for $.90 per gallon or less.This lower fuel cost coupled with the higher fuel efficiency of the new generating unit is expected to reduce the City's fuel costs.The base case fuel costs for this study were determined assuming an average fuel price for the yaer of $.90 per gallon and an average efficiency of 12.5 kWh per gallon resulting in a fuel cost per gallon of $.0720.With an assumed generation level for fiscal year 1985-1986 of 4,211,578 kWh,fuel costs were estimated to be $303,234.For fiscal year 1986-1987 fuel costs were estimated to be $321,428 with generation of 4,464,272 kWh. In addition to fuel costs direct power generation costs include labor and material costs associated with the actual operation and maintenance of the generating units.These costs are taken directly from the City's oper- ating budget and are estimated to be $239,098 for fiscal year 1985-1986.Our estimate for the following year raises these costs to $263,000.THIS PRELIMINARY DRAFT IS SOLELY Fully allocated generation costs »include more than just fuel andgeneratoroperationandmaintenance'costs.To ,these,costs must be added costsofadministration,inventory,Cdebt>services'building”'maintenance,parts per-sonnel,capital equipment,.and,renewalcand,replacementsi While some of these BY R.W.BECK AND ASSOCIATES. II-2 costs can be allocated solely to the power production function others should also be allocated to the other functional categories of the City's electric system,including distribution and customer services.Debt service costs of $44,000 were allocated in total to the power production function for fiscalyear1985-1986 because those costs are entirely attributable to debt incurredinconnectionwithapowergenerator.For /fiscalsyear 1986-1987 $44,000 ofdebtservicecostswereallocatedtotheproduction"function with the other$11,000 allocated to the distribution "function,'"y This allocation to thedistributionfunctioncorrspondstothe"City!8 need to pay interest costs onthe34.5-kV system to the Alaska Power"Authority.,*"OA,BeRenewalandreplacement«costs,"$80;000 for both years,were alsoassignedentirelytothepower,production .function.These costs represent theexpensesexpectedtobeincurred*'in -the \overhaul of the City's two existingoperating600-kW diesel generators;"the moving |"ef those units to the newfacilityandtheirinstallation,"Thus,all«those.costs |_are attributable tothepowerfacilityandthe''generation of electricity: ”LNsakSSeWw\YMASSs ayThoseelectric"system costs that are."only partially allocated tothepowerproduction':function include ;City administration,electric systemadministrative-and-,general,central'"services,''parts personnel,buildingmaintenanceandelectricsysteminventory.*These costs were functionalized inproportionto.the functionalization.of all other electric system costs exclud-ing fuel expenses. .This methodology 'assigns these joint costs to all func-tional categories,and insures that "each function bares a portion of these costburdens."ey RESULTS Below is a summary table of the bus bar costs at the City's new power facility for fiscal years 1985-1986 and 1986-1987.A more detailed itemization of the specific costs is presented on Table II-]at the end of this section.Each of these tables gives both the total functionalized costs and the per kilowatt-hour costs.The per kilowatt-hour costs are based on a peak of approximately 1.2 megawatts and generation of 4,211,578 kWh for fiscal year 1985-1986 and a peak of approximately 1.26 megawatts and generation of 4,464,272 kWh for fiscal year 1986-1987. Fiscal Year 1985-1986 Fiscal Year 1986-1987 Amount Cents per kWh Amount Cents per kWh Operating Expenses: Power Production - Fuel eeeeseeoceonvneneonse¢0 $303,234 7.20 321,428 7.20 Other wosvesccsccece 239,098 5.68 263,000 5.89 Overheads wecscccccsece 176,859 4.20 190,732 4.27 Debt Service eevee cese Tis-44,000.ARY Gr 11.045 SOLELY 44,000 099CapitalEnditBese102,690 5 89,076 2.00P*penee care THT Taw cetY OF RUN TOCCK AND Total Power Production .45:$865,881 NOT 20-56.8.6 FCK $908,236 20.34 GENERAL RELEASE UNTIL AUTHORIZED EY &OW.BECK AND ASSOCIATES. II-3 With respect to the above costs,it should be noted that fuel costs are variable,while the other costs are for the most part fixed.That is, fuel costs will vary with the level of generation while other costs will not. \ THIS PRELIMINARY DRAFT 1S SOLELY THE PROPERTY OF R.W.BECK AND ASSOCIATES NOT AVAILABLE FOR GENERAL RELEASE UNTIL AUTHORIZED BY R.W BECK AND ASSOCIATES. TABLE II-1 CITY OF UNALASKA - POWER PRODUCTION COST UNITS AsLine.Fiscal Year 1985-1986 Fiscal Year 1986-1987 No.Description Total Unit 'Costs Total Unit Costs OPERATING EXPENSES:gS).6?1 City Administration 16,796.tio Bertcents/kWh -17,692 0.40 cents/kWhElectricSystem:SAM2Administrative&General 111 386.{NR oa "seats /kuh 118,066 .2.64 cents/kWh 3 Central Services 25,224 _0.60°cents/kWh 26,357 0.59 cents/kWh4PartsPesonnelLs473°.0.25 cents/kWh 10,77 "0.24 cents/kWhPowerProduction:os NN,ava 5 Fuel c 303,236.?7.20°cente/kWh 321,428 7-20 cents/kWh6Otheroo23909853"§8.segnte/¥an .263,000 5.89 cents/kWhLineRepair&Maintenance?>a were7PrimarySOY"<$.00°esnes /xwn ©0 0.00 cents/kWh 8 Secondary Pe oa 0 NO 00 "cents/kWh ©0 0.00 cents/kWh 9 Automotive Repair.and.anaes "ony.NOMMaintenance .SAS on,=.0.00 cents/kWh 0 0.00 cents/kWh 10 Engineering Equipment Repaie "On aFandMaintenance..."y SSO NO.00 cents/kWh 0 0.00 cents/kWh 11 Meter Reading }*\*,"0!0.00 cents/kWh 0 0.00 cents/kWh 12 Building Maintenance 53 952 .0.14 cents/kWh 6,126 0.14 cents/kWh. 13 Electric System Inventory a Increase °7,028 «0.17 cents/kWh 11,714 0.26 cents/kWh 14 Debt Service 44,000 1.04 cents/kWh 44,000 0.99 cents/kWh ° 15 TOTAL OPERATING EXPENSES .763;191 18.12 cents/kWh 819,160 18.35 cents/kWh CAPITAL EXPENDITURES: Line Construction: 16 Primary 0 0.00 cents/kWh 0 0.00 cents/kWh 17 Secondary 0 0.00 cents/kWh 0 0.00 cents/kWh 18 Capital Equipment 22,690 0.54 cents/kWh 9,076 0.20 cents/kWh 19 Renewals and Replacements 80,000 1.90 cents/kWh 80,000 1.79 cents/kWh 20 TOTAL CAPITAL EXPENDITURES 102,690 2.44 cents/kWh 89,076 2.00 cents/kWh 21 TOTAL REVENUE REQUIREMENT 865,881 20.56 cents/kWh 908,236 20.34 cents/kWh Fiscal Year 1985-1986 Generation =4,211,578 kWh Fiscal Year 1986-1987 Generation =4,464,272 kWh THIS PRELIMINARY DRAFT IS SOLELY THE PROPERTY OF R.W.BECK AND ASSOCIATES NOT AVAILAELE FOR GENERAL RELEASE UNTIL AUTHORIZED BY Rh.W BECK AND ASSOCIATES SECTION III RATE REQUIREMENTS INTRODUCTION This section of the study is comprised of two major subsections which follow a discussion of the purpose and goals of this section.The first is the cost of service subsection containing a discussion of basic cost of service principles and the class cost allocation methodology utilized in this study.A summary of results is also given showing customer class cost responsibilities, The other subsection deals with rate design.The rate design sub- section contains a discussion of each of the City's current customer classes and applicable rate schedule.An explanation of the proposed rate classes, Residential,Small General Service (non-demand metered),Large General Service (demand metered),Industrial and Street Lighting,is given with appropriate recommended rate structures, PURPOSE AND GOALS The purpose of this section of the study is to analyze the City's cost of operating the electric system to serve its customers.The City's current rate schedules were reviewed with revisions being recommended,if appropriate.The cost analysis was made based on the operation of the new power facility,estimated costs for fiscal year 1986-1987 and an estimated peak in fiscal year 1986-1987 of 1.26 megawatts. The first goal of this section of the study is to allocate the costs of operating the new power facility and the new primary distribution system to customer classes in accordance with customer load characteristics. A second goal is to design rates that would reflect the costs to serve the various customer classes.Recommended customer class revisions and rate design changes are intended to enable the City to collect the revenues neces- sary to operate its electric system and to reflect costs incurred in serving the customer classes. Another goal of this section is to design rate schedules that would be appropriate for large power users should the City determine it would be inits\best interests and the present customers best interests to add such customers to the electric system.Such a rate is to reflect the size of the customers,power supply costs associated with serving those additional custo- mers,and revenue and benefits accruing to the system as a whole.) COST-OF-SERVICE METHODOLOGY The purpose of a cost-of-service study is to determine the cost to serve each of the City's electric customer classes or rate groups.The cost- of-service study allocates a portion of the revenue requirement to each class I1I-2 of customer.The results of such a study provide a guideline as to the amount of revenues which should be recovered from each customer class. An estimate of the City's revenue requirements for fiscal year 1986-1987 was prepared based on the City's fiscal year 1985-1986 operating budget.Table III-1 has been prepared which shows a comparison of the City's fiscal year 1985-1986 operating budget to the City's estimated revenue requirements for fiscal year 1986-1987 as used in this study.Except for fuel costs and debt service,fiscal year 1986-1987 costs were increased from the fiscal year 1985-1986 operating budget amounts_to_allow for inflationaryeffects.(Fuel costs were estimated by applying the estimated fuel cost_perCkilowatt-hour of 7,2 centstotheestimated generation levelS”Debt serviceincludesanamountfordebtincurredinconnectionwithpowergenerationand interest expense on the loan for the 34.5-kV line. The primary line construction account was not adjusted in antici- pation of line construction work corresponding to the addition of industrial customers.Line extension costs totaling $768,659 have been estimated for the six potential customers listed on Table V-l,whereas the primary line con- struction budget figure is $112,931 for the fiscal year 1985-1986 operating budget and estimated at $115,000 for fiscal year 1986-1987 for purposes of rate requirements.The 1.2 MW load level assumed for purposes of this study represents the addition of one or two large new loads depending upon which loads are added (Universal Seafoods is an exception because of its large size).The capital expenditures would probably be between $100,000 and $200,000 for line extensions to add this level of new load.If required expenditures for line extensions exceed the amount available from revenues, funding would have to come from other sources such as customer contributions, state grant funds,or additional debt.Should additional debt be required, rates may have to be adjusted to pay for the additional debt service. The 1986-1987 fiscal year was chosen as the test year for the cost-of-service study and rate design to allow the proposed rates to be in effect during the study period.Cost classifications and allocations have been made which are indicative of the cost of providing service to the various types and classes of customers, In the preparation of a cost-of-service study,the first step is to functionalize the projected revenue requirement.The functionalization proc- ess arranges the costs according to functional categories (i.e.,power produc- tion,distribution,customer accounts and capital costs). Following functionalization,estimated revenue requirements are classified to the demand,energy and customer cost components.These cost components are described as follows: 1.Demand Costs Demand costs are those costs associated with meeting the peak demand of the utility customers. 2.Energy Costs -Energy costs are those costs associated with meeting the electric use requirements of the customer."y III-3 3.Customer Costs -Customer costs are those costs which are expected to vary with the number of customers on the system. After the elements of the expenses are classified to cost compo- nents,an allocation is made to the City's customer classes.This study is based on the customer class designations proposed herein.These classes are: Residential,Small General Service (non-demand metered),Large General Service(demand metered),Industrial and Street Lighting.| A coincident peak method was selected for allocation of the demand components of the revenue requirement except secondary line construction which was allocated on the basis of non-coincidential peaks excluding industrial customers.Customer class demands were estimated by applying assumed load factors to the kilowatt-hour sales figures for each class.The assumed load factors were based on system usage and peak data,data from other studies,and a general knowledge of relative customer class characteristics. The demand component is comprised of the demand-related expenses from power production,debt service,functionalized overhead expenses and capital expenditures,The method used in this study allocates demand-related costs to customer classes on the basis of the estimated annual coincident or non-coincident peak demand for each class.The annual estimated peak demand allocation method was selected based upon load data available for this study. Energy-related costs were allocated based on the estimated annual energy requirements in kilowatt-hours of each customer class.The energy component is comprised of expenses from power production (e.g.,fuel),line repair and maintenance and functionalized overhead expenses. Customer costs were assigned to classes of service on the basis of the number of customers weighted to reflect cost differences in each class. Expenses contained in the customer component come from meter reading and functionalized overhead expenses. The demand,energy and customer allocation factors used in this study are presented on Table III-2.The allocations of the functionalized and classified costs to the customer classes are shown on Table III-3. COST-OF-SERVICE RESULTS Based on the cost components and allocation factors described in this section,the estimated cost to serve each customer class has been devel- oped for the 1986-1987 test year.The cost -of-service study results for the City are highly dependent on the assumed amount of incremental industrial load added to the system.As additional load is added the City is better able to utilize its installed capacity and spread its fixed costs over a larger base, reducing per unit costs for all customer.classes.- ITI-4 Table III 4 shows the results of three different assumptions regarding the amount of additional industrial load and an assumed variable cost of 7.6 cents per kilowatt-hour.The three load assumptions were: (1)768,500 kWh industrial sale (total generation 4,464,272 kWh); (2)1,590,000 kWh industrial sales (total generation 5,310,417 kWh;and (3)2,650,000 kWh industrial sales (total generation 6,402,217 kWh).The first case assumption corresponds to the loads,generation level and costs used in the cost allocations and rates designs proposed herein.With variable costs of 7.6 cents per kWh the system's average rate under the first assump- tion is 30.26 cents per kWh.If the total generation level is raised to 6,402,217 kWh as in the third assumption the system's average rate drops to 23.39 cents per kWh.Comparing the results of those two assumptions also shows the average industrial rate dropping from 29.04 cents per kWh to 22.33 cents per kWh. For the purposes of this study the industrial sales level of 768,500 kWh was chosen.As mentioned earlier,this represents the addition of one or two large loads to the system.This level is believed to be a little on the conservative side reflecting the reality that the City must attract these loads before it can realize the associated benefits for its customers. The following table summarizes the allocated cost-of-service for each proposed customer class and indicates the percentage which each class represents of the City's total allocated revenue requirement. Allocated Cost-of-Service Customer Service Amount Percent Residential eecoeveorereecon $479,497 37.1% Small General Service ....240,324 18.62 Large General Service ....339,216 26.3% Industrial eeoespeeceooeosvseeeee8 223,143 17.32 Street Lighting ....ceeees 8,747 0.72% Total eeeeoeeseoeeseeeeeeve8 $1,290,928 100.0% CURRENT RATE STRUCTURES A product of the cost-of-service study is unit cost data for each customer class by cost component.For the City these data are shown on the bottom of page 2 of Table III-3.These unit cost data are used in the rate design process as guidelines for the level and structure of the individual customer class rate schedules.However,any rate change under consideration may or may not be based strictly on a cost-of-service requirement depending on the policies and goals of the City.Other factors to be considered are rate relationships between customer classifications,revenue stability and relia . bility,existing rates,and for the City,incentives to attract additional III-5 industrial type load over which it may spread its fixed costs thus reducing its per unit costs to all its customers. The City currently has two rate schedules.Schedule A applies to Residential and Commercial and Small Power Service with single-phase or three-phase service at secondary voltage.The published energy rate structure has four usage rate blocks,however,since each rate is the same (i.e., 34 cents per kWh)it essentially is a flat.rate structure with a $10.00 per month minimum. Schedule B,applicable to industrial and large power users taking three-phase service at the City's standard voltage,has a blocked energy rate structure with no demand charge.However,like Schedule A,all blocks are priced at the same rate (i.e.,34 cents per kWh)making it also a flat rate. The minimum is $55.00 for 50 kVA or less of transformer capacity with a $1.00 additional charge for each additional kVA of transformer capacity.All City and community facilities are billed at the universal City rate of 34 cents per kWh and are not treated separately for billing or record keeping purposes. Since all of the City's energy sales are made at a rate of 34 cents per kWh no differentiation is maintained in the billing records as to the type of account or service.While such a tariff system is easy to administer and understand,it does not allow for the reality that the service requirements for different types of customers do vary and similarly the costs to serve those various customer types vary.Differentiated