Loading...
HomeMy WebLinkAboutSummary of Well Testing Unalaska Island 1984'D ..2 56.97.09| RECEIVED Summary of the Well Testing on Well ST-1,Unalaska Island,1984 NOV 05 1984 ALASKA POWER AUTHORITY Summar Analysis of an extended flow test of well ST-1 on the flanks of Makushin Volcano indicates an extensive,water-dominated,naturally fractured reservoir.The reservoir appears to be capable of delivering extremely large flows when tapped by full-size production wells.A productivity index in excess of 30,000 Ib/hr/psi implies a phenomenal permeability-thickness product,in the range of 500,000 to 1,000,000 md-ft. The flowing bottomhole (1,950-foot)temperature of the fluid ts 379°F, which 1s lower than the measured static temperature at that depth (395°F). This phenomenon,coupled with an observed static temperature gradient reversal from the maximum 399°F observed at 1,500 feet,indicates that the reservoir proper is located some distance from the well,communicating via a high conductivity fracture system. A material balance calculation yields an estimate of reserves that are capable of sustaining ail of the present power needs of the island (13+MW) with a geothermal power plant for several hundred years.Theoretically,a single large diameter well at the site of ST-1 could satisfy this requirement. Introduction Unalaska Island,located in the central portion of the Aleutian Chain has been the site of a multi-year exploration program for the evaluation of its geothermal energy potential. Makushin Volcano,the 6,680-foot high active volcano,situated on the northern end of the island,has a large number of surface manifestations, including extensive fumarole fields. Following extensive geological,geophysical,and geochemical surveys of the Makushin region,three +1,500-foot temperature gradient holes were sited and drilled in the summer of 1982. The holes and their temperature gradients were described by Isselhardt,et al (1983a)who also provided a geothermal resource model of the Makushin geothermal area (Isselhardt et al,1983b). The heat source of the Makushin geothermal system appears to be a buried igneous intrusion associated with the volcano.The temperature and post-glacial volcanic distributions suggest that the heat source for the system is not directly beneath the summit,but rather is offset to the east. The location of the Makushin potentially producing horizon appears to be structurally controlled by a major northeasterly striking fracture zone.The reservoir its situated in fractured dionite. In the summer of 1983,a stratigraphic test well (ST-1)was drilled near one of the 1982 temperature gradient holes (E-1).A steam zone was encountered at 672 feet,followed by a significant fracture at 1,946 feet where the drilistem dropped free for three feet. The 1983 well testing described by Campbell and Economides (1983) confirmed a highly productive reservoir producing 47,000 1b/hr through three-inch pipe and little pressure drawdown.Insensitive pressure instrumentation prevented vigorous analysis.A productivity index of over 3,000 Ib/hr/psi and a permeability thickness of over 50,000 md-ft were inferred.A long flow testing in the summer of 1984 was to provide a better estimate of these reservoir parameters. Test Facilities and Instrumentation The surface equipment utilized during the 1984 testing was basically the same as that used in 1983 and described by Republic's (1983)report by Campbell and Economides.A relatively simple two-phase orifice meter and James tube were installed at the end of the flow line to measure the Flow rate.Upstream and downstream orifice pressures were recorded simultaneously with a differential pressure flow meter.The James tube lip pressure was monitored continuously during the flow test utilizing both a test quality pressure gauge and a Barton pressure recording meter.In addition,the wellhead pressure and temperature were recorded continuously on Barton meters throughout the flow test.The orifice plate described above is utilized to calculate the enthalpy of the fluid using the empirical equation developed by Russel James.Figures 1 and 2 show the surface equipment arrangements utilized during