billing records can also provide a useful source of load and usage characteristics by customer type for use in future analyses. PROPOSED RATES An analysis of the City's monthly billing records shows that the City currently serves three basic types of customers;residential,small com- mercial and large commercial.With the City's electric system expansion plans anticipating growth of the electric system by adding the loads of larger industrial type customers,the City should have a separate rate schedule for large industrial type loads.Therefore,separate rate schedules applicable to each of these customer types with an additional schedule for street lighting are recommended in this report.The new rate schedules would be for Resi- dential,Small General Service,Large General Service,Industrial and Street Lighting.Additionally,the industrial rate schedule includes an interrup- tible provision,Following is a discussion of each of these schedules includ- ing a description,rate structure and rate level. Residential Service The proposed residential rate would apply to only those customers taking electric service for domestic purposes.This would include single and multi-family residences and trailor parks.The current rate's four energy rate blocks would be eliminated and replaced with just a single flat energy III-6 rate.Essentially there would be no difference in rate structure,however, since the current charges are the same for each rate block.Eliminating the blocking structure should remove any confusion or misconception of the present structure. The City currently charges its residential customers at a rate of 34 cents per kWh for all kilowatt-hours consumed with a $10.00 per month mini- mum charge.Under the proposed residential rate the City would charge its residential customers 29.5 cents per kWh for all kilowatt-hours consumed.To this energy charge would be added a customer charge of $10.00 per month which would also be the monthly minimum bill. The current and proposed residential rates are shown below.A residential bill comparison comparing the present rate to the proposed rate is presented on Table III-5.Note that an equal allowance has been given to each bill for State of Alaska energy assistance. Residential Present Schedule A Proposed Energy Charges:Energy Charge: First 200 kWh -$.34/kWh All kWh -$.295/kWh Next 300 kWh --34/kWh Next 600 kWh --34/kWh Customer Charge: Over 1,200 kWh --34/kWh Each Customer -$10.00/month Minimum Charge -$10.00/month Small General Service The customers that fall into this category the City currently bills under Schedule A along with its residential customers.These customers include small commercial and other small power users who take service for other than domestic purposes.The rate structure of Schedule A was explained in the discussion of the Residential rate.The proposed Small General Service rate would apply to commercial customers with less than 30 kW of demand and would not require demand metering.The rate structure applicable to these customers would not vary in structure from the current applicable rate in that all kilowatt-hours would be charged the same rate with no demand charge.A different feature for this rate from the current rate would be the inclusion of a customer charge similar to that in the Residential rate. The proposed Small General Service rate would have the City charge its commercial and small power users (under 30 kW demand)a uniform energy charge of 30.5 cents per kWh for all kWh consumed and a monthly charge of $12.00.The monthly charge would also serve as the minimum charge.For a IiI-7 comparison of customer bills computed using the present Schedule A and the proposed Small General Service rate refer to Table III-6 at the end of this section. Small General Service Rate Customer Charge $12.00 per month Energy Charge (all kWh)=<:-.$0.305 per kWh Large General Service These customers are currently billed by the City under Schedule B. As explained earlier Schedule B is comprised of five energy rate blocks (all the rates at these five levels are the same,however,at 34 cents per kWh) with no demand or customer charge.The rate proposed herein is a three-part rate,a customer charge,a demand charge and an energy charge.A three-part rate for these customers allows them to pay for their requirements how theyareneededandastheyareneeded, The charges proposed for this customer class are given below with a bill comparison table presented on Table III-7 at the end of this section. This rate would only be applicable to those customers of the City whose demand exceeds 30 kilowatts but is less than 100 kilowatts (those over 100 kilowatts would be billed under the Industrial rate schedule).This rate would also have a demand ratchet feature which would set the billing demand at a level equal to 75%of the customer's highest demand over the previous eleven months.This feature would help to insulate the City from the affects of customers who might place a large demand on the system for only a short period of time for which the City would have to install and maintain capacity.It should be noted that since demand meters are not installed,demand charges were calculated using estimated demand billing units.After some experience is gained with the demand meters installed,the demand charge level should be reviewed. Large General Service Rate Customer Charge .escecsseccsees $50.00 per month Demand Charge (all kW)weceooee $15.00 per kW Energy Charge (all kWh).......$0.242 per kWh Such a rate structure will require the City to install demand meters on those customers to which this rate will apply.In the interim until demand meters are in place for these customers the City could bill them under an interim Large General Service rate comprised of a customer charge ($50.00 per month)and an energy charge (28.7 cents per kWh).Currently the City serves only six or seven customers that might fall into this customer category so the additional metering requirements should not be prohibitive.The interim Large General Service rate is shown below. IItI-8 Large General Service Rate (Interim) Customer Charge seccscscsesscee $50.00 per month Energy Charge (all kWh).......-$0.287 per kWh Industrial Service . The City does not now have a separate industrial rate class or structure.This new rate class and structure,as proposed,would apply to large power users (i.e.,over 100 kW of billing demand).None of the City's current customers would qualify for this rate.The idea behind this rate and its structure is to provide a customer category in which to put,and a rate structure under which to charge,the large power users the City has identified as possible additions to its system.Each of the identified large power users currently have their own generation source.Also in this class would fall any large power users that might come to the area that do not have or would not have another source of electric power. The proposed rate structure for this class would be a three-part rate similar to that proposed for the Large General Service class.It would have a customer charge to recover metering and billing costs,a demand charge to recover fixed demand related costs and an energy charge to recover the remaining costs.The demand charge would have a 75%of the highest previous eleven month's billing demand ratchet feature like the Large General Service rate.The rate structure and proposed rate levels for this proposed new rate classification are shown below. Industrial Rate Customer Charge ceccscsccvsccecs $100.00 per month Demand Charge (all kW)....ce0e $25.00 per kW Energy Charge (all kWh)....eee $0.195 per kWh The above rate was developed using estimated billing data.After some experience with new large loads is gained,the rate level for these customers should be reviewed. We have also developed an interruptible service provision in con- junction with this rate schedule.If a customer can be served on an interrup- tible basis that customer would only pay the customer and energy charges.Theinterruptiblerateisshownbelow. III-9 Interruptible Rate Customer Charge .scccccceaceccs Energy Charge (all kWh)....0.- $100.00 per month $0.195 per kWh Street Lighting . The City does not have a street lighting rate but charges for street lighting service on a fixed basis.Since it is anticipated by the City that it will be installing more street light fixtures,a separate Street Lighting rate should be established that charges for street lighting services on a per fixture basis.Such a billing structure would allow street lights to be added to the system as they are needed and allow the City to bill for their usage as theYcome on line.The City only has 175 watt mercury vapor lamps anddoesnotforeseeanychangesinitspracticeofusingonlythatsizeandtype of fixture.The proposed Street Lighting rate,therefore,has only one charge,a fixed per-month per-fixture charge of $15.00.This charge would cover the average energy costs of operating the light,allocated system costs, and operating and maintenance costs associated with the street lighting services. Street Lighting Rate 175-Watt Mercury Vapor Street Lights ..ccccscccsccce $15.00 per month per fixture Revenue Summary at Proposed Rates Based on the sales and customer estimates used in the allocation process of the cost-of-service study,the table below presents the revenues to be expected from the proposed rates.These revenues are shown by proposed customer class and are compared to the allocated customer class revenue requirement as determined in the cost-of-service study. Customer Class Allocated Costs Revenues Residential eeeeeeseneesenen $479,497 $481,659 Small General Service ....240,324 241,545 Large General Service ....339,216 340,792 Industrial eeeenvoaoeseecoaneoe eee 223,143 219,058 Street Lighting ...cescece Total eeenesenseevorese 8,747 $1,290,927 10,800 $1,293,854 III-10 The Scope of Services for this section of the study specified that future rate requirements should be projected for the new system based upon a base load of 1.2 MW.Such a base load assumes the addition of some industrial load.It should be recognized,however,that if no new industrial customerswereaddedtothesystemandnoincrementalindustrial(or interruptible) sales were made,the City could be faced with a revenue shortfall if the rates developed in this section are implemented.The following table shows an esti- mate of how such a situation might impact the City's costs and revenues. Customer Class Allocated Costs Revenues Residential eeseeseesoveee28000 .$479,497 $481,659 Small General Service ....240,324 241,545 Large General Service ....339,216 340,792 Industrial @eeeveeoecevoeevon een ne 166,151 0 Street Lighting ...cseceee ,8,747 10,800 Total eeeceecoaoeveaeesea seen ee "$1,233,935 $1,074,796 The above table shows that $166,151 of fixed costs are allocated to the industrial class while no revenues are recovered.The City's revenues would be $159,139 below costs in this scenario which assumes the addition of no new industrial load.The rates proposed in this section would have to be adjusted upward to recover this revenue shortfall should no new industrial load materialize. It should also be recognized that in calculating revenues under the proposed rates,we have assumed that all new industrial load would be firm load rather than interruptible load.We have developed an interruptible rate in this section and some industrial customers may find such a rate advan- tageous.If significant amounts of interruptible load develops rather than firm industrial load,then revenues will be less than shown in the above table.For example,if all of the projected industrial load developed as interruptible load rather than firm load,industrial revenues would be $154,058 rather than $219,058.Rates of other classes would have to be adjusted upwards to recover this revenue shortfall. 15 16 i7 1g 19 20 21 CITY OF UNALASKA REVENUE REQUIREMENTS OPERATING EXPENSES: CITY ADMINISTRATION ELECTRIC SYSTEM ADMINISTRATIVE AND GENERAL CENTRAL SERVICES FARTS PERSONNEL POWER PRODUCTION FUEL OTHER 4 LINE REPAIR AND MAINTENANCE PRIMARY SECONDARY AUTOMOTIVE REPAIR AND MAINTENANCE ENGINEERING EQUIFMENT REPAIR AND MAINTENANCE METER READING BUILDING MAINTENANCE ELECTRIC SYSTEM INVENTORY INCREASE DEBT SERVICE (1) TOTAL OPERATING EXPENSES CAPITAL EXPENDITURES: .LINE CONSTRUCTION PRIMARY SECONDARY CAPITAL EQUIPMENT RENEWALS AND REPLACEMENTS TOTAL CAPITAL EXPENDITURES TOTAL REVENUE REQUIREMENT FY 1985-1986 OPERATING BUDGET. 23492 155793 o5260 22352 332557 239098 31637 ZE454 19119 9085 8905 13117 9TESSI 112931 46077 11€5897 Table III-1 PROJECTED FY 1996-1987 REVENUE REQUIREMENT' 163500 36500 23000 321423 263000 33500 25000 9500 10000 13500 25000 55000 1025728 115000 50000 1290926 KWH SALES FY 1985 GROWTH (ADDITIONS) KWH SALES FY 1996 GROWTH KWH SALES FY 1987 LOSS FACTOR KWH GENERATION ENERGY FACTOR -E LOAD FACTOR NONCOINCIDENT DEMAND NCD FACTOR -Di COINCIDENCE FACTOR COINCIDENT DEMAND CD FACTOR -D2 CUSTOMER-MONTHS WEIGHTING FACTOR WEIGHTED CUSTOMERS CUSTOMER FACTOR -C en ery 516 0.4512 0.9 464 0.3696 3750 0.6511 CITY OF UNALASKA DEVELOPMENT OF ALLOCATION FACTORS 1.50 0.1497 & LARGE GENERAL, SERVICE "=1109654 6.00%> 1175173 5.00% Soyer"2764 "0.40 27 erry 0.0112 0.5 INDUSTRIAL 4024836 4266326 4.64% 4464272 1.0000 0.36 1403 1.0000 1256 1.0000 5159 5760 1.0000 c IIIOT9PL LINE NooCITY OF UNALASKA REVENUE REQUIREMENTS BY CUSTOMER CLASS SMALL LARGE GENERAL,GENERAL STREETDESCRIPTIONTOTALRESIDENTIALSERVICESERVICELIGHTS INDUSTRIAL BASIS OF ALLOCATION OPERATING EXPENSES: CITY ADMINISTRATION (1) ENERGY FES 3526 1802 2752 112 1766 ENERGY DEMAND 13328 4926 Z517 32464 36 2434 DEMAND -D2 CUSTOMER 1214 790 182 152 2 89 CUSTOMER SUBTOTAL 24500 9243 450t 6269 150 4338 ELECTRIC SYSTEM ADMINISTRATIVE AND GENERAL (1) ENERGY 66455 23833 12025 13468 .746 11783 ENERGY DEMAND 83944 32375 16798 22452 243 16577 DEMAND -D2 CUSTCIMER 8100 5274 1213 1013 10 591 CUSTOMER SUBTOTAL 163500 61682 30036 41833 999 2e761 CENTRAL SERVICES (1). ENERGY 14836 5254 2684 4101 166 2620 ENERGY DEMAND 19856 T1329 3750 5012 54 3701 DEMAND -D2 CUSTOMER 1808 LIT?271 226 2 132 CUSTOMER SUBTOTAL 36500 13770 619%9339 223 6463 PARTS PERSONNEL (1) ENERGY 9343 3311 1692 28e4 105 1658 .ENERGYDEMAND125124€25 2363 3153 34 233Z DEMAND -02 CUSTCHER 1140 T42 iv!142 |1 83 CUSTOMER SUBTOTAL 23000 8677 4225 505 140 4073 POWER PRODUCTION FUEL 321428 113825 58161 88343 3606 56992 ENERGY OTHER -ENERGY 65750 23284 11897 18173 733 11653 ENERGY DEMAND 197250 TZ905 37252 49791 $39 36762 DEMAND -D2 LINE REPAIR AND MAINTENANCE : PRIMARY 33500 11863 606Z 92389 376 5940 -ENERGY SECONDARY 28000 FAS 5067 1739 314 4965 ENERGY AUTOMOTIVE REPAIR AND MAINTENANCE (1) ENERGY T1926 ze07 1434 2191 89 1405 ENERGY DEMAND 10603 3921 2003 2673 /2 1977 DEMAND =D2 CUSTCMER 966 629 145 {21 "1 70 =CUSTOMER SUBTOTAL 19500 T3587 3582 49989 119 3453 ENGINEERING EQUIPMENT REPAIR AND MAINTENANCE (1)ENERGY :3861 13467 699 1067 43 685 ENERGY DEMAND 5168 1910 976 1305 4 963 DEMAND -D2 CUSTOMER 471 306 70 59 1 34 =CUSTOMER SUBTOTAL 9500 se4 1745 2431 58 14682 ZJO[aseg€-IIIeTqeL CITY OF UNALASKA REVENUE REQUIREMENTS BY CUSTOMER CLASS SMALL LAPGELINEGENERALGENERAL STREETNO.DESCRIPTION TOTAL RESIDENTIAL -SERVICE SERVICE LIGHTS =-s INDUSTRIAL BASIS CF ALLOCATION 2 METER READING 10000 és 1497 1250 13 729 CUSTOMER BUILDING MAINTENANCE (1) 30 ENERGY 5487 1943 993 1517 6 973 ENERGY 31 DEMAND 7344 2714 1387 1954 20 1269 DEMAND -D232CUSTOMER6694351008A149CUSTOMER 33 SUBTOTAL 13500 $093 2460 3454 62 2370 ELECTRIC SYSTEM INVENTORY INCREASE (1); 34 ENERGY 10161 3598 1939 2209 .ig 1902 ENERGY35DEMAND13600502725683433372535DEMAND -D2 3 CUSTCMER 1239 806 ics.ee ta*)a 2 90 CUSTOMER "ar SUBTOTAL 25000 9431 4593 6396 153 442738DEBTSERVICE5500020323103871358315010250 DEMAND -D2 i 39 .TOTAL OPERATING EXPENSES 1025928 377469 182191 -269535 THEO 183073 "”CAPITAL EXPENDITURES:a on __LINE CONSTRUCTION Poy ai40°PRIMARY 115000 42505 21719)29029 |314 21433 DEMAND -D2 re oo SECONDARY 50000 22562 11529.15409 500 _DEMAND -Di42".CAPITAL EQUIPMENT 20000 7392 3TT?5049 55 |3727 "DEMAND =D243RENEWALSANDREPLACEMENTS$0000 29569 15109 20194 219 «14910.DEMAND =D2 44>,TOTAL CAPITAL EXPENDITURES 265000 102028 52133 "69681 1088 40070 43 TOTAL REVENUE REQUIREMENT 1290928 AT9497 240324 339216 8747 223143 :”UNIT COSTS: 46 ENERGY -TOTAL S7é6711 204227 104354 159404 6470 102256 47 -CENTS FER KWH SALES 13.52 13.56 13.56 13.56 13.56 13.31 48 DEMAND -TOTAL 6seélt Z52898 132136 176612 2245 =:11902049-$PER KW NCD-MONTH 45.04 46.01 46.01 46.01 18.01 42.00 SO CUSTOMER -TOTAL 25606 16672 3834 3201 32 1867 51 >$PER CUSTOMER-MONTH 4.96 4.45 6.67 44.46 0.04 44.46 TOTAL -TOTAL 1290928 479497 240324 339216 8747 223143 7 PER KWH SALES 30.26 31.95 31.24 23.87 13.34 29.04 (1)CLASSIFIED ACCORDING TO OTHER OPERATING EXPENSES LESS FUEL 7:597aseg€-III°TqdeL CITY OF UNALASKA COMPARISON OF UNIT COSTS CENTS/KWH -Small Large Oe General General Street Assumptions Total Residential Service Service Lighting Industrial Variable Cost/kwh =$0.0760* en 4 -Fiscal Year Generation Level:. 4,464,272 kWh 30.26 31.85 31.24.28.87 18,34 29.04 fs 5,310,417 kWh 26.64 28.39 27,80 «25.74 16.81 25.37 3 >6,402,217 kWh 23.39 «25.26.«24,66 =22.89 «15,43 22.33 :|*Assumes $0.90 cents per gallon average fuel cost and 12.5 kWh per gallon efficiency..Y-III9T9?L Table III-5 CITY GF UNALASKA RESIDENTIAL BILL COMPARTSON -DIFFERENCE PRESENT PROPOSED USAGE BILL (1)EILL(2)AMOUNT _.PERCENT 0 10.00 10.00 0.00 0.00% 50 10.00 16.63 BBB 64.20% 100 17.76 23.26 . §.50 30.97% 200 35.52 26.52 1.00 2.62% 300 53.28 47.73 -3.50 -6.57% 400 71.04 .63.04 .*-,$8.00 11.26% £00 €S.60 -16.30 "12.50 -14.08% 600 106.54 87.56 17.00 |.-15.95% 750 133.20 107.45 cs -23.75 --17.20% $50 167.20 138.95 § .-28.25 -16.90% 1000 212.20 -W83B.Z0 eH 8G.00 -16.04% 1Z00 286.20 . 242.20 6 4.00 |-15.37% 1400 354.20 301.20 «+83.00 "14.96% 1600 422.20 340.20 os,-€2.00 -14.68% 2000 £85.20 476.20 _780.00 714.304 (1)PRESENT RATE:SCHEDULE A ENERGY CHARGE ; FIRST 200 KWH 34.00 CENTS /KWH NEXT 300 KWH 34.00 CENTS/KWH NEXT 600 KWH 34.00 CENTS/EKMH OVER 1200 EWH 34.00 CENTS/KAH MINIMUM $10.00 /MONTH COST EQUALIZATION RATE FIRST 750 KWH 16.24 CENTS/KMH (2)PROFCSED RESIDENTIAL RATE: CUSTUMER CHARGE $10.00 /MONTH ENERGY CHARGE ALL KH 29.50 CENTS/KAH COST EQUALIZATION RATE FIRST 750 KWH 16.24 CENTS/KH Table III-6 -CITY OF UNALASKA SMALL GENERAL SERVICE BILL COMPARISON DIFFERENCE PRESENT PROPCGED USAGE BILL (1)BILL(2)AMOUNT PERCENT 0 10.00 12.00 ©2.00 20.00% 100 17.76 26.26 -8.50 47,86% 200 35.52 40.52 5.00 14.03% 300 53,28 4.78 1,80.2.62% 500 88.80 re)6.19%750 133.20 2 MBG "14.25. 10.70% 1000 218.20,195,20.--23.00 10.54% 1250 303.20 2TLAS ws 931.75 10.47% 1500 338.20 347.70 < =40.50 10.43% 2000 -558.20 800.20...$88.00--10.39% 2500 728.20 652.70.*=75.50 10.37% 3000 898.200 805.20 .»93.00.10.35% 4000 1238.20 1110.20...=128.00 © 10.34% 5000 1378.20 1415.20 .-163.00 710.334 (1)PRESENT BILL:SCHEDULEA ENERGY CHARGE a FIRST 200 KWH 34.00 CENTS/KWH NEXT 300 KWH 34.00 CENTS/KWH NEXT &00 KWH -34.00 CENTS/KWH OVER 1200 KWH.34.00 CENTS/KWH MINIMUM FIRST 10 KVA $10.00 /KVA ADDITIONAL KVA $1.50 /KVA COST EQUALIZATION RATE FIRST 750 KwH 16.24 CENTS/KWH (2)PROPOSED SMALL GENERAL SERVICE RATE! CUSTOMER CHARGE $12.00 /MONTH ENERGY CHARGE ALL KWH 30.50 CENTS/KWH COST EQUALIZATION RATE FIRST 750 KWH 16.24 CENTS/KWH ° LARGE GENERAL SERVICE BILL COMPARISON CITY OF UNALASKA KWH BILLING PRESENT USAGE DEMAND BILL (1) 6000 27.4 1918.20 7000 32.0 2298.20850038.8 2768.20 10000 45.7 3278.20 12500 o7e4 4128.20 15000 68.5 4978.20 17500 79.9 5028.20. 20000 91.3 "»,6678.20 22500 102.7 .7328.20 » 25000 114,2 8373.20 27500 125.8 .9228.20 30000 137.0 10078.20 - 35000 159.8 11778.2040000182.6 13478.2045000205.5 13178.20 50000 228.3 16878,20 (1)PRESENT BILL:SCHEDULE B ENERGY CHARGE FIRST S00 KWH NEXT 1500 KWH NEXT 8000 KWH NEXT 190,000 KWH NEXT 200,000 KWH MINIMUM FIRST 10 KVA ADDITIONAL KVA COST EQUALIZATION RATE FIRST 750 KWH (2)PROPOSED LARGE GENERAL SERVICE RATES CUSTOMER CHARGE ENERGY CHARGE ALL KWHDEMANDCHARGE ALL BILLING KWoy : COST EQUALIZATION RATEFIRST750KH Table III-7 10795.46 16,24 CENTS/KWH $50.00 /MONTH 24.20 CENTS/KWH $15.00 /KW >): 16.24 CENTS/KWH DIFFERENCE PROPOSED BILL(2)AMOUNT-PERCENT 1791.16 -127.04 b.62h 2101.65. 156.55 6,93%, |2567.39 -200.81 "7.813033.13 -245.07 .7.48% 3809.36 -318.84 -7.72%"585.60 - 392.60 -7.89%, S361.83 466.37. 8.00% 138.06 $540.14 "8.09% 6914.30 ©-613,90 "8.15% «7690.53 687.67 -8..21% |8466.76 -761.44 8.2519242.99 835.21 -8.29% -982.74 8.34% *12347.93 1130,27 -8.39% 13900.39 1277.81 8.42115452.86 1425.34 "8.481 34.00 CENTS/KWH 34.00 CENTS/KWH 34.00 CENTS/KWH 34.00 CENTS/KHH 34.00 CENTS/KWH $10.00 /KVA $1.50 /KVA SECTION IV AVOIDED COST RATES INTRODUCTION The purpose of this section is to determine avoided cost rates for the electric system based on the operation of the City's new system (power facility and primary distribution)and a 1.2-megawatt system load.These avoided cost rates can then be used in the evaluation of resource acquisition proposals as well as load acquisitions.a METHODOLOGY An analysis of the City's avoided costs was prepared in conjunction with our evaluation of Energy Stream,Incorporated's proposal to the City for a hydroelectric project.That evaluation is included as Section IX of this report.In particular,the portion concerning the City's avoided costs is contained on pages 9 through 12..Fora complete description and explanation of the avoided cost methodology and principles please refer to that section. CONCLUSIONS Based on the analysis prepared for the hydroelectric proposal it is our conclusion that the City should use 7.6 cents per kilowatt-hour as its avoided cost rate for electric power.This rate would at least equal the City's estimated fuel costs per kilowatt-hour of 7.2 cents and allow a slight margin for other variable operation and maintenance expenses. Since the City currently has sufficient capacity in its new power facility the avoided capacity cost is zero.Additionally,if an avoided capacity cost rate were to be used,it would have to be determined for each specific case such as was done in the case of the ESI proposal.Absent special conditions,the avoided cost rate should be set at the avoided energy costs,or 7.6 cents per kWh. SECTION V ECONOMICS OF SYSTEM EXPANSION INTRODUCTION The City's electric system,with the new power facility having new and overhauled older generation units,has more than adequate generating capa- bility to serve its existing loads.The City,therefore,wants to know the expected costs and revenues associated with.system expansion.The expansion should be undertaken only if the net impact of such expansion would not be detrimental to the City's current customers, The incremental costs associated with the additional loads result mainly from greater fuel purchases and labor and material costs associated with the construction of the line extensions,Incremental revenues would result from sales to these customers.A benefit to existing customers from the addition of incremental loads would be the City's ability to spread its current fixed costs across a larger sales base.This would reduce all custo- mer's unit costs,providing the incremental fixed costs attributable to the new loads are not so large as to make the connection of these additional loads uneconomical. Within the two communities served by the City,Unalaska and Dutch Harbor,several industrial type loads exist whose electric power requirements are met with their own diesel generation.The City has identified these loads as potential customers for system expansion and,to the extent possible, surveyed these customers.From this survey,the Alaska Power Authority deter- mined 1983 and estimated 1984 loads for these customers for use in its Un- alaska/Dutch Harbor Reconnaissance Study published in April 1985.It was this load data that was utilized in conjunction with estimates of line extension distances for the cost and revenue estimates in this section. METHODOLOGY This section addresses basically three things.First,we examined whether or not the conditions set forth in the City's line extension policy would be met in adding specific new customers.Second,we examined the eco- nomics of adding particular customers.Third,we examined the net impacts on the City's other customer classes. The City's line extension policy for primary service (Section 10.08.110 -Extension of Facilities)for a distance of over 100 feet requires that the customer enter into a long-term contract.This section of the City's service policies also defines line extension economic feasibility as being determined by the City and based on gross revenues from additional sales in the first year of operation equal to or greater than the cost of the line extension. To determine if the conditions in the City's line extension policy would be met,line extension cost estimates were developed for several of the identified potential new loads.These cost estimates include labor and material costs for transformers,breakers,pull boxes,metering equipment, elbow connectors,fault detectors,transformer and breaker pads and cable. The total cost of each of the line extensions reflects Alaska labor and material multipliers and a 30%pricing and construction change allowance. Summary construction cost estimate sheets are included at the end of this section for line extensions to the following potential customers:Universal Seafoods,Pacific Pearl Seafoods,Pan Alaska Seafoods,Sea Alaska,East Point Seafoods,and American President Lines (note:these are the only customers for which sufficient data is available to make estimates). The Industrial rate developed in Section III of this study was applied to the potential customers'loads to develop a revenue estimate to compare to the line extension cost estimates.This comparison is presented on Table V-1.As that table shows,each of the customers would satisfy the con- ditions of the City's line extension policy if they were served on a firm power basis.If,however,these customers desire to be served on an inter- ruptible basis not all would satisfy the line extension conditions.To make that comparison,on Table V-l1 the demand revenues are subtracted from the customer revenues.The resulting revenues (energy revenues plus customer revenues)are then compared to the line extension costs.On an interruptible basis,Pacific Pearl Seafoods,Pan Alaska Seafoods and American President Lines would produce annual revenues less than the estimated line extension costs. The economics associated with adding these loads to the City's electric system can be examined by calculating the payback period for recovery of the City's investment in line extensions.This approach first deducts from the estimated revenues an amount equal to variable costs.In this case that amount would be the estimated annual sales times the variable costs of 7.6 cents per kilowatt-hour as determined in Section IV,Avoided Cost Rates. The net revenues are then divided into the estimated line extension costs to determine the number of years the customer would need to be served before the line extension is payed for.(Note:In this simplified approach no interest rate factor is assumed and no customer sales growth is assumed.) The results of the payback period calculations are shown on Table V-2.If firm power service is assumed,applying this approach to the City's identified potential industrial customers reveals a range of payback periods from approximately two months for Universal Seafoods to just over one year for Pacific Pearl Seafoods.These calculations are shown in the first column of Table V-2.If,however,these customers were served under the interruptible rate option the payback periods range from three months for Universal Seafoods to approximately two years for Pacific Pearl Seafoods,Pan Alaska Seafoods and American President Lines.The second column of Table V-2 shows interruptible rate results. As discussed previously in conjunction with the cost-of-service study assumptions,the City's and its customer's unit costs are sensitive to the total sales volume of the system.The City's per kilowatt-hour variable costs,expected to be 7.6 cents,are in the short run the City's only truly variable costs that directly vary with output...Other "variable"type costs may vary over longer periods of time (i.e.,operational personnel),but,in the short run,are not directly related to the level of plant output.The remainder of the system's average unit cost of 30.26 cents per kilowatt-hour is comprised of fixed costs.As sales increase,these costs are spread over more kilowatt-hours thus lowering the per unit costs. To show the impacts of increased generation levels of the City's other customer classes,the results shown on Table III-4 are reproduced below.These figures show that if the City's level of generation increases from 4,464,272 kilowatt-hours to 6,402,217 kilowatt-hours due to the addition of industrial loads,the average allocated cost to each customer class and the system as a whole decreases,It is assumed that the City's installed gener- ation capacity will be sufficient to serve these increased generation levels. We have not made any analysis to determine the impact on the City's of addingadditionalgeneration, Average Unit Costs in Cents per kWh Small Large General General Street Generation Level Total Residential Service Service Lighting Industrial 4,464,272 kWh 30.26 31.85 31.24 28.87 18.34 29.04 5,310,417 kWh 26.64 28.39 27.80 25.74 16.81 25.37 6,402,217 kWh 23.39 25.26 24.66 22.89 15.43 22.33 CONCLUSIONS As shown on Table V-l,based on the cost estimates and assumptions incorporated into this study,each of the identified industrial customers for which estimates were prepared would satisfy the City's line extension policy if served with firm power,At the firm Industrial rate each customer would provide gross revenues to the City over the first year of service at least equal to the estimated cost of the line extension.If,however,these custo- mers are served on an interruptible basis not all would satisfy the City's line extension policy conditions. Table V-2 shows the results of our payback period calculations assuming both firm and interruptible industrial rates.On a firm service basis all the customers examined show favorable payback periods of one year or less.On an interruptible basis the payback periods range up to two years, and therefore are still favorable,although less so than with the firm ser- vice.With a payback period of two years a potential customer should be reviewed more closely regarding its longevity §and revenue potential.The addition of industrial 'customers bringing large incremental. loads to the City's electric system would benefit the City's other customer classes,The magnitude of this benefit,however,is dependent on the size of the load or loads and the costs,if any,that are borne by the City.In addition,the City should examine carefully the additions of any load which would require added generation capacity. Based on the results of our analysis,the City should proceed with its efforts to connect additional loads.These loads and the system's costs, however,should be monitored as the loads are connected since as the system's total loads grow,the point is approached where additional generation may be required,The requirement for additional generating units will significantly change the system's cost patterns and,potentially,the advisability of attracting additional loads.The addition of the new large loads to the City's system may hinge on the ability of the new large loads to take service under an interruptible basis.The cost based firm Industrial Rate developed in Section III of this study may be too high for most customers to take firm service.Interruptible service,on the other hand,may be an attractive alternative since interruptions should be infrequent and not of long duration. CITY GF UNALASKA PROPOSED INDUSTRIAL RATE ENERGY CHARGE 90.195 PER KH DEMAND CHARGE $25.00 PER Ki CUSTOMER CHARGE $100.00 PER CUSTOMER-MONTH BILLING COMPANY DETERMINANTS UNIVERSAL SEAFOODS ENERGY 54100000 DEMAND 1,450 CUSTOMER '42. TOTAL PACIFIC PEARL SEAFOOO? ENERGY 400,000 DEMAND a 17S CUSTOPER :12 TOTAL PAN ALASKA SEAFOOOS ENERGY 800,000 DEMAND 350 CUSTOMER 12 TOTAL SEA ALASKA ENERGY 675 4000DEMAND300 CUSTOMER 12 TOTAL EAST POINT SEAFOOOS ENERGY $50,000 DEMAND 8s CUSTOPER 12 TOTAL AMERICAN PRESIDENT LINES ENERGY 600,000 DEMAND 1,250 CUSTOMER 12 REVENUES $994,500 362,500 1,200 _$1,358,200 :$78,000 #3,750 "$4200 $122,950 $156,000 87,500 44200 $244,700 $131,625 75,000 1,200 $207,225 $165,750 218,750 1,200 $325,700 $117,000 312,500 1,200 $430,700 TABLE V-1i LINE EXT. costs S144,728 S97,622 $191,129 586,469 $102,210 $146 502 COMPANY CITY OF UNALASKA CALCULATION OF PAYBACK PER TOO FOR SELECTED POTENTIAL INDUSTRIAL.CUSTOMERS TABLE V-2 UNIVERSAL SEAFOODS ESTIMATED REVENLES LESS3 VARIABLE COSTS NET REVENUES LINE EXTENSION COETS PAYBACK PERIOD PACIFIC PEARL SEAFOOOS ESTIMATED REVENUES LESS3 VARIAELE COETS NET REVENUES LINE EXTENSION COSTS PAYBACK PERIOD PAN ALASKA SEAFOQO0S _ ESTIMATED REVENUES LESS!VARIABLE COSTS NET REVENUES LINE EXTENSION COSTS PAYBACK PERIOD SEA ALASKA ESTIMATED REVENLES LESSS VARIABLE COSTS NET REVENUES LINE EXTENSION COSTS PAYBACK PERIOD EAST POINT SEAFOOOS ESTIMATED REVENES LESS?VARIABLE COSTS NET REVENUES LINE EXTENSION COSTS PAYBACK PERIOD AMERICAN PRESIDENT LINES ESTIMATED REVEMES LESS VARIABLE COSTS . NET REVENUES LINE EXTENSION COSTS . PAYBACK PERIOD FIRM RATE $1,358,200 387,600 970,600 144,728 0.15 YEARS $122,950 30,400 92,550 97,622 1.05 YEARS INTERRUP TIBLE RATE $995,700 387,600 602,100 144,728 0.24 YEARS R.W.Beck and Associates CONSTRUCTION COST ESTIMATEenovecrDUKEKID.SERVEE_E%TENS/OWS verre LMA Location CLASKAD wo.SSIPETELNAX TYPE Es _PLawmine-PReoesion-vesion ___raxe-orr VL pniceo =2Z5_cate.cuxo.___apnoven care LIVES i ITEM.ANO DESCRIPTION Quantity |uNT |MATL [LABOR [ut cost ||ney 72.|AwvBboe|I (08,36%36,366A|OVISEA tl Lf oF 4 2 PACIFIER PEARL eat al Spe C |PAY AlcasKA ple slel 7,of) DISEA ALAS EA reenrse 3eeVT |50,5531 24,87 |REEITASE4ALosEnwerenrs|Core 26973 7 wera|e leas Powr |pares 22227 PRO] EN AATER.PEELIDEWT-LIMES WITHA [LOR 56,POP THE,SOT Ez AAPL,PEEIDEMTLiesNO \TRAWS O23 25,077 |FS Fara SSSidesok€Sheet Zot R.W.Beck and Associates CONSTRUCTION COST ESTIMATEmnoseer(LMALASAA SERVICE EXT reste UWISEA rocarion LILISKA wo,SS/PEZELIAN TYPE ts7:_CFTami AS7PREDESION-DESTON TAKE-OFF PRICED EB CALC.CHKO._Us APPROVED DATE [ITEM AND DESCRIPTION QUANTITY UNIT |MATL {LABOR uMIT COST I 1 a a ys)?2 TOTAL TlI(See Cates Te 2 I _|}|TRAVSEORMER,2200 kVA I )| 4./6 KV A-yt PeD tOUT,FUSED ]Ge ELOBLN|FE F¥7 |SSS 7Z|ACUILI)br€th ker,35Hy ,22A._<e 7.lea!15,39 2297S ll 1 Y277VoLCEMNECTOFSis Gi wslew )[lee 2Y-7ol|Ble oo 0,060||METER Ve LKQUIPIPEVYT|1 |sert A1C2-|2752 7OWSLaskerlyeExT(Cer en :WPACKIC FEAEL\POO NET 246708 __IS-SF Ce |meze |72,752).LAAE EXT,3SAM C42¢6.934 l5|fhe |7a,1A%SHIT (B,etELBOWCowMECTPAS,2004 |9 |2al440]76m a”21 FOZ 1,04 ">Eav.T DETECT LS,>|eeli¢s|40 S54 LAe "LL WTS lyre PAD _GYECME Z 76 |Y-icoo|e00 [16400 {402 Z 202:10 breakerfad 5a'Xlz"Ras a.62°1602 4 22°1,0e2 1 PFO SA BTOTAC oz 73 STS Se Fer [2G TT,|PRICIVEE CONST.CHEpilodHn neck |B ZY OSFT OT 32,775 IKte 7TAL ONISEA [rh se7 #7405 168,970 |Ci0fst><8 AAO 18,63%£3,047)|<2,547><55d4> *Raw Tes nn,108,362,36,366 144,728 A Remvé ite.6 ge AO ADO INAL Livi Chireason Meypep Aq Usised, Sheet>.of 8 RwB 3$0-41 R.W.Beck and Associates CONSTRUCTION COST ESTIMATEpnosect(LVALA SKY SERVICE EXTEWS OV eeaveme PACIFIC EAR rane-orr LEO PRICED LEE ome CHKD.LOCATION nL,LAKE APPROVED wo,DS SE TERIAN DATE S22 ESTYPEEST:PLANNING-PREDESION-DESION .ITEM AND DESCRIPTION .QUANTITY unrt |marl |LABOR UNIT COST tl TOTAL (see Caccs P62){||TKAVS,S00kbA,30 34 5|7 lee 12,771 |4222 1 WelelanADMoupT.i id id idEVsED| wl EeseED seifeH,3S5hY .20,Teepe R..?Zea |Lp ag|-ZATIN IETS|OS IMETP RING EA!{SET 4/22 2752 FOS# 4-1 34.5 Line EX(Qpmor _Oise $20 [Er ged 704 ES 27ek |45.264 7 2A3z|SIVE EXT,BY SF COD IEF"/349V /7,15¢BFPO!7¥,e¢ G ELBod CorirectorS 2004 e Wy,i Zoot 4h ZLIEMILI- PETEE THES 3 S40 I SSS PX"C7S| Za s_PAD Se Te |TOE a Bool _oe? G|SW-PAB__5 ye yTS PY 7,a Pe ACT -ae ----ra Sb TOTAL 4H,FIC 29 Ee Z Cost tlonst Aanfe Alle +)ZO _|\%o 13419 "LL@FI_2260.3| TOTAL 5G 275 ||SOUL WS 7,57 Bal me err,245 KY 420 [Er 3.3086 2,830 C216 30%L016 '844 1065 AdIu5TOO Tork 62847 BY TRS 7),6221 -----! Sheet Hot B nwe =>R.W.Beck and Associates CONSTRUCTION COST ESTIMATE ) ero (LMMLASK A SERV.EX 7...reatune 2:MLS LiA-LOCATION 4)AS Ke 7 _wo.5S/FES EB!Ay TYPE EST:__PLAWING-PREDESION-DESION rane-orr 72S emicen CGE CALC,CHKO.______aapproven pare Yagf7S I ITEM AND DESCRIPTION QUANTITY |UNIT |MAT [LABOR UNIT COST TorayICSECatesP21)Li eae LED | I 34,DAVSLe LAI 4 /mn 2=3 47.420 2,FL JLateen7,Psa,P|7 lea Taaa\ZY |[2 AT?| ZL BokWeennecler3CeFes$12 a f(a 272 22FP |Z pooW4ETEELVanER!L SCZ |ZIez I 2752 LOST 2S Line Exreasiert |Fee \|Frin Bly?54,777 42 ¢50l 75240 JEL P04 C0 wee TAe$,2°OA|@ 7717,ae 2H 46%ZS 2 2 Fav DETECTP RS Fleet isslgo|:f S355 120 ove|<.Paws POP CAIs T=As |Lhe |éoo Lee"fe =ZL OgSuntechPubSUEATEta._1000 l2e|2O6d subtetad PGES IeET NAL OTE'Cost brat Change dled |2°|e OU |TZ ZCPY AG TET TUT AR UATE 77. j ---a!I Sheet4z.0t_@ R.