the long-term test of 1984. The downhole pressure and temperature measurements were obtained using two separate monitoring systems.The pressure monitoring equipment was a capillary tube system which utilizes a gas filled,volumetric chamber downhole connected to a very small diameter capillary tube with a surface recording pressure transducer.This equipment was filled with helium gas as the pressure transmitting medium from the bottomhole location to the surface transducer.The equipment utilized in this test has an accuracy of approximately 0.3 psi with a sensitivity of 0.1 psi on the transducer.The temperature measurements were obtained using a thermocouple cable system completely separate from the capillary tube.This required that the temperature data and the pressure data be acquired in separate runs in the well.The thermocouple was a chromel-alumel,grounded junction-type with an accuracy of +3 degrees and a sensitivity of +3/4 of a degree.The thermocouple cable and the capillary tube were contained on two separate spools.The surface arrangements for both systems are illustrated in Figure 3.As will be seen in the data discussed later,the pressure data and the temperature data were found to be quite reproducible throughout the flow test. Flow Test Measurements The test of ST-1 consisted of two flow periods of approximately 33,000 lb/hr and 63,000 1b/hr each.The first flow period lasted 15 days, while the second flow period at the higher rate lasted 19 days.During the 34 days of flow from ST-1,there were several minor changes in the flow rate and/or a bypass of the measuring system in order to perform sampling experiments or to modify the flow equipment.However,the test proceeded relatively smoothly with the two flow rates being maintained at essentially constant conditions throughout their respective test periods. Prior to the initiation of flow from ST-13,a static temperature profile through the wellbore was obtained on July 3 and a static pressure profile was obtained on July 4 as shown in Figures 4 and 5.These surveys clearly indicate that the well has a steam zone with the vapor-liquid interface located at 825 feet.This is shown by the constant temperature and pressure conditions existing in the upper part of the wellbore.Below 825 feet there is a liquid zone which increases to a maximum temperature of 399°F at the 1,500-foot depth,then shows a slight decline to a temperature of 395°F at the bottom of the wellbore (1,950 feet).The slight temperature decline from the 1,500 feet to 1,950 feet suggests a temperature reversal in the reservoir. The higher temperatures indicated by geothermometers could be significantly deeper. After flow was initiated on July 5,1984,the well stabilized at a flow rate of about 33,000 lb/hr and this condition was maintained until July 20,1984.During this flow period the pressure tool was left at the bottom of the well (1,950 feet)continuously recording bottomhole pressure, except for the times when wellbore pressure and temperature profiles were being obtained.Flowing pressure and temperature profiles were obtained on July 6.The results are shown in Figures 6 and 7.A second pressure profile was obtained on July 19 (Figure 8),followed by a second temperature profile on July 20,1984 (Figure 9).Following the change in the flow to the higher rate of 63,000 lb/hr on July 20,another temperature profile was obtained 4 through the wellbore (Figure 10).On July 21,a high-rate pressure profile was obtained (Figure 11)and again,on July 7,1984 a pressure profile was obtained (Figure 12).A final pressure and temperature profile was obtained in the ST-1 well on September BLANK (Figures 13 and 14)1984,BLANK days after the well was shut-in.These profiles constitute the full suite of temperature/pressure profile surveys during the ST-1 test.In addition, during the second stage high-rate flow period,the pressure tool was again left at the bottom of the hole continuously recording bottomhole pressure until August 8,1984.These 11 profile surveys are illustrated in Figures 13 and 14.The well was shut-in on August 8,1984 with the pressure tool hanging in the well at 1,940 feet.The pressure tool