\tke B80SD-4!a CONSTRUCTION COST ESTIMATEprovectLAWLHSKreatuneDEAD-ALA SKF __rocarion SIL #5 Ka wo,55/PETERIAY TYPE EST .PLANNING-PREDESION-DESION rane-orr re 2S PRICED HEB one.CHKO.APPROVED DATE fe ITEM AND DESCRIPTION .QUANTITY UNIT |MAT'L |LABOR UNIT COST TOTAL (See.Gabe ce (4)if L|Wrens S00K VHD 35H 13263]2729 |(5 7Aze4/bKYy2,£40 (hua?|<2 ?? marae safeh BE KV 3bPAPWI0UNT flan [joce|24/7 ||_73,4177 2 |POLE Bay_Weehnaatrs,7 Ling.Efe hs le4 f /Z 4 €©Bi/eP2ll_2 pee '|Merees we Fev irae 7 Z GIOZ 22 52\7,0 aia:PZB he Lee ex7 208 [FT ee y=Zo7F £245 |7%224- |Z 6 TECR ead Len Nezve Rs la Pete ||73 ZoY Yor yeroe|so JLExz |Favt®Perecrors 2 _leal rgslvo S355 VEL <a 75 ; e |RAYS.FAD GXAIE Ll leah {U2 FT a2 TSS IA a7 PAD 7 Taye Lar?|7e%e|2277 a Sv lTatTa &23271 18,320 5 7797|Beeark #Gait Chg WEL \FO 1b Theol |S446 |1757 | TWTAL P 30 PIA _23,716 F349aaTalAAalrai,PeladedemsFFaR oe DELSSAPULETADPcaelExT,BOC ET Woz Ve TOG IE 2S |FIZ SIbTE TAL 7t 7 L2G AED TH ORT FRSAConpore:Pris doFk 3 CDY ALLb 37 \Jo Fes ree LeTole--5;at pe57,135 29,334 86596702 Deal R.W.Beck ond Associctes CONSTRUCTION COST ESTIMATEnosecrLLLIEKASERVICEFxreatuneEVS7FOCWT-Location ALA SKA no.175 7ER/AR TYPE EST:__PLANNING-PREDESION-DESION cane CELE PRICED LEF core.CHKD.__APPROVED OATE i((TEM AND DESCRIPTION Quanrity |usr |maT'L/LABOR UNIT COST TOTAL I|(SEE CALCS -fe [72 LITLAYVS..1500 kv 325 ¢-V_PIAL MeyyT”[leat BE2Z57 FF AB |2ha/ce l [ PAD POE BEL EE SP ZLETA ATER |ate,TZ, ZATMLL.FON Wan vee7ees LHC0 ||_34220 \||_G0004METEL/VE EQUIP 2 -4/22 2772 ZOSE |REA ve [7ee [EVE -724973 |t£73 I-77 |:[HS Ate el Ce NPR S___}__i&LAlnZzsr ---2 otf ACE 73 Zz |:1-2 FAULT DETECT ez.J _eal/2Sl¥__7 Too oF.|2 FRRAE_PAE-CAEALE ZEW |eeloa |_|7eeel Je eo 32e5] .:ze Sa tea TEER Te 1 lyf?galeor i.V7 £7)Leoeal 2oes :[eee 1 -SE,SET 20 28 272 S||(aest#Const Che Mad {Oo 1%[RETA G 085 |25,57 |TReTAL.75,¢F3\_20,267}104212 |Sheet Zot RWS SD-4!R.W.Beck ond Associates CONSTRUCTION COST ESTIMATEmnosectLLIVMLMASKPreatuneAPPELTRES.Lf UES rocorin ALY SKE wo SSITEZTERIAY TYPE EST:-_PLANWING-PREDESION-DESION TaKe-orr oy EF PRICED AEF cc.CHKD..__APPROVED DATE ITEM AMD DESCRIPTION QUANTITY |UNIT |MAT'L|LABOR UNIT cost TOTAL (see Caics Fa /¢-)=ALE ieAE eae Z_\#2:hee St|ST7ZL|Ssirz Fal Vee BEER,TER |+|TAIER ?ZL#TO £7OZ\26,772 AIL Boe ConnecPer |7 |e Z9°eo |gseeel G4,ea |-4 rereewsPaw-.Se7t 41E2 ZFS 2.2287)FLA SKY Lie PATe FOO ET lo [4+I C774 ||S668 ||JR,43 ELE Nu/Connectprs,Z2004|& |e@awe?=Zot ROE 73 J\EAVLT DETE<TCRS NIE ee 4 SS86 4AP |hot k a TRAVS,FAD GxX7K/=2%5)£02 600 4 n ZOO! 4eo0 | o _|freaver FAD SXCV Zz./22 bf -|eceeboo 1Cco|seel0 oo CSTE ST LD el 7|2a OTe |112 cPPpieiaeg#Corp Change fll |FT PD 2b 3isl £423 |35 9o8TATATIC,00 ee [Ae 507 |LIERW IIE Vek 17h (fECERA PETZ MCSF EEAOL?24.EKV_EXT 6°O IEP EP pot "ASE |8,492 ||1x, Sib TeTAL FC TLL 220,972 Poe ELIZIA PE COWS Lihange ZA SOV Leelee |Foye 22k MLTERMETE [7 POL Zo,35,990 |75¢Z7_1 SheetSotes SECTION VI ECONOMIC FEASIBILITY OF A WASTE HEAT RECOVERY HEATING SYSTEM INTRODUCTION The purpose of this section of the study is to examine the economic feasibility of installing a waste heat recovery heating system.The waste heat recovery would be from the new power facility with the heat distribution system potentially going to the airport terminal building and/or the residen- tial housing units on Standard Oil Hill.This analysis is only a preliminary evaluation which should be used in determining the advisability of performing a more comprehensive and detailed study of the feasibility of waste heat recovery systems for the City.' METHODOLOGY This preliminary economic feasibility analysis was prepared using estimates and data provided by the City.The estimates were for distances from the power facility to the airport terminal building and Standard Oil Hill,1,600 feet and 1,500 feet,respectively,with no elevation gain to the airport and a 100-foot gain to Standard Oil Hill.Other data provided by the City included annual airport terminal building heating fuel costs of $10,457 and consumption of 11,275 gallons. The waste heat recovery system and its installation in the new power facility was paid for by a grant from the State of Alaska which promotes the use of waste heat recovery systems.The heat exchangers from the City's present waste heat recovery system at the old power facility in the community of Unalaska would be salvaged and reinstalled at the airport terminal build- ing.The only out-of-pocket capital costs the City would be facing,there- fore,would be piping and piping installation costs associated with transport- ing the recovered heat to the heating customer. For purposes of this preliminary feasibility analysis we focused our attention on the potential for heating the airport terminal building since historical heating cost and fuel consumption data are available.The Standard Oil Hill presents a more complex problem because the piping would have to be installed to reach a number of separate buildings rather than a single instal- lation such as the airport.The ciitical element in determining the feasi- bility with respect to the airport is the cost of the piping between the airport and the power facility. An installed cost of $20.00 per lineal foot for preinsulated pipe for direct burial manufactured in Alaska is used to estimate the costs associ- ated with the piping system.This estimate is based on a similar installation in the Fairbanks,Alaska area and is assumed to be a reasonable proxy for the VI-2 Unalaska area.Since piping would have to be laid to carry the heating medium in both directions the estimated distance of 1,600 feet is doubled to 3,200 feet.Therefore,the piping costs are estimated to be $64,000.We have added to this amount ten percent,or $6,400,for other incidental materials and expenses and installations at the terminals of the pipeline.Therefore, the estimated capital costs for the installation of the piping system from the power facility to the airport terminal building is $70,400.i Assuming annual fuel costs savings to be approximately $10,500 andacostofcapitalof10%,the payback period.for the-invest ent in the pipinginstallationisabout11.6 years.If a loan-is obtained from 'the Alaska PowerAuthoritysimilartotheloanforthe34<5-kV line at 2%interest,the payback ©would be 7.3 years.(Note:A no interest loan situation would result in apaybackof6.7 years.)For purposes of-this-analysis,we have assumed thatfueloilpriceswouldremainconstant..If fuel oil prices increased,the pay-back period would be shorter,while if fuel oil prices decreased,the payback eriod would be longer.;-ye ik arene©P g {:Ped S Oly s abt.St tO{uw Jt 7 1 wy ke Ee.CONCLUSIONS \tal ne Based on the estimates and assumptions used herein it is our con- clusion that the economic feasibility of the installation of a waste heat recovery distribution system from the new power facility to the airport terminal building is marginal.At best,the payback period would be over 6 years with no interest and could be more than eleven years depending on the type of financing available to the City. With respect to the Standard Oil Hill,we expect that the payback period would be even longer than for the airport.While we have not made any detailed analysis with respect to Standard Oil Hill,the cost of the piping would be greater than with respect to the airport because of the multiple buildings to be served.In order to obtain a reasonable cost estimate for Standard Oil Hill,a piping distribution system would have to be layed out. With respect to the airport,we recommend that installation of the waste heat recovery system only be undertaken if grant funds or low-cost financing can be obtained.The City should also obtain a detailed cost esti- mate of the installation before making a decision to proceed. SECTION VII LOAD FORECAST INTRODUCTION The purpose of this section is to develop a load forecast for the City for the period of fiscal year 1985-1986 through fiscal year 1989-1990. This five-year forecast examines the City's service area and uses existing demographic and economic studies to estimate energy loads and peak demand requirements.Such a forecast will assist the City in its short-range plan- ning and help the City alter its plans if conditions should change. METHODOLOGY Sufficient detailed historical load and usage data were unavailable to properly perform a customer class by customer class econometric load fore- cast which could be aggregated to provide a forecast for the entire system. Additionally,with the existing potential for sizeable and immediate incremen- tal loads impacting the City's electric system a point or line forecast would be too narrowly focused.Therefore,a forecast range was developed for the City's entire electric power load requirements.In this section we develop a range of forecasts with an upper bound,a lower bound and sample intermediate forecasts falling between those two bounds, SYSTEM LOAD For this forecast procedure the City's system load is divided between a base load amount and an incremental load.The base load is com- prised of the energy requirements of the City's current and traditional type customers,residential,small power,commercial and governmental.The incre- mental load would result from the addition of large commercial and industrial type customers. The basis of the base load forecast is the historical generation totals taken from the City's reports to the Alaska Power Authority relating to the Power Cost Assistance Program.These are monthly reports and were avail- able for the period March 1982 through June 1985.Additional background information on historical trends and occurrences was gained from two reports provided by the City.One was the Unalaska Airport Master Plan 1982-2000 prepared for the City of Unalaska by Unwin,Scheben,Korynta and Huettl in July 1982.The other report was prepared by the Alaska Power Authority in April 1985 titled Unalaska/Dutch Harbor Reconnaissance Study Findings and Recommendations. With this data and information as the basis of the base load fore- casts and by using information from these two studies and from City personnel relating to the potential incremental loads,assumptions were made concerning growth patterns and load additions.These assumptions were then used to VII-2 develop four separate energy requirements forecasts,a lower bound,an upper bound and two intermediate cases.Typical assumed load factors were then applied to each of the base load and incremental load forecasts to develop a forecast of the City's annual peak requirements for each year in each case. These four cases and the relevant assumptions are discussed in the following paragraphs.Tables VII-1 and VII-2 in this section present these four fore- casts.Graphical representations are shown on Exhibits VII-A and VII-B. Table VII-1 shows the historical generation'for the period fiscal year 1982-1983 through fiscal year 1984-1985 and the base,incremental and total energy requirements projections through fiscal year 1989-1990.Table VII-2 develops the City's peak requirements forecasts for this period based on the forecasts presented on Table VII-l. The Lower Bound The principal assumptions determining the lower bound of this fore- cast range are that no new incremental load comes to the system and that the base load grows at between 2.0%and 4.0%per year.This bound represents the case that the growth in electric power consumption in the Unalaska/Dutch Harbor area grows less than normal and that additional large loads are not added to the system.Also,implicit in these assumptions is that the antici- pated increase in bottom fishing activities does not materialize. From an actual annual kilowatt-hour generation total of 3,481,801 for fiscal year 1984-1985,the lower bound increases to a generation amount of 4,035,601 kilowatt-hours in fiscal year 1989-1990,an annual increase of 3.0%.Assuming a 41%load factor for base load customers,the lower bound annual peak requirements increase to 1,124 kilowatts in fiscal year 1989-1990. Intermediate Case 1 This intermediate case relates directly to the loads utilized to estimate fuel costs,develop allocation factors and determine rate levels for fiscal year 1986-1987 as used in Section III,Rate Requirements.This case assumes that the incremental load added to the system in fiscal years 1985- 1986 and 1986-1987 represents the only load additions.It is also assumed that only 80%of the load comes on in these years with the remaining 20% coming on in the following year and then growing at a rate of 2%per year afterwards,Pertaining to the base load,the assumption is that load growth will be below the historical average for the first two years then increase to a 5.0%rate by fiscal year 1989-1990. These assumptions result in the City's system load going from 4,051,437 kilowatt-hours in the first year of the forecast period to 5,202,937 kilowatt-hours in the final year.This increase is approximately 8.4%per year,however,the major portion of it occurs in the first two years,fiscal years 1985-1986 and 1986-1987. The system's peak requirements are forecast to go from 1,135 kilo- watts in fiscal year 1985-1986 to 1,516 kilowatts in fiscal year 1989-1990. Base load is expected to maintain between a 41%and a 40%annual load factor. VII-3 The incremental load's annual load factor is expected to range downward from 39%to 36%.This estimated range and its downward sloping nature results from an examination of the customers and their loads which have been identified by the City as potential acquisitions.These customers are generally fish processors with energy consumption patterns which can vary widely depending on the fishing/crabbing seasons. Intermediate Case 2 sf The second intermediate case assumes that the City acquires incre- mental loads at a more rapid rate than in intermediate case 1 for fiscal year 1985-1986.This more rapid pace continues through fiscal year 1986-1987 with incremental loads being double those in intermediate case 1.The total impact of these additions is not felt until fiscal year 1987-1988 with the incremen- tal load growing another 20%.These loads then continue to grow at a rate of 2%per year to the end of the forecast period.With the increase in incremen- tal load being more encouraging it is also assumed that the system's base load will grow at a slightly faster pace,beginning at 3.0%and increasing to a rate of 5.5%per year. The assumptions in this intermediate case result in the City's system energy load going from 4,336,255 kilowatt-hours in fiscal year 1985- 1986 to 6,377,111 kilowatt-hours in fiscal year 1989-1990.This amount of increase,resulting mainly from the addition of large commercial and indus- trial type loads as incremental loads,translates into an annual rate of growth of 12.92. From an estimate of 1,224 kilowatts in fiscal year 1985-1986 the system's annual peak in this intermediate case is forecasted to increase to 1,933 kilowatts in fiscal year 1989-1990.The annual load factor associated with the system's base load is expected to decline slightly from 41%to 39% over the forecast period.This slight decline can be expected as a result of the construction of better insulated homes of which some may be electrically heated and the installation of new and replacement of existing appliances and equipment with more energy efficient models.For reasons similar to the first intermediate case the incremental load's annual load factor declines from 38% to 35%. Upper Bound The upper bound is intended to represent consumption levels having little chance of being exceeded by the City during the five-year forecast period.Incremental load is added to the system at a faster rate than in the intermediate cases for fiscal year 1985-1986.During fiscal year 1986-1987 incremental loads are added at over twice the pace of the previous year.This increase also reflects the realization of the bottom fishing industry carrying over into the next year and,coupled with the connection of additional large commercial and industrial type loads,would resultin the addition of another one million kilowatt-hours of incremental load.The total load impacts of these additions would not be entirely felt until fiscal year 1988-1989 with VII-4 another 20%growth.Total incremental load on the City's electrical system would increase from 900,000 kilowatt-hours in fiscal year 1985-1986 to 4,130,590 kilowatt-hours in the last year of the forecast period,fiscal year 1989-1990. During the forecast period the City's base load also experiences a more robust continuous growth rate than the historical normal reflecting bottom fishing and general business activities in the area.The growth rate for this portion on the load is assumed to be 6.0%per year. The upper bound of this forecast range would start from a gener- ation level of 4,521,073 kilowatt-hours during fiscal year 1985-1986.It would then increase,fueled by an active business climate and vigorous load acquisition efforts,to a generation level of 8,702,111 kilowatt-hours infiscalyear1989-1990,an average growth rate of 20.1%per year. The upper bound's related annual peak forecast is anticipated to increase from 1,279 kilowatts in the first year of the forecast period to 2,685 kilowatts in the fifth year.The load factor assumptions and reasonings made in this case are similar to those used in the intermediate cases. CONCLUSION Based on the background information,data and assumptions utilized, this forecast range is a reasonable estimate of the energy requirements and peak requirements the City can anticipate facing during the period fiscal year 1985-1986 through fiscal year 1989-1990.The City is in the situation of having within its service area significant electrical loads which are current- ly being self-served but whichin the future could be served by the City.Dealing with the unknowns of the amount and timing of the acquisition of these loads is a major factor in forecasting the City's future loads.Realizing these quantity and timing uncertainties,the range of forecasts provides the City with a planning framewcerk upon which system improvements can be based. The forecast range has an energy requirements band of approximately one million kilowatt-hours and a peak band of 290 kilowatts in the initial year of the forecast,fiscal year 1985-1986.These bands increase to approxi- mately 4.6 million kilowatt-hours and 1,561 kilowatts,respectively,by the final year of the forecast period.The uncertainty with respect to economic recovery and the extent and timing of adding incremental loads makes selection of a specific forecast difficult.At this point,we recommend using inter- mediate case 1 as the best estimate.At such times as the extent and timing of adding incremental loads to the system becomes more certain,the forecast should be re-evaluated. LOWER BOUND EASE LOAG PERCENT INCREASE INCREMENTAL LOAL PERCENT INCREASE TOTAL LOAD FERCENT INCREASE INTERMEDIATE CASE 1 EASE LOAN FERCENT INCREASE INCREMENTAL LOAL PERCENT INCREASE TOTAL LOAL! PERCENT INCREASE INTERMEDIATE CASE 2 EASE LOAN FERCENT INCREASE INCREMENTAL LOAD PERCENT INCREASE TOTAL LOAD FERCENT INCREASE UFFER BOUND BASE LOAD FERCENT INCREASE TNCREMENTAL LOAD PERCENT INCREASE TOTAL LOAD FERCENT INCREASE CITY OF UNALASKA HISTORICAL AND PROJECTED ENERGY REQUIREMENTS HISTORICAL TABLE VII-1 PROECTED FY 1962-88 FY 1953-4 FY 1984-05 FY 1905-86 FV 1966-87 FY 1967-88 FY 1968-89 FY 1927-90 2,625,792 3,385,378 3,481,801 381,437 3,622,456 3,731,140 3,830,805 4,005,60122.93%2.8%2.00%©2.0%3.0%40 4.0% 2,605,772 3,305,378 3,421,801 3,881,437 3,622,466 3,781,140 2,800,385 4,085,601 93 2.8%2.00%2.00%3.00%4.00%4.00% 2,605,792 2,305,372 381,801 BEB1,437 3,675,787 B,BM1,145 4,013,997 4,214,69728.932 2.8%2.00%BLK 4.5%4.5%5.0% 00,000 TALES 947,866 968,863 (983,2420.0%2.0%2.0% 2,625,792 3,505,378 3,451,801 4,061,437 4,467,272 4,771,011 4,982,960 5,202,93722.93%2.8%16.26%10.26%7.2%4.00%4.42% 2,605,792 3,385,378 3,401,801 «3,884,255 3,747,637 3,952,757 4,171,213 4,400,62028.93%2.0%3.002 4.5%5.0%5m 5.8% 70,000 1,882,110 1,899,782 1,937,727 1,976,4120.0%2.0%2.0% 2,625,772 3,205,372 3,421,901 4,306,255 5,830,747 5,853,407 6,108,940 6,377,11123.92%2.25%24.542 22.93%9.81%4.36%4.29% 2,608,792 3,305,372 «3,1,B01 «3,621,073 3,888,307 4,068,638 4,212,756 4457180123.93%2.8%4.00%6.0%6.0%6.0%6.0% 900,000 2,374,665 3,374,665 4,049,598 4,130,69020.0%2.0% 2,6%5,792 3,305,578 3,401,901.4,621,072 6,213,002.7,443,903 8,242,354 2,702,111 oF.19.80%12.35%4.06%2h a 2.054 Stn cm Re a ."yPkSAA!ore Ai PoBRBPROPreee TOTAL LOAD -KH -L.F. -Kn INTERMEDIATE CASE 1 TOTAL LOAD =Kit! -LF. -KH INTERMEDIATE CASE 2 BASE LOAD -KH -LF. TOTAL LOAD -Kitt -LF. -Kn CITYOFUNALASKA PROJECTED PEAK REQUIREMENTS Table VII-2 FY 1985-86 FY 1926-67 FY 1987-82 FY 1958-69 FY 1989-90 3,551,437 34622,%66 3,731,240.2,890,385 #5035 4602 100%1.0%$1.0%41.0%41.0% 989 1,009 "44039 1,060 1,124 3,551,437 34622,4%66 3,731,240 3,850,325 4,035 601 HL 00%1.0%1.0%1.0%1.0% 989 1,009 1,039 1,080 14124 35514437 3,675,737 3,841,145 %013,997 4,214,697 41.0%1.0%000%40.0%40.0% 929 1,023 2,096 1,146 1203 500,000 71,555 49 5866 968,863 72S M1 39.0%38.5%37.0%26.0%26.0% 146 _235 293 307 313 054 437 4,467,292 4,791,011 982,860 5 202,937 40.7%40.5%37.9%39.2%39.2% 1,135 1,258 1,389 1,453 14516 3,586,255 34747 637 3,953,757 171,212 %54004630 1.0%40.0%40.0%29.0%3920K 999 1,070 1,128 15221 1,288 TSO ,000 14583,110 25899,732 14,937,727 1,976,421 28.0%36.0%35.0%35.0%35.0% 225 502 620 632 os 336,255 5330,™7 5 253,489 6,108,440 6,377,112 0.4%38.7%38.2%27.6%37.7% 1,224 4,572 1,72 1,83 1,933 3,621,073 2,838,337 ,068 638 %312,756 %571,521 1.0%40.0%39.0%39.0%29.0% 1,008 1,095 1,192 24262 2,338 900 5000 253744655 3,374,665 049 593 %,130,590 38.0%36.0%35.0%25.0%35.0% ZrO '753 $4101 1,321 1,37 5521 073 _6y213,002 _Ty*43,303 8,362,5%8,702,411 OMX 8"gee area "370K 37.0% 4279 4 yate So 2,292 2,583 2,685 WAREHO(Millions)EXHIBIT VII-A PROJECTED ENERGY REQUIREMENTS FY 1985 -FY 1990 ab1885 1686 1887 1088 1889 1880 EXHIBIT VII-B PROJECTED PEAK REQUIREMENTS FY 1885 -FY 1990 KiLW.wATTwCThousands)bh1886 1887 1888 1888 1880 SECTION VIII PRIVATELY-OWNED ELECTRICAL GENERATION INTRODUCTION Generation of electricity in the City of Unalaska and the Dutch Harbor area is not limited to City-owned facilities.Several industrial enti- ties,principally the seafood processing plants,have met all or nearly all their electrical energy needs through self-generation.There is also the potential for additional,privately-owned generation within or in the vicinity of the City for instance,through the development of small hydroelectricfacilities.1/ The generation of electricity by entities other than the City may affect planning and rates for the City's electric system in several ways. First,from the City's perspective,privately-owned generation is a potential electrical resource to meet load growth,provide outage reserves,or displace generation from its older,less fuel efficient units.Conversely,there is also the potential that the City could interconnect with adjacent industrial entities and economically displace operation of existing on-site generation,The economic value to the City of extending lines to serve new load is dis-cussed in Section V of this report. From the private viewpoint,an owner of an existing or new generat- ing plant may look to the City to purchase all electricity generated or what- ever amount is surplus to his own use.An industry with its own generation might also interconnect with the City to purchase electricity (i)to cover permanent increases in load,(ii)to meet peak loads which periodically exceed on-site generation,and (iii)to provide back-up power during regular mainte- nance or forced outages of equipment. The purpose of this section is to describe and analyze the City's regulations and ordinances on privately-owned generation and recommend re- visions,if appropriate.This section will also present available information on the existing and proposed privately-owned electric generation within or in the vicinity of the City and discuss the assessment of the potential inte- gration of these units with the City's electric resources. Several different characterizations of privately-owned electrical generation will be used below;there are subtle distinctions in the use of these phrases that should be clarified."Privately-owned electrical gener- ation"means all electrical equipment,regardless of motive force,that pro- duces electricity and that is not owned or leased by the City.There are two main sub-categories of privately-owned generation:"Small power producer"is an electrical generation facility which is primarily driven by renewable 1/Energy Stream,Inc.has contacted the City regarding purchase from their hydroelectric project proposed for Pyramid Creek. VIII-2 resources or waste products and of which less than 50%is owned by an electricutility.2 "Cogenerator"is an electrical generation facility which sequen- tially produces another form of energy,such as steam or mechanical energy,and of which less than 50%is owned by an electric utility.3/Together, generation facilities that meet these operating and ownership criteria are "Qualifying Facilities"under FERC regulations implementing the Public Utility Regulatory Policies Act (PURPA).Facilities which are privately-owned elec- trical generation,but not qualifying facilities,would include most of the simple-cycle,diesel-engine equipment used by the industries within and in the vicinity of the City. CITY ORDINANCES AND STANDARDS AFFECTING PRIVATE POWER GENERATION Current Policies and Standards City Ordinance 10.08.1000,Service Conditions,addresses privately- owned electrical generation in paragraphs N.and 0.These paragraphs state, in parts: "N. Self-generation.As soon as electrical energy is available,each customer shall purchase from the city all elec- tric energy purchased for use on the premises specified in his application for service,and shall pay therefore at rates estab- lished in this title.Production or use of electric energy on a customer's premises from a source other than that of the city xxx shall be subject to appropriate regulations as shall be fixed from time to time by the city «xx. O.Cogeneration.Any customer may operate his generating equipment in parallel with the public utility system whenever this can be done without adverse effects xxx.The Director of Public Works shall prepare and publish standards,requirements, and guidelines for connection of cogenerators and small power producers xxx." Through Resolution 83-03 the City approved a document containing "standards,requirements,and guidelines for connection of cogenerators and small power producers."This document generally describes applicable Federal law and regulation,customer eligibility,system configurations,and electri- cal interconnection requirements.Through these standards,any customer is 2/The regulations of the Federal Energy Regulatory Commission (FERC)for- mally define the size,fuel use,and ownership criteria in Subpart B, Section 292.203(a).co \ 3/See FERC regulations,Subpart B,Section 292.203(b). VIII-3 permitted to operate in parallel with the City's electrical system if there are no adverse effects in so doing.These standards do not require purchase of electricity from a customer if the City is simultaneously selling power to the customer at a rate lower than the price being paid for the customer's electricity., Federal Requirements for Electric Utilities According to FERC regulations (18 CFR 292,101-602)an electric utility must interconnect and purchase electricity offered for sale by quali- fying facilities,which consist of (i)cogenerators,and (ii)small power producers.These facilities produce electricity with renewable resources or at high fuel-use efficiencies obtained through sequential energy use.An electric utility cannot own more than 50%of a qualifying facility.Simple or combined-cycle turbines using primarily coal,natural gas,or oil are not permitted as qualifying facilities under the FERC rules. An electric utility must purchase all electricity offered by a qualifying facility,regardless of the rate relationship between the purchase price and the concurrent retail rate paid by its customers.A qualifying facility is allowed to maximize its financial gain by either serving its on-site load and selling only occasional surplus power or selling all elec- tricity produced at a price equivalent to the utility's avoided cost andpurchasingitsnormalelectricalrequirementsatregularretailrates.2 Back-up,maintenance,and supplemental power must also be made available to a qualifying facility at reasonable,non-discriminatory rates.A reasonable rate requires,in part,that forced and scheduled outages of the qualifying facility not be assumed,without substantiation,to fully coincide with the utility's peak loads. The rates offered to qualifying facilities must reflect all the costs of the utility avoided by virtue of the purchase.However,a rate less than full avoided costs can be set by a self-regulated utility (such as the City)if these lower rates are in the public interest,are found to be suf- ficient to encourage development of qualifying facilities,and do not dis- criminate against such facilities. Utility avoided costs can be estimated at the time a firm contract is executed or calculated at the time of delivery.A standard rate must be availale to qualifying facilities with a design capacity of 100 kilowatts or less. 5/_Electric loads that can be purchased simultaneously from the utility donotincludethosesolelyassociatedwiththeproductionofelectricity, for example,feedwater pumps and fuel conveyors. VIII- 4 Evaluation and Recommended Changes The current ordinances and documents .pertaining to the City'spoliciesonprivately-owned electric generation |are incomplete and are,atsomepoints,confusing.The needed revisions to 'the City's program would not constitute a major undertaking for the City and would insure that the City's policies are understood and consistently applied,to the benefit of the utili-ty system and its customers,. * , €woewee Oe "Sy 'e There are three major areas in which revisions or additions should be made.First,distinctions between types of electric generation facilities should be addressed.Facilities that qualify under the PURPA regulations of the FERC can require several services of the City (as described above).Othergeneratingfacilitiesdonotqualify,©except as may be allowed by the City'sownpolicies,Thus,there is the potential for two distinct sets of policies affecting the City's transactions with owners:of electric generation facili-ties.a Pr co The policy 'ordinancesand.standards of the City should be clear astoanydistinctionsintreatmentoftheseelectricfacilitiesand,if so,whatthesedifferenceswillbe.'Terms,such as "cogeneration,"should be defined in Section 10.08.060 and used precisely within text and headings.The need to define a term is especially important -'if it is _used in a special context.Second,the Federal requirement of the City (18 CFR 292,101-602) concerning interconnection to,purchases from,or selling to qualifying facilities should be fulfilled through implementation or by requesting waivers of the FERC from those items which the City considers unnecessary,financially burdensome,or administratively impractical.Through Resolution 83-03,the major policies required by FERC have been adopted.The remaining requirement of the City entails adoption of a standard purchase rate for qualifying facilities with a design capacity of 100 kW or less.Standard rates should include the savings in normal utility operating expenses,as described in Section II,and be administered to periodically update fuel costs and fuel use efficiency estimates. Because of the relatively small load currently served,the City should consider applying to FERC to reduce the size limit of facilities eli- gible for standard rates from 100 kW to 20 kW,as allowed in 18 CFR 292.403. This lower limit could forestall disputes as to the rights of various qualify- ing facilities to produce during minimum load hours.Reducing the amount purchased at a standard rate should also improve the accuracy in estimating the associated avoided costs, Specific items for which revisions are recommended are listed below. 1.Paragraph N,is unclear.Entitled "Self-generation,"the paragraphstatesthatallpurchasesby-a.-customer,specified,jin a service applicationmustbemadefromtheCityandalsostatesthat.electric energy from a sourceotherthantheCityis'subject:to appropriate regulation if interconnection with the City facilities is required...)avriatie FOR Gi Pt RELEASE URI ALT HGORIZED Wa am year get A EPILCROESee VIII-5 Neither of these points is directly related to the issue of self- generation since both address electric services potentially provided to a customer by a third-party. It is unclear as to whether the City is requiring the exclusive right to sell to a customer or only restrict a customer from switching loads originally served by the City to another supplier.The second statement does not make clear what sources other than the City may serve a City customer andbeinterconnectedwiththeCityfacilities.It is also ambiguous as towhetheritistheproductionofelectricity,.use of electricity from thenon-City source,the interconnection,or all aspects of privately-owned gener-ation which is to be subject to City regulation.Regardless of the original 'intent of 'Paragraph N.,the 'City cannotregulatetheproductionoruseofelectricitywhichisproducedbyaqualify-ing facility and not resoldto a third-party who.is a customer of the City;this paragraph should be redrafted accordingly.The revisions should alsomakeclearthetypeofinterconnection.operation.permitted for non-qualifyingfacilities.Reference should then be added to a 'single technical document oninterconnectionstandards,"requirements,and 'guidelines which covers bothseparateandparallelsystemoperation,:: 2.Paragraph'0.does not address”the distinction between generationfacilitiesthatqualifyordonotqualifyundertheFERCregulations.The heading of the paragraph uses the term "cogenerator,"and the second sentence calls for the adoption of interconnection standards for "cogenerators and small power producers."However,the first sentence permits the parallel operation of any customer's generating facility without restriction as to type of equipment. The document containing interconnection standards exhibits this same dichotomy.The FERC rules for cogeneration and small power production facilities are presented,but all types of customer-owned electrical equipment are allowed to operate in parallel with the City's system. The policy of permitting parallel operation of any type of generat- ing equipment also contradicts the Paragraph N.'s requirement of a double- throw switch to interconnect a customer with another electrical source.(The double-throw switch implies that the generation on the customer's premises will be electrically isolated from the City's system at all times.) In Paragraph 0.,as well as in Paragraph N.,the problem with the policy ordinances is not the intent to create an equipment-blind policy for electric service,interconnection standards,and parallel operation.Though Federal regulations oblige the City to adopt certain policies for qualifying facilities,the City may offer the same opportunities to all privately-owned generation.The problem with the current policy ordinances is the uncertainty engendered by interchanging of .generic and.specific equipment descriptionwithoutaddressingwhat,if any,distinction between them is made in theCity's policies.Poa Phebe Re VAS VIII-6 3.The "Standards,Requirements,and Guidelines for Connection of Cogenerators and Small Power Producers"should delete the introductory dicus- sion of Federal law and FERC regulations.Background material such as this isgenerallyinappropriateforwhatessentiallyisa_technical document and maydetractitsprimarypurpose. Subsection 1.1 of the standards document states that the City will not purchase "from a facility which is found-to have a net drain on the utili-ty''s system."The term "net drain"is defined,in effect,as a purchase from a customer at avoided costs and a sale at average costs which provides no netsystembenefit. Even with a statement of intent,the meaning of the restriction is unclear,at best.The apparent meaning is to limit a concurrent purchase-and-sales transaction by a customer,if the avoided cost rate of the City isgreaterthanitsaveragecosts..This transaction is permitted to qualifyingfacilitiesbyFERCrulesand,consequently,must be allowed by the City;how-ever,the City could restrict.non-quali fying facilities from concurrentpurchase-and-sales _transactions.4 Since,such a restriction is more apolicydecisionthantechnicalinformation,it:would be better stated withinanordinance.a a?ae There are circumstancesunderwhich a utility is not required byFERCrulestopurchasefromqualifyingfacilities.If the City's costs would be increased,purchase from qualifying facilities can be declined.Mainly, such instances would occur during low-load hours when generating equipment that cannot be restarted quickly to meet peak-load hours is operating at its minimum loading.Though this circumstance may or may not be of concern for the City,this restriction affects the purchases made by the City,rather than interconnection standards,and is properly included with the standard rate offering or specific rate agreement. Subsection 1.2 allows a customer to use any energy source to oper- ate generating equipment.Again,this broad allowance on equipment type is inconsistent with the title of the standards document and Resolution 83-03, which uses the phrase "Cogenerators and Small Power Producers."A more in- clusive description of generation equipment should be used or "cogeneration and small power producers"should be defined by City ordinance to include all types of generation. 