recorded the buildup data for the next three days without showing a significant increase in bottomhole pressure.Figure 15 depicts a summary of pressures and temperatures recorded during the 1984 testing of ST-1. Discussion of Results The test rate/wellhead pressure history is shown tn Figure 15.The flowing conditions of the well were relatively stable at the low rate and extremely stable at the high flow rate.Although the resolution of the pressure equipment utilized during this test was far superior to that utilized during the 1983 test program,it was again found that the drawdown pressure response in ST-1 was extremely small,beyond the sensitivity of the tool.A precise interpretation of the data is not possible.Within the sensitivity of .the instrument it appears that the pressure drawdown during the first stage low-rate flow period was on the order of one psi,while the pressure drawdown in ST-1 during the high flow rate,second stage was on the order of two psi. Thus,the productivity index derived from the two flow periods equals 31,000-33,000 Ib/hr/psi.These values are very large (an order of magnitude more than the ones speculate in 1983)and indicative that the productivity of the Makushin reservoir is extremely large.The data obtained from the 1984 flow test of ST-1 may not allow the precise calculation of the permeability-thickness product,although it is easy to infer that the value is phenomenally large.The pressure buildup data suggest that when the well was shut-down the bottomhole pressure changed less than one psi from the flowing condition after more than three days. In ST-1 produced fluid enters the wellbore at the bottom of the well,near 1,950 feet,at a temperature of 379°F which is less than the static temperature in the wellbore at that level (395°F).This indicates that colder water is entering a fracture zone of the well from some other area of the reservoir along an unknown fracture path.The actual communication between the steam and the liquid zone outside of the wellbore is unknown.During the shut-in,the colder water 1s restricted and the wellbore would heat up to its static condition.This would mean that the fluid density within the wellbore column will lighten over a period of time as it returns to its static temperature level,and thus reduce the measured pressure buildup. Any temperature disturbance changes the pressure gradient.Under these conditions,accurate reservoir pressure can only be measured opposite the producing zones,and then only after temperature and pressure equilibria have been reached in the wellbore.If the gradient pivots around one point at depth during heating or cooling,that depth is assumed to be the main fluid entry zone.For two or more entry zones,the pivot point is located somewhere in the interval between the highest and lowest entry zone,its actual position being dependent on the potential and permeability of the respective zones. Thus,the re-equilibration of the wellbore fluid temperature to static conditions after the well was shut-in and the existence of the steam cap may have obscured the pressure buildup data. In addition to the pressure data,it was found during the recovery of the pressure tool on July 19,1984,that a layer of calcium carbonate on the order of 1/16 of an inch thick had built up on the capillary tubing exterior surface at about the 1,100-foot level.This scale must have come from the chemical reaction of the CO,gases evolving from the liquid or the steam cap.This calcite layer had built up during the 13-day period when the capillary tube was hung at the bottom of the well.It is interesting to note that when the 6 capillary tube was hung in the well during the second flow period for 16 days, no scale buildup was observed on the capillary tubing over its entire length. As was observed during the 1983 test program there was noncondensable gas buildup in the wellbore when the well was shut-in.The pressure at the wellhead began to increase from the shut-in pressure level to a maximum value of approximately 140 psi. Reserve Estimation Using a Material Balance Calculation for the Makushin Geothermal Reservoir The material balance calculations for largely incompressible systems such as the one at the Makushin geothermal reservoir have been developed and used by a number of investigators in the petroleum literature.The initiating step 4s an expression providing the isothermal compressibility. C=-4 (IV)T (1) Vv Assuming that the total compressibility of the system is constant,Equation 1 may be integrated: V2 =ecdp (2) I and since the recovery in terms of reservoir volumes is defined as r =V2-Vl (3) v1 then a combination of Equations 2 and 3 results in V2-v1 =eCAP -](4) v1 The cumulative production in terms of reservoir volumes is,of course, V2-V1 and since the fluid is considered as incompressible,then the ratio V2-V1 v1 may be taken as:Wp,which is the ratio of the cumulative mass produced to the W initial mass -in-place.Hence,Equation 4 becomes Wp =eC4p -}(5) W of the variables in Equation 5,WP is the one known with certainty.In this case Wp is equal to Wp =33,000 x 15 x 24 +63,000 x 19 x 24 =4.06 x 107 Tbs reflecting the two flow periods. The variables contained in the exponential expression consist of the total compressibility of the system and the average reservoir pressure drop observed during the flow period.In this system,the total compressibility is the sum of the individual rock and fluid compressibilities. Ct =Cy +Cf (6) The fluid compressibility is normally taken as 3 x 1076 psiv!while the compressibility of the rock could range between 2 x 107°psi7!for hard matrix and 6 x 107°psi !depending on the lithology and the elasticity of the geologic features.For most reservoirs the value of the compressibility1stakenasequalto3.x 10°°pst-!.This value will be used here with the knowledge that it could be somewhat higher. The observed bottomhole pressure drop at ST-1 during the 34 days of the flow test was 1.7 psi.The subsequent pressure buildup test resulted in, perhaps,less than one psi pressure gain.Both tests indicate an extremely large permeability-thickness product which 1s consistent with the small pressure differences observed.Hence,the total average reservoir pressure drop could be taken as roughly one psi. Using Equation 5,the initial fluid in place may then be calculated 4.06x10)=e &X 10-6 x1 _y W yielding W =6.8 x 1012 Ibs This value could range from 4.5 x 10'*(using C,=9 x 10”pst”')to 8.1 x 10'?(using C,=5 x 10°pst”').In any case,assuming a full-size production well on the site of ST-1 that could yield 1,000,000 PPH (depending on the technology used it could generate 7-11 MWe)the longevity of this reservoir is extremely large.The calculated initial -mass-in-place could deliver this flow rate for 776 "years”while the other two reserve estimations could deliver 514 or 925 "years”respectively. Conclusions Results from the slim hole ST-1 flow test in 1984 confirmed the basic model of a shallow steam zone overlying a liquid-dominated reservoir in fractured diorite.A flowing temperature at 1,950 feet was found to be 379°F.This fluid appears to be entering the wellbore along a fracture which brings in colder water than would be suggested by the 395-399°F static temperature of this reservoir zone.The flow testing of the wel]proved that the reservoir is potentially highly productive even with only a few feet of fracture interval open to the wellbore.Flow through a 3-inch diameter wellbore on the order of 63,000 lb/hr,with essentially no pressure drawdown, suggests a very large permeabiltty-thickness value for the reservoir.The well productivity index obtained during this test was approximately 30,000 Ib/hr/pst.No estimate of the reservoir recharge is possible at this time.Thus,the data obtained during the 1984 flow test supports the results obtained during the short-term flow test of 1983. FIGUREZ MAKUSHIN ST-1 WELLHEAD DRAWING FOR SUSPENSION STATUS 3°X2”ADAPTER FLANGE V/2"BALL VALVE PRESSURE GAUGE 3”SWAB GATE§°X3"ADAPTER FLANGE]1/2”BALL VALVE |4°FLOW LINE.5 THROTTLING VALVE 6°XE7"X4"pH ee, 600 RTJ i ule”S-49FLOWTEE-lowe rere6°X4"AGAFTER NE .->4.626 . r a =7 DISCONNECTED FLOW LINE & TESTING EQUIPMENT 87600 RTJ BARTON (40°LENGTH) MASTER VALVE ; WA Den cr &ve i o6°XS”"ADAPTER FLANGE a 1 b Dohaedky£-.