4/In the near-term,this restriction may be without effect.The City's estimated average costs are 30.3 cents per kilowatt-hour and the esti- mated avoided energy costs are 7.6 cents per kilowatt-hour. VIII-7 POTENTIAL GENERATION FROM PRIVATE ENTITIES There is approximately 10.4 MW of diesel-powered generation in- stalled by industries in or in the vicinity of the City --roughly two and one-half times the 'installed capacity of the City's equipment.Information taken from a survey by the City of industrialplantsissummarized below. cd Industrial Generation at Unalaska/Dutch Harbor a Total oo te |Number Capacity Plant”BO of Units (kW) Unisea Processor <3 1,840 Vita Processor (Unisea)"3 1,900 Sea Alaska 7 2 610 Panama Marine ' we 290 Pan Alaska *°;-6 2,700Majellan(Pan Alaska)|2 750 American President Lines 3 1,320 9 720.East Point Seafoods The survey data and discussion with City personnel indicate that few specifics about the operation and operating costs of the existing indus- trial information is known.Few,if any,of the installations meter the electricity generated by each unit or fuel burned.Through a survey conducted by the City using temporary metering and log books,an estimated 20,967 MWh (2,393 average kilowatts)was generated in 1983 by industrial plants.The estimated figure for 1984 is much lower. All equipment cataloged by the City's survey are diesel-fueled, engine/generator sets.None of the installations is indicated as using renew- able fuel sources or waste heat recovery systems,so these facilities would not qualify for the opportunities required by the FERC regulations.Any services,rates,or interconnection with such facilities is at the discretion of the City. New Generation Energy Stream,Inc.has proposed to develop and sell to the City a hydroelectric plant on Pyramid Creek with an installed capacity of 1,400 kW and an estimated energy output of 7 million kWh (800 average kW)annually. The project would divert water from Pyramid Creek which is not required for the City's water supply.Construction could be complete in 1986-1987,if regulatory permits are obtained and agreement for purchase by the City is reached,This project would qualify under.the FERC rules as a small powerproducer.The Energy Stream,Inc.proposal |is discussed in detail in Sec-tion IX.Pro oei eda eG LE aN VIII-8 Energy Stream,Inc.has proposed an initial price (also a minimum price)of 18 cents per kWh for electricity sold to the City.No other poten- tial projects have been identified. Arrangements With Private Entities Integration of the City's system with privately-owned electrical generation could have one of three impacts.on the City:(1)increase power purchases;(2)increase power purchasers and retail sales;or (3)increase retail sales.Which of these occurs will.depend on the location of the pri-vate generation,the operating costs of the various generating units,and theratepoliciesoftheCity.. Most small power producers 'using "renewable resources will haverelativelylowenergycostsandwillbeanindependentfacility,that is,notpartofanindustrialplant.These projects represent a net resource to theCityand,by virtue of their lower operating costs and the force of Federal regulations,would normallybe dispatched prior to operation of the City'sequipment.To finance new investment,project owners would generally seek a rate based on the full avoided costs of the City,with a significant portion of the rate guaranteed for at least 10-15 years.Any sales by the City to the project would be normally limited to emergency and maintenance power.The hydroelectric project proposed by Energy Stream is a prime example. At nearly every point the converse is true for the existing gener- ation at the local industrial plants.The operating costs of the industrial units is based on burning diesel and,therefore,without knowing specific figures,are high. Both the City and the industries could potentially benefit by limited integration of their systems and sharing of reserves.For industries with smaller generating units (e.g.,less than 300 kW),it may be economical for the City to offer interruptible service for all but critical plant loads, with the industrial plant's reserve coming from its own generating equipment. For industries with newer,more efficient units,operating this equipment, removing older and smaller units,and purchasing their plant reserves from the City through retail rates for back-up and maintenance power may be the more economical arrangement. The possibility of joint dispatching of the City and industrial generating units could also be explored;however,given the relative similari- ty of the generation equipment and fuels (i.e.,diesel-powered engines)the fuel savings may not offset the additional equipment investment and adminis- trative costs to coordinate joint dispatching. Assessing Potential Power Purchases from Private Entities Renewable resources and generation-at industrial plants representpotentialnewresourcestotheCity.Additional information is required to.make a realistic appraisal of 'the potential 'purchase of either type ofresource.BG ee mF AVL Abie SOE VIII-9 For renewable resources,information on the resource itself should be compiled initially.The factors addressed by the assessment should include -- + 1.the size of the resource,including 'seasonal and daily character- istics;(aa Oeaos.me 2.the location of the resource-in''relation to the City's currentdistributionsystem;and Te aS 3.any unusual engineering features or significant environmental impacts,a ne"wo. Renewable resources*in'the vicinityof the City may include hydro,geothermal,and wind.In additionto.the Pyramid Creek development proposedbyEnergyStream,development of hydroetectric facilities on the City'sdomesticwatersupplyshouldbeinvestigated...me - Windmills”and "Low-temperature.geothermal using binary-cycle equip-ment are still considered.emerging technologies (i.e.,equipment costs areexpectedtodeclineas'they are more widely used).However,in some appli- cations these technologies are already considered cost-effective,particularlywhenthelong-term costs of alternative generation is considered,At the industrial plants.in 'the vicinity of the City the principalresourceopportunityispurchase'of power generated from existing diesel engines.Information on this resource includes the type of equipment,major maintenance data,and some temporary metering of energy production, To determine the extentto which economical purchases could be madefromthisindustrialgeneration,additional information on the operating costs of each unit and the operating pattern of the equipment must be compiled. From this,the average cost of power available for purchase by the City could be calculated. For the most part,net resources (purchases £rom less sales )teypurchasedfromanindustrialplantwouldcomedpérationofolder,smaller units which would normally be used for reserves.It is doubtful that short- run purchases from these less efficient units could be economical;however, under long-term firm agreements industrial generation might be a cost-effec- tive resource to meet load growth of the City.Management of the industrial plants should be approached to see if long-term,firm operating commitments are feasible. SECTION IX PROPOSAL OF ENERGY STREAM,INC. INTRODUCTION aa Energy Stream,Inc.(ESI)has proposed to develop the Pyramid Creek Hydroelectric Project and sell its electrical output to the City.The project would have an installed capacity of 1,400 kW and a generation capability of 7,100,000 kWh per year.This section will examine the ESI proposal. BACKGROUND In connection with our studies of the.ESI proposal we reviewed andanalyzedthefollowingdocuments?©so l.Draft Contract prepared by ESI. 2.FERC License Application by:ESI.oO3.Copy of ESI presentation to Unalaska City Council dated June 4,1985. 4.Manufacturers specifications.and other City records for City's diesel generator units... In addition,a meeting was held in Seattle,Washington on July 20, 1985 to discuss the ESI proposal and to agree on common assumptions to be used for analysis purposes.Those attending the meeting were Mr.Harry Noah, Mr.W.J.Lawrence,and Mr.Gene R.Crooke,all representing the developer ESI,Mr.David Helsby and Mr.Curtis Winterfeld of R.W.Beck and Associates, and Mr.Jeff Courier of the City. Subsequent to the meeting on July 20,1985,a letter was prepared and forwarded to the City setting forth our analyses,conclusions and recom- mendations with respect to the ESI proposal.A copy of that letter dated August 1,1985 follows in this section.Reference is made to the letter for a complete description of our studies and conclusions with respect to the ESI proposal. CONCLUSIONS The potential savings in fixed and variable costs of the City do not support the minimum contract rate of 18 cents/kWh offered by ESI.Given the uncertainties about the City's future load,operating and dispatch prac tices at the new power facility,and equipment fuel efficiency,any minimum contract rate at this time greater than the City's avoided cost of about 7.5 cents per kWh would 'place substantial 'risk on the City unless some off- setting current or future benefit was offered by ESI.. IX-2 The City should not accept the ESI proposal in its current form. Rather,if the project is to be pursued,the City should attempt to negotiate with ESI a contract purchase rate and terms acceptable to the City as outlined in the August 1,1985 letter.If a permanent contract rate is required by ESI,the base energy rate should reflect current fuel costs to the City and expected load conditions when and if ESI begins .operation.Based on ouranalysis,this would be about 7.5 cents/kWh. :Any *future.rate escalationshouldbetiedtoanindexrepresentativeoftheCity's fuel costs,Analternativetoescalatingtheenergyratebasedsolelyonafuelcostindex would be to add both a lower and upper bound.°.This method would guarantee a minimum rate escalation to ESI (and its financiers)regardless of future oil prices.As the counter-balance for the City,'a maximum escalation rate would also be added to protect the City from rapidly increasing oil prices, Foy *a”oe :a\s R.W.Beck AND ASSOCIATES ENGINEERS AND CONSULTANTS PLANNING GENERAL OFFICE DESIGN FOURTH &BLANCHARD BUILDING ATES eNTAL 2121 FOURTH AVENUE SEATTLE,WASHINGTON CONOMICS SEATTLE,WASHINGTON 98121 Telephone:206-441-7500 MANAGEMENT 206-441-7500 Telex:4990402 BECKSEA 'eno,SS-1987-ER1-AX August 1,1985 Mr.Jeff Courier City of Unalaska Post Office Box 89 Unalaska,Alaska 99685 Subject:Proposal of Energy Stream,Inc. to the City of Unalaska Dear Mr.Courier: Energy Stream,Ince has proposed to develop the Pyramid Creek Hydro- electric Project and sell its electrical output to the City.The project would have an installed capacity 1,400 kW and is expected by the developer to gener- ate 7.1 million kWh annually (810 average kilowatts).1/ Because Pyramid Creek is also the community's water supply,the proj- ect's energy production would depend on whatever water might be available after diversion by the City.I do not know to what extent,if any,studies have been made by ESI to validate the above project capacity and annual energy production under average or adverse water conditions in Pyramid Creek. DESCRIPTION OF THE ESI PROPOSAL ESI has proposed a draft contract to the City.Through this draft con- tract,the offer of ESI proposes the following: (1)Initial service by the City of several industrial plants (unnamed by the contract)is a pre-condition to the agreement.During the term of the agreement,the City is also obligated to make reason- able efforts to maintain a certain level of sales,including add- ing to its customer base.(Article 11,parts c¢and d). (2)Except during the first two years,the City must first purchase electricity from ESI prior to operating its own generation or purchases from any other supplier.During the first two years, operation of a single generator (apparently,the 1,450 kW unit being tested)to be specified in a contract appendix will be allowed to displace purchases from ESI.(Article 3,parts b and Ce)::.a a a es vob?i rer 1/Notice of Application,EL85-20-000,Federal Energy Regulatory Commission,March 25,1985.'.Fe a OS Oe Ss ANT)ADE DIATE Seattle.WA *Denver,CO «Phoenix,AZ ¢Orlando,FL *Columbus.NE ¢Welleslev.MA «Indianapolis.IN ¢Minneanolic MN e Gacramentn CA o Actin TY Mr.Jeff Courier -2-August 1,1985 (3)The initial and minimum purchase price is 18 cents/kWh.One- quarter of the purchase price would be adjusted annually based on oil prices paid by the City;one-quarter of the purchase price would be adjusted annually based on an index of labor costs.One- half of the purchase price would be fixed for the term of the contract.(Article 4,parts a-e.) (4)A system of purchase price reductions is offered the City through a combination of facility use and annual.performance fees.The facility use fee varies with cumulative purchases from the proj- ect.The initial fee paid by ESI to the City 1s 2.5%of the gross revenues to ESI.After specified,cumulative purchase levels are attained,the fee increases to 5.0%,10.0%,and 25.0%. If the City renews its purchase.agreement (in year 31 of thecontract)the facility use fee is automatically set at 50%.The annual performance fee gives.an additional'20.0%of gross reve- nues from the project back to the City.in any year that purchases by the City exceed 6.8 million kWh.(Articles 5 and 6.) (5)After ten years,the City can'purchase portions of the water pipe-line and the transmission line.extending from the project power-house to the City's existing distribution'system.(Article 7.) (6)The City is obliged to undertake certain actions or future responsibilities:.to enhance 'the.project.The current obligations include (i)scheduling water use with ESI (Article 9,part a.), (ii)giving ESI access and permission to modify the existing water diversion structure,and granting ESI associated rights of way and easements (ARticle 8,part 1.),(411)granting ESI a security interest in all its accounts (Article 29,part 1.),and (iv)submitting design specifications for the City's electrical distribution system to ESI for consultation (Article 10,part b). Future obligations of the City would include maintaining a cer- tain level of sales (as explained above)and approval of future 'amendments or termination of the agreement by the project's financier (Article 28.part b). COMMENTS ON CONTRACT (OTHER THAN RATE LEVELS) Overall,the contract is clearly written and is organized in a manner typical of standard agreements between electric utilities and small power producers.However,unlike most purchase agreements by utility systemns,this draft contract goes to great lengths to insure that the City will provide a physically and financially stable market for the project.Comments on the most important contract sections follow. Definitions ESI proposes to require (after.two.years)that,the City purchase exclu-sively from ESI the cumulative energy demand of its customers."Customers"of the City are defined as all persons,entities,etc.,which receive or purchase Mr.Jeff Courier.