= i |wee Ss -- CASING PRESSURE |ef 87-600 AT]WKM&TEMP.GAUGES Pp MASTER VALVE =2”VALVES (2A Ee L ma(0¢]un[0%4)mmr tanmeenn{o7o}en (0"6) r \NEEDLE VALVE /50°.2°KILL LINE >CASING EXPANSION ' WING VALVE SPOOL 2”CASING WINGTOBACKOF1/2"BALL VALVES (2) SUBSTRUCTURE |VALVE Layee SS.BLEEDLINE fC : tL _} NOTES: (1)ALL WELLHEAD VALVES &FITTINGS ARE SERIES 600 (2000 os:t WORKING PRESSURE. (2)MASTER VALVES,4°THROTTLING VALVE, 2"SWAB GATE &2°WING VALVES TO 83E CHAINED &LOCKED. (2)WELL TO BE MONITORED MONTHLY AND ALL GAUGE READINGS REPORTED TO AGI.TF RGi E°St1é FIGURE 3. MAKUSHIN WELL TEST EQUIPMENT 1ay yeth WELLHEAD FLOW tree)hyIntOMFIcESAMPLES BYPASS LIP PRESSURE ™>»vw)OQ _ e) =|HYDRAULIC STUFFING BOX COLLAR el |}b)LIFTING CLAMP CAPILLARY TUBE 'LUBRICATOR GIN POLE LIFTING CABLE . ">BLEED-OFF VALVE bs KNOCK-OFF UNION WINCH | 7 ;&|Capitlany Tube ov Thérwocovsfe wireTek|SPOOL :@@=n)3 \3|D gitHM|=|meASURING \{ GIN POLE DEVICE :BRACKET ™Z a (|pea S )600 FLANGE |X c we )-<5 HAY PULLEY DEPTHINFEETSTATI.TEMPERATURE ST-14 JULY 3,1984 0 50 100 1450 200 250 300 350 400 450 500 550 600 0 0 ---TEMPERATURE 200 200 400 :400 600 |600 B00 B00 4000 4000 4200 4200 4400 |4400 4600 4600 4800 .4800 * a 2000 2000 0 50 400 450 200 250 300 350 400 450 500 550 600 TEMPERATURE (DEGREES F) DEPTHINFEETSTAC PRESSURE '-14 JULY 4,1984 _| 0 50 400 450 200 250 300 350 400 450 500 550 600 0 0 Tt ---PRESSURE 200 200 400 400 600 600 800 800 4000 '4000 4200 a 4200 \4400 is 1400 'N \N4800 -4600 NI '\1800 x 1800 Ne 2000 2000 O 50 100 450 200 250 300 350 400 450 500 550 600 PRESSURE (PSIG) DEPTHINFEETl¥-_rr FLOWZNG PRESSURE TT-1 JULY 6,1984 0 50 400 450 200 250 300 350 400 450 500 550 600 0 0 t ---PRESSURE 200 7 200 400 \400 * 600 \600 B00 'B00 4000 4000 ,\4200 -T 4200 N\ \4400 :4400 NN 4600 i 4600 4800 _4800 2000 2000 O 50 400 450 200 250 3006 350 400 450 500 550 600 PRESSURE (PSIG) DEPTHINFEETads FLOWI!5 TEMPERATURL ST-4 JULY 6,1984 0 50 400 450 200 250 300 350 400 450 500 550 600 0 0 3 --TEWPERA TURE200 200 400 - 400 500 500 B00 .BOO 1000.1 4000 4200 4200 '. 4400 1400a 4600 46500 4800 4800 * 2000 2000 O 50 100 450 200 250 300 350 400 450 500 550 600 TEMPERATURE (DEGREES F) DEPTHINFEETliye FLOWLNG PRESSURE _T-4 JULY 19,1984 0 50 400 450 200 250 300 350 400 450 500 550 600 9 0 \---PRESSURE 200 200 \400 400 600 |600 B00 B00 4000 4000 4200 .4200 4400 N.4400 \4600 N 4600 4800 N 4800 2000 3 2000 0 50 100 450 200 250 300 350 400 450 500 550 600 PRESSURE (PSI15) DEPTHINFEETVoneyy FLOWI..3 TEMPERATURL ST-14 JULY 20,1984 0 50 400 450 200 250 3CO0 350 400 450 500 550 600 ---TEMPERATURE 200 200 500 400 800 1 800 4000 4000 4200 4200 * 4400 £400 4600 4600 * 4800 4800 * 2000 2000 O 50 100 450 200 250 300 350 400 450 500 550 600 TEMPERATURE (DEGREES F) DEPTHINFEET200 400 600 800 4000 1200 4400 4600 4800 2000 1 ofFLOWI..3 TEMPERATUR JULY 20,41984 0 50 400 450 200 250 300 350 400 450 500 550 600 -_TEMPERA TURE \ \ | 4 * 0 50 400 450 200 250 200 350 400 450 500 550 600 TEMPERATURE (DEGREES F) 200 409 6500 B00 1000 1200 4400 4600 1800 2000 DEPTHINFEET200 600 B00 1000 1200 1400 1600 4800 2000 rij'FLOWX.NG)PRESSURE _T-14 JULY 21,1984 0 50 400 450 200 250 300 350 400 450 500 550 600 ---PRESSURE \ \ \Nn N\IN| \iN i '\ K C 50 400 450 200 250 300 350 400 450 500 550 60: PRESSURE (PSIG } 200 490 600 800 4000 1200 1400 1600 1800 2000 DEPTHINFEET200 400 600 BOO 1000 1200 1400 1600 4800 2000 a?pas FLOWisNG PRESSURE WTT-14 AUGUST 7,1984 C 50 100 450 200 250 300 350 400 450 500 550 600 N\ NO \' 0 50 400 450 200 250 300 350 400 450 500 550 600 PRESSURE (PS IS)- 400 500 800 1000 4200 4400 4600 1800 2000 STATIC TEWMPERLTYKE ST-|[ CoP Tie PRESSLY Ce ST-/ SepT 7 i9¢4 ca”,Saereme ee iiqeyy) Gag |1E382 188 38ae23389388oh NATIONAL ey e '$tt f e KN Ly TO a ee eee ae eeeoe ne33.000th/Wn rate F 'LOW RATE HIGH RATE =2.07 nozzle 3,0"nozele \I"hIs"ORIFICE 3.49”omSice - ||{{\ 0 5 /0 1S 10 7S yD =Ai UA KUSH/ ST-1 Flow TESTJohy August 1994 5SQUARE5SQUARE5SQUARE£mesNATIONAL $8.07.01 APO DISCUSSION DRAFT CITY OF UNALASKA ELECTRICAL RATE AND LOAD PROJECTION STUDY NOVEMBER,1984 Introductions: The accompanying Electrical Rate and Load projection Study was pre- pared pursuant to the request for proposal from the City of Unalaska dated November 16,1983. The