-3-August 1,1985 energy from the energy distribution system of the City or are interconnected with said system.This broad definition would potentially restrict the City from wheeling electricity to an industrial facility (for example,from a plant on one -side of the harbor to a plant on the other side of the harbor)or providing maintenance or standby services to an industrial facility having its own generation.This definition would also effectively restrict the City from serving any customer not interconnected with its main distribution system.For instance,the City would be economically restricted from temporarily serving an isolated plant prior to extension of its main distribution system. The term "energy"is used in several'different contexts within the contract;however,its definition is simply "electric energy".Coupled with Article 3,which requires the City to purchase any energy offered for sale by ESI,this definition would require the City purchase electricity from ESI regardless of its source.Therefore,notwithstanding the content of the con- tract describing the Pyramid Hydroelectric Project,the source of 'electric energy could come from any plant or plant type chosen by ESI. Purchase of Power The draft contract gives ESI (except during the first two years)the exclusive right to serve any and all energy requirements of the City's custo- mers.The proposed franchise of ESI,however,is one-sided.ESI would not be required to schedule generation or maintenance outages with the City.This would essentially require the City's generation system to serve as permanent backup to ESI.Whenever water or equipment conditions at ESI's project re- quired,the City's generation system would have to stand ready to pickup the load,perhaps,on very short or no notice.While unscheduled purchases from smaller units on a larger system are not unusual,this arrangement would not seem satisfactory to the City from the standpoint of operating economy or overall cost-effectiveness. Fees to the City The fees to the City from ESI seem to represent a troublesome concept. First,neither fee seems to follow its stated function.For instance,the facility use fee is initially quite low and escalate with both the rate of payment and time.Therefore,after several years the facility use fees may be quite large even though it is unlikely that either (1)use of the City's facili ties by ESI will increase during this period or (ii)the City's expenditures on facilities used by ESI will increase during this period. A second problem with a facility use or annual performance fee concept is that it represents a potentially large but unquantified source of revenues to the City.Of course,these fees could be treated as any other revenues of the City and applied towards general administrative and operational costs of the City government and utility services.As such,these fees would represent, in effect,taxes by the City on electric use.The fees paid the City could pepyed Mr.Jeff Courier -4-August 1,1985 also be treated as a net reduction in electrical expenses of the City and returned to its customers in next year's billing.Either as a tax or as a reduction in electrical expenses,receiving this fee at the beginning of each year as a one time,lump-sum payment could present administrative and financtal planning problems for the City.If the fees were to be treated as a reduction in electrical expense,some customers may argue that those who paid the fees during the previous year:should properly be receiving the credit available fromtheESIfees.Trying to calculate and then return credits from the ESI fees to each customer would be a great burden on the utility billing personnel. Finally,the fee system proposed by ESI is a problem for the City simply because ESI would retain the fees.throughout the year,rather than providing a discount to the City as purchases are actually made during the year.This leaves the City at risk thatESIwill be financially solvent andableandwillingtoreturntherevenuesrepresented.by these fees to the Cityinthecomingyear.In this situation,the City could find itself one ofseveralcreditorsawaitingpaymentbyESI.:This.risk should certainly diminish the value of the discount in purchase price .offered |_the City through thesefees.,Lg A facility use fee offered "by ESI is.taittally low,only 2.5%.Overtheyearsthescheduledfeeincreases,eventually..to as much as 25%of grosspowerrevenues.This pattern of «low.initial discount on the purchase rate paidbytheCityallowsESItorecovermost.of.its cost upfront in the contract.The pattern of increasing facilityuse fees may also appear to offer more discount than is actually represented.by the figures.To illustrate better the value of the discounts offered by ESI.to the City,the table below expressed the average discount offered the City throughout various periods of the con- tract based on present value.As shown,the average value of the discount even after 30 years is never greater than 5.4%.0n the basis of its present value to the City.This is far less than the apparent 10%and 25%discounts containedwithinthedraftcontract.settee?Rate Discounts Provided by ESI,Inc. Contract Average Effective Period Rate Rate (Years)Discount Discount* 1-8 3.1%2.9% 1-11 3.8 3.4 1-15 5.6 4.3 1-30 8.2 -5.4 *Based on present value at 10%discount rate. This pattern of rate discounts offered by ESI may also affect produc- tion from the project.In later.years,.ESI could be,rebating to the City as much as 25%of its gross operating revenues.With this rebate,ESI will be Mr.Jeff Courier -5-August 1,1985 less inclined to properly maintain and replace equipment to insure maximum production from the facility.Reduced production by the project in later years of the contract would reduce still further the effective fees paid to the City. Since these fees to be paid the City are not really tied to any facili- ties or services provided to ESI the effect of these fees on the net revenues paid to ESI could be readily reflected in the rates paid to ESI.ReflectingthesediscountsintheratespaidESIwouldreducetheadministrativeburdenof this complicated charge and credit system and would'solve any equity problems the City might have amongst its industrial customers over the collection and potential rebate of these fees.To the extent that the City does provide specific facilities and/or services to ESI in conjunction with this project,a schedule of service fees would be appropriate..*.These fees should reflect theCity's actual or estimated cost of providingthesefacilities or services andcouldbedetailedinaseparateappendix.to the ESI agreement.For example,if the City operates and maintains a transmission line built by ESI,a facilitieschargeof8to12%per year based on the"investment in the line would betypicalofindustrypractice.Also,any "meter testing or other billing related services could be charged ESI .according to a schedule of charges set forth in the City's electric rate tariff or:inan appendix attached to the contract withESI.ne Project Engineering and ConstructionThedraft.contract 'requires each party.to submit to the other its initial design specifications for the,project and the electrical distribution system.The contract.calls on each party to consult with the other regarding design,but does not require either party to accept the proposed modifications or changes of the other party.This creates the possibility that ESI may use inappropriate or inferior equipment or design,causing or contributing to outage on the City system or equipment damage to either the City's equipment or its customers.In addition,the contract specifies that ESI would not be responsible for damage on the City'Ss|system.ESI's proposed freedom from utility design standards is not typical of standard agreements with small power producers.The draft contract should be changed so as to give the City the right to review the design of the project by ESI and require that certain reasonable design and equipment standards be adhered to.The City already has adopted basic design standards for intercon- nection with small power producers.If qualified City personnel are not avail- able,review of ESI's design and equipment specifications could be done at a reasonable cost by an engineering design firm.Moreover,establishing the right of the City to insist upon reasonable design standards could be a valu- able precedent in dealing with future cogenerators or small power producers. The contract language should continue to assure each party that the review process of electrical design will be accomplished as quickly as possible by the appropriate party so as not to unreasonably delay the final design and construction plans of the other party. Mr.Jeff Courier -6 August 1,1985 The draft contract calls for the City to allow ESI to modify,re-engi- neer,or replace all or part of the existing water diversion structure.ThoughArticle27ofthecontractcallsforeachpartytomaintaingeneralliability and property damage insurance,the City should require additional assurances from ESI with respect to the safety and soundness of the modifications to the diversion structure.Such assurances could include detailed review of ESI's proposed re-engineering,and work plan for construction on the diversion struc- ture,a performance bond on behalf of the City for any modification of the diversion structure,and specific property damage and property replacement insurance on the diversion structure naming the City the insured party. Though I don't know the configuration of the City's water supply system,it would seem reasonable that the City approve beforehand the proposed work schedule on the diversion structure by ESI or its contractor in order to minimize any disruptions or impairments to the City's water service. Water Delivery The draft contract calls for ESI and the City to agree to a scheduling process whereby the City will inform ESI of the amount of water required at its chlorinating plant.Presumably,water not required at the chlorinating plant is available to ESI for production of electricity at the project.Because of the importance of the project generation to the City,as well as the seeming interrelatedness of the City's water use at the chlorinating plant and the generation by ESI,the scheduling arrangement agreed to by the parties should also require that ESI inform the City of its planned generation.The exchange of information on each other's operating schedules would be mutually beneficialinplanningoperationandmaintenance. In Article 9,part c,the City is obligated to use its best efforts to maintain water flow at the main powerhouse of ESI's project.The implications of this requirement on the City are unclear to me,but could potentially obli- gate the City to a good deal.For example,efforts to maintain water flow to the powerhouse could require the City to prematurely repair or replace water supply or distribution equipment or police wasteful water use practices of its customers.Clearly,having the maximum amount of water available to its power- house is important to ESI;however,the current language is too broad.The best efforts of the City should be delineated within the contract to itnclude only those operating and maintenance practices which directly affect its water supply and distribution facilities. Extending the City's Customer Base The draft agreement requires the City to make all reasonable efforts to maintain a customer base which would allow ESI to sell at least 7 million kilowatt-hours per year to the City.In addition,the City is required to reinforce and upgrade its distribution system in order that the City can reliably serve all customers during the termofthe contract with ESI.WhiletheseconditionsmayseemreasonablefromESI's point of view,they represent Mr.Jeff Courier -7-August 1,1985 an unknown burden to the City.Moreover,since there is no context in the contract or in other documents of the City and ESI as to the basis for the purchase price,there is little background upon which to judge what is a rea- sonable effort by the City to maintain a customer base and facilitate purchases from ESI.If ESI were selling energy to the City at less cost than would other- wise be incurred by the City it might be reasonable for the City to extend,at its own expense,distribution facilities to connect new customer load.On the other hand,if there is no price advantage or even a slight premium being paid by the City to ESI,it would not seem reasonable for the City to incur addi- tional expense on behalf of ESI to extend its distribution facilities to con- nect new customer load.Hence,reasonable efforts in maintaining a customer base may depend a great deal upon the context in which a purchase price is established with ESI.If the context of the purchase price is not to be con- tained in the agreement (and I suppose that it would not),general statements as to obligations of the parties should be replaced by more detailed descrip-tions.. The obligation of the city to reinforce 'and modify its distribution systems to reliably serve all customers also goes too far.There may be circum-stances which require the City to temporarilyorpermanently isolate portionsofitsdistributionsystem.Financing these reinforcements and line extensions could be an additional problem for the City.Since these modifications to the distribution system would primarily benefit'ESI,:it would be more reasonable tohavetheCityundertakemodificationsofthisdistributionsystemsforthebenefitandattheexpenseofESI. Billing A draft agreement requires that the City install and maintain,at its expense,peak demand and energy meters for the project.The agreement also requires the City test annually the accuracy of these meters and more frequent- ly at the request of ESI.The draft agreement envisions,however,that ESI will maintain its own metering records and may bill the City based on these independent records.The City is required to pay ESI the billed amount even if the City disagrees with ESI's calculation of the monthly payment.The City must forward the entire amount of the billing by ESI and then file a claim for the contested portion.This is unreasonable and illogical;the draft agreement clearly makes the meters installed and maintained by the City the basis for final determination of the energy delivered by ESI and should not allow ESI to bill and retain the monies of the City based on its own records.The agreement should allow ESI access to the metering apparatus and the metering records of the City for visual inspection and review.If the records appear to be in error,the meter registers should be inspected and,if necessary,the meter equipment tested.If the meter or the meter records are in error,the agree ment already proposes procedures for adjustment.However,in all cases,bill- ings to the City by ESI should be based on the meter equipment and records of the City.Furthermore,since the City owns and maintains the equipment and compiles the records upon which any final billing determination will be made, it should not be required to forward additional monies.to ESI which its ownrecordsdispute. Mr.Jeff Courier -8-August 1,1985 Interruption of Deliveries The City is not obligated to accept deliveries from ESI for good cause,such as equipment repair,force majeure or system emergencies.Whenever possible the City is required to give ESI reasonable notice that such interrup- tion or reduction in purchases may be required by the City.Scheduling of purchases from ESI is just as crucial to the City and,.since emergencies and forced outages will also affect the ability of ESI's equipment to deliverelectricitytotheCity,notice requirement of interruption or reduction indeliveriesshouldalsoextendtoESI. General Contract Terms I have reviewed the general contract terms (Articles 20-33).For the most part,the language contained in the draft contract seems to comport with the standard agreements which have .been offeredby other electric utilitysystems.Exception to this similarityis:found in Articles 28,29 and 30 which address,respectively,the City's relationship with the ESI financier,thesecurityinterestgrantedtoESI.by the City,and the default provisions of thecontract.Because of the importanceof these three Articles,their review bycompetentlegalcounsel'of .the.City is”especially,important.Of course thecontractinitsentirety'should be reviewed by the City'8 regal counsel.The City should.note that although 'the.'draft agreement represents both the City of Unalaska and ESI as being incorporated under the laws of the State of Alaska,the agreement itself will be governed under the laws of the State ofCalifornia. Some additional comments on the contract details and suggestions for changes in contract language are contained on the attachment. COMMENTS ON THE PROPOSED PURCHASE PRICE ESI proposes a minimum price of 18 cents/kWh.Of the total rate,25% would be increased (or decreased,if the total rate was still greater than the minimum)to reflect escalation in the cost of fuel ofl delivered to the City. Another 25%of the base rate would be adjusted according to changes in an index of labor costs (with downward adjustments so long as the minimum rate is pre- served).This is a gross rate because ESI also proposes to rebate at least 2.5%of gross revenues after the end of each operating year and,also,rebate an additional 20%on any purchases by the City greater than 6.8 million kWh per year.Based on ESI's target sales level of 7 million kWh,this would reduce the initial rate paid ESI to 17.45 cents per kWh.The rebate (facilities use charge)from ESI would periodically be increased as the cumulative purchases of the City reach contract milestones.When considering the time value of money to the City (and its ratepayers),the discounts offered by ESI amount to about 5.4%per year,or the net initial rate proposed by ESI would approximate 17.0 cents/kWh.(However,this presumes that the larger discounts offered by ESI in the later contract years will be achieved:and*that ESI's:project will continue producing the full 7 million kWh annually.).wae Mr.Jeff Courier -9-August 1,1985 Background on Purchases Under PURPA .The FERC rules implementing the Public Utility Regulatory Policies Act ("PURPA")require that electric utilities pay small power producers a rate which reflects the costs avoided by the utility as a result of the independent purchase.For small power producers wanting to sign long-term contracts,the utility is required to offer rates based either on (1)the avoided costs deter- mined at the time of the purchase or (ii)the avoided costs estimated at the time the contract is executed.Estimating long-term avoided costs was not a procedure well described by the FERC rules,and,in fact,FERC has shown reluc- tance to take on this challenge.While some'utilities which are displacing plant construction through PURPA type purchases have incorporated the estimated capital costs in the contract rates,few utilities have offered contract rates which fix the fuel component.Even California - which has the reputation of offering agressive programs for small power producers --has only temporarily allowed contracts which incorporated estimates of future fuel price in current contract rates.Even then,to obtain:a.ten-year:.price guarantee,the small power producer had to sign at least a 20-year contract. Incorporating future fuel prices,when its been offered in PURPA con- tracts,has been done by two methods:(1)a fixed.escalation rate or schedule of forecast prices is used to adjust future rates,e.g.,rates are increased at 5%per year;or (2)a uniform ("levelized")rate is created by annuitizing the present value of forecast prices.The latter method has been generally shunned by utilities because of the risk involved.in,essentially,pre-paying avoided costs due the small power producer in later contract years.The vast majority of utilities use neither method of .incorporating estimates of future fuel prices and simply offer rates based on savings as actual conditions justify. Estimate of Potential Avoided Costs of the City The City,as a very small electric utility,has few of the operating and planning records available from major utility systems.Therefore,calculat- ing avoided costs,based on actual operations,a short-term estimate,or a long- term estimate is problematic. To estimate the avoided costs of the City,I started with the only information currently available,which were the manufacturers specifications of operating efficiency and the average weekly operating efficiency of one of the City's 600 kW units.I supplemented this data with assumptions concerning the following items: Dispatch order Start-up fuel requirements Minimum and maximum operating range per unit. System peak load (without ESI purchase) System average load (without ESI purchase) Daily load shape (without ESI purchase) -Reduction in system peak load by ESI purchase.Reduction in system average load by ESI purchase ©oo0o00000 Mr.Jeff Courier -10-August 1,1985 The major parameters affecting the avoided cost estimate were based on the discussions of July 20 with ESI representatives.These estimated values include the following (beginning 1987): °Annual generation 17,520 MWh (2 avg.MW) °Annual system load factor -602% °Price of fuel oil -90 