City of Unalaska (City)is substantially expanding the electric distribution system and changing the power production facilities. This expansion allows the City's electric system to serve additional customers,some of whom have been providing for their own electrical needs.Associated with the system expansion,the City has incurred new debt.Accordingly,revision of the rates charged for electrical services are required in order to provide for the increase in depre- ciation and debt service relating to these new facilities. In addition to the above,the City desires a long-range planning guide in order to anticipate system requirements in the future and establish preliminary alternatives to meet those requirements. The computations presented with this report in tables 1 through 9 were processed on a model developed by Mr.Jim Patras of Arthur Young and Company and Mr.James R.Hendershot,Rate Consultant,using an elec- tronic spreadsheet program (Lotus 1-2-3).The purpose of developing the model are: Exhibit To process the information and assumptions required to pre- pare the accompanying report. To provide the capability to respond instantly to any changes in assumptions or rate designs arising from the presentation of a draft report to the City Council and Management. To provide a tool for future forecasting and rate deter- mination as conditions and assumptions change. I,Scopes of Services and Presentation,presents the seven tasks undertaken in this engagement.The underscored items represent increases in the scope of services not contemplated in the proposal to provide services submitted by Arthur Young. 2. SCOPE OF SERVICES AND PRESENTATION CITY OF UNALASKA ELECTRICAL RATE AND LOAD PROJECTION STUDY Analyze the service area and existing studies on demographics, economic,and energy use forecasts to estimate loads and peak demands the next twenty years on at least five year increments. Analyze the existing service area to determine the economic viabi- lity of system expansion to currently unserved consumers and the willingness of those potential consumers to purchase power from the City including the rates that potential consumers would con- Sider economic and the amount and timing of potential purchase of electricity from the City. Analyze the service area with respect to existing electrical generation systems in order to determine cogeneration potential. Estimate the City's avoided costs (broken down into energy and capacity avoided costs)and provide an estimate of the value of cogenerated power to the City.Analyze the effect of the City's cogeneration policy ordinance on the economics of cogenerated power and,if appropriate,make recommendations for revisions to the ordinance. Analyze the waste heat recovery potential for sale and consequent reduction of system operating costs. Analyze the existing City electrical system,planned upgrades, cogeneration potential,and waste heat recovery potential andprovideacapacityadditionplanandacapacityretirementplan. Determine the rate requirements necessary for operation,main- tenance and debt retirement. Analyze rate structure and load management alternatives based on the existing system,planned upgrades,and capacity addition and retirement plans in order to determine options that would levelize daily peak capacity demands and stabilize load factors. Provide the City of Unalaska with a written report that presents and discusses the data obtained,analyses performed and conclu- sions reached in items 1 through 6 above.The capacity addition plan and capacity retirement plan required in item 5 may be pro- vided in the form of a letter with supporting attachments. Presentations: The accompanying report is presented in the form of responses corresponding to the services listed above and include the following topics aS appropriate to each task: Methodology Information services Reference to corresponding tables Model description Conclusion TASK 1: Analyze the service area and existing studies on demographics,econo- mic,and energy use forecasts to estimate loads and peak demands over the next twenty years on at least five year increments. The methodology to develop future loads was