cents/gallon .Cost of non-fuel,variable O&M --.7 centé/kWh °General inflation -5%/year *s,a .Fuel price escalation; Years 1-5 -2%/year Years 6-30 -St/year . °ESI dependable capacity at ceysten2 Peak-200iWTheaddedloadon'the city'8 system |was »assumed to "require purchase of a 2,400 kW diesel generator having the same fuel use characteristics estimated by Caterpillar for the 1,450 kW unit.Further,the additional generation wasassumedtocost$700/kWandhave an economic life of 20 years.The annualcarryingcharge(i.e.,cost of money,interim replacements,and general fund transfers)was estimated at 18.6%,or $130/kW-year «The fuel efficiency of all disel generators of the City were estimatedfromthemanufacturer's specifications,except for the Caterpillar 3512 (600 kW)units;the fuel efficiency of the 600 kW units was based on the weekly records of one unit during the period of April to June,1985.Because the weekly records averaged fuel use over higher and lower load conditions,this gauge of fuel efficiency should bias downward the actual fuel efficiency of the 600 kW units measured at a single load level. To analyze the potential savings to the City through purchase from ESI,three representative load conditions were used.These daily load shapes had the following characteristics: Fraction of Average Load Peak Load Annual Peak Load Factor Load Condition (kW)(%)(kW)(2) (1)Winter Peak Day*3330 100 2297 69 (2)Summer Peak Day*2797 84 2013 72 (3)Fall Peak Day*2731 82 -2157 79 *These seasonal references are for discussion purposes and are not based on historical data or estimatesoftheCity.......... Mr.Jeff Courier -ll-August 1,1985 Energy generated by the ESI project was also assumed to vary with the seasonal load conditions as available water flows in Pyramid Creek changed.As indicated in the July 20 meeting,generation in the winter was expected to be at a minimum --approximately 200-400 kW.Maximum generation of up to 1,400 kW was expected in late spring or early summer.The City's hourly loads with and without purchases from ESI are illustrated on Figures 1-3.As indicated on each figure the assumed average generation and generation at system peak were as follows: Peak (kW)Average (kW) (1)Winter Peak Day 200 250 (2)Summer Peak Day 900 900 (3)Fall Peak Day 800 800 For each representative daily load,five operating scenarios were developed.The first three scenarios assumed that ESI purchases resulted in fuel and other O&M savings to the City,but no reduction in plant investment and related annual expenses.These scenarios varied only as to plant dispatch order.Scenarios 4 and 5 assumed that ESI purchases allowed the City to offset 200 kW of capacity when purchasing a new diesel generator.Accordingly,these last two scenarios measured savings in variableand fixed costs of meeting theCity's full system load with an additional:2,400 kW of generator capacity ver- sus meeting its reduced system load with an additional 2,200 kW of generator capacity. The results of the analysis are.depicted by Figures 4-6,showing, respectively,the winter,summer,and fall load conditions.Each figure begins by listing the major assumptions incorporated by the cost calculations.The savings in variable costs include fuel and non-fuel O&M using the base,1987 costs and escalation rates set forth above.Per unit savings are calculated and shown for the first,sixteenth, uniform (or "levelized")savings in scenario.This levelized estimate provides the same present value as actually be accrued by the City due costs of the City escalated at 22, The estimate of levelized savings uniform payment to ESI based on sav provided for illustrative purposes making such a payment offer to ESI. Potential savings and thirtieth year of ESI purchases.A variable costs is also calculated for each of the City's savings over thirty years the sum of escalating savings which would to the ESI purchases as andif variable O&Mthen5%per year over the 30-year period. represents an upper bound for making a ings to the City in variable costs;it is and is not meant to recommend or support in fixed (related to capacity value)and total (variable plus fixed)costs are also displayed for each scenarios in Figures 4-6.Though the estimates used in discussed with ESI,I believe these the City,and,in any case, increase the savings estimate. Based on the calculations calculating capacity cost savings were not fairly represent the potential savings to changes in cost assumptions would not greatly and assumptions indicated by Figures 4-6,the estimated range of savings in annual expenses (of the (City due to purchasesfromESIarethefollowing:toro: Mr.Jeff Courier -12-August 1,1985 Savings to City Through ESI Purchase Variable Costs (cents per kWh): oO 6©First year (1)6.1 -7.2 o Thirtfeth year (30)22.6 -26.5 Fixed Costs (cents per kWh): Oo Over thirty year (30)contract .34 Total Costs (cents per kWh): oOo 6First year (1)6.5 -7.6 ©Thirtfeth year (30)23.0 -26.9 O tLevelized over thirty (30)years [9.3 -10.8 Though the actual conditions experienced by the City or a more elaborate anal- ysis may indicate savings outside the range of-.estimates presented,many fac- tors in the analysis appearto have only minor influence.Of the data used in the analysis,the base price of fuel ofl and generator efficiency appear to have the greatest consequence.In all operating scenarios used in developing the range of estimate savings to the City,the single set of estimates agreed upon in the July 20 meeting with ESI representatives was used for these two parameters.; Preliminary Conclusions and Recommendations for ESI Rates The potential savings in fixed and variable costs of the City clearly do not support the minimum contract rate of 18 cents/kWh offered by ESI.In fact,given the numerous uncertainties about the City's future load,operating and dispatch practices,and equipment fuel efficiency,having any minimum contract rate at this time greater than is justified by the City's limited operating records would place substantial risk on the City unless some offset- ting current or future benefit was offered by ESI. To better illustrate the difference between the total estimated savings to the City through the ESI purchase and the current proposal of ESI, Figure 7 provides a head-to-head comparison:the estimated cost savings to theCityareforecastforthethirtyyearsbeginningin1987andincludethe22%/5% annual escalation in fuel ofl prices and 5%annual escalation in other O&M expenses.The ESI rate is increased based upon these same price forecasts and in accordance with the proposed contract terms.The ESI rate is a net rate, that is,all discounts to the City have been subtracted from the proposed base rates. Initially,the proposed ESI rate is 2.5 times the estimated savings of the City.By the end of the original contract term,the disparity is smaller but would still exact almost a 25%premium from the City. Mr.Jeff Courier -13-August 1,1985 I recommend that the City negotiate with ESI a contract purchase rate on the basis of the following:If a permanent contract rate is required by ESI,the base energy rate should reflect current fuel costs to the City and expected load conditions when and if ESI begins operation.Based on my pre- liminary analysis,this would be about 7.5 cents/kWh.This may be a generous figure since it is at the upper end of the range of.estimated savings and includes anticipated savings in plant construction..Any future rate escalation should be tied to an index representative of the City's fuel costs. An alternative to escalating the energy rate based solely on an indexwouldbetoaddbothanlowerandupperbound.-.This method would guarantee aminimumrateescalationtoESI(and financiers).regardless of future oil prices.As the counter-balance for the City,a maximum escalation rate would also be added to protect the City from rapidly increasing oil prices.For example,the minimum and maximum escalation.rates of 2.5 and 6.0%per year could be established.a a If you have any questions or comments on my review of the ESI con- tract,please let me know.I would-be happy to.send this material,at your direction,to the ESI representatives or to discuss the results of my analysis. WANN < Very truly yours, oS "Re We BECK AND ASSOCIATES (|Yow)CurtisK.Winterfeld Principal Engineer CKW:dch Attachments l. 2. 3. 4. Se 6. 7. 8. 9. 10. Attachment Specific Comments and Suggested Revisions to the ESI Draft Contract Article 1 (b),page 1.Revise the definition of commercial operation date to the following:"The date when the Project is mutually agreed by ESI and Unalaska to be capable of producing sustained energy available for delivery to Unalaska." Article 1 (c),page 2.Change the definition of customers to read as follows:"All persons and entities whatsoever,including natural persons; association;partnerships;corporations;government bodies or agencies;and municipalities,including Unalaska itself and all of its subdivisions and departments,which receive or purchase Energy generated or purchased by Unalaska and which are connected with the main energy distribution system. Article 1 (d),page 2.Change the term to "main energy distribution sys- tem";relocate to appropriate location within Article 1.Change the defini- tion to read as follows:"All stationary plant and associated apparatus owned,operated or leased by Unalaska.for the purpose of transmission of energy and which is electrically connected with the Transmission Line. Article 1 (1),page 3.1 find no reference to Net Income in the current draft agreement.If not reference elsewhere the definition of Net Income should be removed. Article 2 (d),page 4.The agreement calls for an independent appraisal of fair market value if disagreement by the parties.The agreement does not establish who will pay for the independent appraisal. Article 3 (a),page 4 The first two lines should be revised to read as follows:"ESI shall sell and deliver and Unalaska shall purchase and accept all Energy generated by the Project and offered for sale by ESI,". The period on the fifth line after Energy Distribution should be removed. Article 3 (d),page 5.The term "energy"should be capitalized. Article 7 (e),page 10.If disagreement by the parties,the market value of the equipment is determined by an independent appraiser.The agreement does not establish who will pay for the independent appraiser. Article 9 (a),page 11.Revise the penultimate sentence to read as fol- lows:"The Parties shall agree to a schedule according to which (1) Unalaska shall inform ESI of the amounts of water so required and (ii)ESI shall inform Unalaska of the amount of Energy available from the Project." Article 9 (c),page 12.Modify this section to read as follows:"Unalaska shall,at its sole expense,use reasonable efforts'in its operating and maintenance practices of its water supply and distribution facilities so as to maintain the water flow to the Main Powerhouse."... ll. 12. 13. 14, 15. 16. 17. 18. "Je Article 10 (b),page 12.The term at the end of the first sentence should be revised to read as,"Energy Distribution System"., Article 12 (a)(3),page 15.Capitalize the term "facility". Article 14,page 16.Capitalize the term "energy". Article 17 (a),page 17.Capitalize the term "capital". Article 17 (a),page 18.Change the first full sentence beginning "ESI shall deliver ..."to read as follows:"ESI shall delivery to Unalaska a bill based upon the amount of Energy shown on the statement provided by Unalaska.This bill will show the following information:(1)The Energy delivered to Unalaska daily and.during peak periods during the monthlybillingperiodasreflectedinthestatementprovidedbyUnalaska;and (2)ESI's computation of the amount due ESI from Unalaska."Article 17 (b),page 18.Revise the second 'sentence to read as follows: "In the event that Unalaska disagrees with ESI's calculation of such pay- ment,Unalaska shall include with =such -payment'a statement of disagreementshowing:see".Strike patagraph (1)under this section.Article 17 (c),page 19.Revise paragraph a)to read as follows:"Make such refund or indicate in writing :its agreement to accept additional pay-ment."Strike paragraph (2).Article 26 (bd),page 2h.Revise."all references in this section to the term"Project"to the term "Facility".The term Project is defined to include all Transmission Line and Replacement Pipeline which may have previouslybeenpurchasedbyUnalaska.. Unalaska Electrical Load ES!Purchase:200 kW Peak,250 kW Avg a 4 3.5 - ; 3-ae a :=. yp 77 :Sy ->161)l7owueLy-|fe00 1 4 7 10 13 16 19 22 HOUR (#1 =12 midnight)0 86 Without ESI Purch -With ESI Purch [Tean3zy aa"NetHourlyLoad(kWyOFEentlytess(W)Unalaska Electrical Load ESI Purchase:900 kW Peak,900 kW Avg 3.5 + a] eA ELE A nn SE ae a47101316 19 HOUR (#1 =12 midnight)--With ES!PurchWithoutES]Purch ZPin3yzy *eessands)OY3RenUnalaska Electrical Load ES!Purchase:800 kW Peak,800 kW Avg o 2.5 4 NDJfeya) T t v |7 ms J v .-|LJ LJ ij a v 4 7 10 13 16 19 HOUR (#1 =12 midnight)Without ES]Purch -With ESI Purch €ean3ty Figure 4 UMNALASKAerryoF ESTIMATED AVOIDED COSTS UNDER ALTERNATIVE PURCHASE,LOAD,AND OPERATING ASSUMP TIONS Cad t SYSTEM PEAK LOAD Ck 3220 SYSTEN AVERAGE LOAD avg kM 2297 @ Percent eof Anneal Peak 100% @ Baily Lead Facter 69% WET PEAK LOAD (After ESI Purchase)ck 3130 WET AVERAGE LOAD (After ESI Purchase)CAvg kM)2ON7 ESI GENERATION Cavg kM 250 DISPATCH OROER 300 kM Unit 300 kM Unit 600 kM Unit 600 KM Unit 600 kM Unit 4950 aM Unit 2 2400 kM Unit a 2200 &M Unit . NON-FUEL,VARIABLE O88 EXPENSE CCents/kun) First year (4)O07 Thirtietn year ¢€30)2.9 FUEL USE STATISTICS? FUEL EFFICIENCY Per Operating Records x Per Manufacturer's Specs FUEL COST TO UNALASKA CCents/gaiten> First year €1)90 Thirtieth year (30)330 «b>te?ca ce? SYSTEN MINTER PEAK DAY 3 3330 3330 3220 3330 2297 2297 2297 2297 100%100%200%100x 69x OnE 69%69% 3130 3130 3130 3130 2047 2047 2047 2047 250°.280 250 250 ®5 2 * r 5 2 2 2 »"2 3 ® nr '2 a 1 a 0.7 0.7 O.7 0.7 2.9 2.9 2.9 2.9 x x x x #0 90 v0 90 330 330 330 330 SECS EEESE $SSTS E8EES $4EEE EEESS £EEES $EEEEOEEEE SEES EEEEE $EESSEEEEEEEEEE$EESSESEES$EESEEEESSE AVOIDED VARIABLE COSTS @ YEAR-BY-YEAR PAYMENT First year (2) Bixteenth year (16) TRirtieth year (30) @ CEVELIZED PAYMENT Over thirty-year (30)centract CCents/kWh) 6.01 11.29 22.36 8.80 SYSTEN MINTER PEAK DAY ' 6.41 6.51 6.64 6.07 42.02 42.622 420894039 23.80 24.19 29.69 22.86 9.37 9.52 9.70 e.e8 SESES FESS 4464S CESSES $EESS EEEEE SERED EEESS E648 $EEES E4448 $ESEEEEESS EEEES EEESS $EESS $4888 FECES AVOIDED CAPACITY COSTS TOTAL AVOIDED COSTS e 8 6First year@Cevelized ever thirty-years (30) CCentsskun>0.00)0.00 «00 aa 4049 Cents /kMh> COUP PAL PELEASES UNTR AUTHOELED 6.04.6e84-. 6eBL-7082 7026 @.80 9.37 «=9.52 2S 20.89 10.07 Figure 5 erry oF UN ALASKA ESTIMATED AVOIDED COSTS UNDER ALTERNATIVE PURCHASE,LOAD,AND OPERATING ASSUMPTIONS «¢g>?ch?aD « ; t TYPICAL SUMMER PEAK DAY 3 SYSTEM PEAK LOAD chm 2797 2797 2797 2797 2797 SYSTEM AVERAGE LOAD .CAvg kW 2012 20132-2012 2033 2013 e Percent ef Annual Peak -etx etx e4x Ox Sx e@ Oaily Lead Factor 72%72%72x 72%72% WET PEAK LOAD CAfter ESI Purchase)cum 4297 1097 1897 12897 1997 WET AVERAGE LOAD (After ESI Purchase)tavg kW)4413.4833 583 4143 4413 EST GENERATION Cavg kM 900 900 ©=900 900 900 DISPATCH ORDER oe a 300 KM Unit es ae a 5 2 % 300 kM Unit 7 5 600 &H Unit z 2 2 600 kM Unit >3 2 600 kM Unit oe a4SO kM Unit on 2 mg 2 2R00 KM Unit :4 1 2200 kM Unit Bo a 2 NOM-FUEL,VARIABLE OOM EXPENSE ©(Cents/kin) First year ¢1)OcT ==§s as OP'0.7 0.7 Thirtieth year (30)2.9 2.9 2.9 2.9 2.9 FUEL USE STATISTICS: FUEL SFFICIENCY Per Operating Recerds x x x x x Per Manufacturer's Specs FUEL COST TO UNALASKA (Cents/galien? First year ¢1)a 90 90 90 90 90 Thirtieth year (30)330 330 330 330 330 SECC $SS ES EEEEEEEEEE $4944 SESESEEEEE ESESS$EESS FEES ESTES OEEESEESES FEES EESES £4844 $4E8S SEESS AVOIDED VARIABLE COSTS CCente/kun)> c TYPICAL SUMMER PEAK DAY 1 e VYEAR-BY-YEAR PAYMENT First year ¢2>6.99 6-62 Veit 7.1 6.78 Sixteenth year (16)£3.20 42.41 43.43 43.39 12.70 Thirtieth year (30)28.93 24.88 26.59 26.51 25.16 e LEVELIZED PAYMENT Over thirty-year (30)centract 20.214 9.68 10.97 20.44 e.91 CUESE ROLES ESSESEEEEESERELERSSETEREERASESESEELEEESEEESSESEEeEsEEeeseeeeeeeeseseseeeseesee AVOIDED CAPACITY COSTS CCents/kwn)0.00 0.00.0.00 0.33 0.33 TOTAL AVOIDED COSTS CCents/kWh>oom cr poy ye ftpTeemers ©First yeor 99 oerMea?7.48 788 a Levelizsed aver thirtwevenre f 2h 10.94 @.42 4A_ae aa_e9 enon erTty OF ESTIMATED AVOIDED COSTS UNDER ALTERNATIVE PURCHASE,LOAD,AND OPERATING ASSUMPTIONS t ck) Cc SYSTEM PEAK LOAD CkM)2731 SYSTEM AVERAGE LOAD CAvg &kM>2187 e Percent of Annual Peak 2x @ Baily Lead Factor 79% WET PEAK LOAD Cafter EST Purchase)Ck)1931 WET AVERAGE LOAD (After ESI Purchase)(Avg km)2357 ESI GENERATION Cavg kD 800 OXSPATCH ORDER 700 KM Unit 300 GH Unit 600 KM Unit 600 kN Unit 600 kM Unit .ag! 1950 kM Unit ee a 2400 KN Unit ee a 2200 kM Unit "=ea oy WON-FUEL,VARIABLE OOM EXPENSE (Cents /kun)- First year ¢2)7 ae my 0.7 Thirtietnh year (30)2.9 FUEL USE STATISTICS: FUEL EFFICIENCY Per Operating Records Ko Per Manufacturer's Specs FUEL COST TO UNALASKA CCents/gatiend-"- First year ¢1)_--90 Thirtieth year (30)330 UNALASKA BOSSE SESS 4S $ESES SEEESEEESE TEESE EESEEEESES SESE $548 $E4ES $EEEE ESSERE ESESS st AVOIDED VARIABLE COSTS CCents/kun) t @ YEAR-BY-YEAR PAYRENT First year (1)6.59 Sixteenth year (16)12.36 Thirtieth year (30)24.97 @ CEVELIZED PAYMENT Over thirty-year (30)centract 9.63 $6406 60468 68888 £6688 $5404 £60580858S £50ES 64948 £5054 FOES S £0584 9088884988 54888 OTS AVOIDED CAPACITY COSTS cCentssumnd 0.00 TOTAL AVOIDED COSTS cCents reund ae ©8 6First year ad @ Levelized ever thirty-years (30) We 9.63 6.59 * Figure 6 rer)ree cn?ce) TYPICAL FALL PEAK DAY ) 2734 2731 2734 2731 2157 2157 =-2187 2157 / e2x (e2x 82x 82x 79x |79%79%79% 2934 1938 1931 1931 4357 4357 4357 4357 800 800 800 #00 @ fs 3 § PaaS § 2.2 2 oe 2 2 -me,ee wt 2 1 :a a Oe?O07 0.7 0.7 2.9 2.9 2.9 2.9 x x x x 90 90 v0 90 330 330 330 330 Feseseecececeees TYPICAL FALL PEAK DAY ' 6.16 7029 6.80 6.37 41.56 13096 9 12076 44296 22.88 26.65 28026 23.67 9.01 10.50 9.95 9.32 +ee0e¢* "@000°-0800-«7 0.37 ae ie Q Se O0lb 3 7.19.on 7-18 6.7% 9.01 20.50 20.32 9.69 Figure 7 CITY OF UNALASKA' Anolyzis of ESI Rote Propesol T 2017 T 2012 LJ 1992 T 1987 2]"1 10- °o wi o mn "n N N ANOY-AGAOp| Jad syU9q 2022 t 2007 T 19971982 -2002 Year GO City's Avolded Cost a--ES Proposed Rote CITY OF UNALASKA Anolysiz of ES!Rote Propossl #HZ/-! CEISAOAQY K#Z@?@'!-! dwtRNACLT:DOOOOOOOOYSYMONCKOTE:MOONYNOOSA 110% WML.T -r 1982 1987 1992 1997 2002 2007 2012 2017 2022 ny BY €5 Proposed RoteZZ)City's Awided Cost