to review February 1983 through 1984 (test year)sales statistics for number of customers, customer usage,and customer characteristics.Based on this infor- mation and discussions with the utility manager and the public works director,classes of consumers were determined and future growth rates were developed.These growth rates are reflected in the development of the following tables: PROJECTED NUMBER OF CUSTOMERS: Table 3,projected number of customers computes the projected total number of customers for each rate class,based on several assumptions. The first section identifies the projected annual percent increase of customers in the GS-1 (residential),and GS-2 (small commercial)rate classes.The list of existing consumers was ana- lyzed by the rate consultant and city employees.All identified commercial consumers were recorded in the GS-2 class in Table 3. The large power consumers are defined as customers with more than 7500 KWH use/month.At present there are three consumers that qualify as being in this class--the school,Alascom,and Carls. The projected assumed growth rate is input in the far right column headed "method." The second section of Table 3 converts the annual percent increase into the number of projected additional customers, The third section of Table 3 inputs the assumed number of addi- tional customers in the large power rate class,interruptable power,heat recovery,and streetlights.The large power customer additions are listed in Table 4 (See Task 2). The fourth section of Table 3 calculates the projected total number of customers for each rate class based on the three sec- tions discussed above. PROJECTED KWH SALES: In Table 4,projected KWH sales,average KWH used per month per customer reflected in the first column of the first section was determined from usage data from the test year.The 1988 usage reflects the assumed growth in customer monthly usage as deter- mined through discussion with the utility manager.The inter- vening years are interpolated.Large power and interruptable loads were determined by review of the existing large loads that could be within the City's system.These potential customers were reviewed with City personnel and probable customers determined (See Task 2).The estimated loads of these probable customers were then input into section 2 of this table. The bottom half of this table is the calculated annual KWH sales based on the information in Table 3 and the top of Table 4. System line loss for 1983 was determined from historical data, assumed for 1988 and interpolated for the intervening years.The calculated result is the projected system KWH requirements. The KWH purchased section in this table has values of zero for all years and is included in the table only to provide an example of the capability of the model to incorporate future wholesale power suppliers or cogenerators,if any. SYSTEM DEMAND: The first section of Table 5A lists all the generation units by rated KW.It should be noted that the addition of the 1.4 MW unit and the 2 2.8 MW units were added at the direction of the utility manager and represent planned on contemplated additions.The Alaska firm capacity is computed by the model.This computation is a measure of the generation capacity available to a utility if its largest generation unit should breakdown.This "worst case assumption"has proven to be a useful measure of available capa- city for Alaskan electric utilities because of the isolation in which many generation systems exist.The Alaska firm capacity is computed by summing the capacity of all generation units,then subtracting the largest unit's capacity. The second section contains the computed demands for each rate class.The three categories of demand are computed based on the estimated load factor for each demand category for each respective rate class (see Table 5B),and the projected KWH sales for each rate class as projected on Table 4.The total demand in each of the three categories is added at the bottom of this section. The third section computes the average demand of the system,the system load factor,and the system's Alaska firm capacity in excess of the system's projected coincidental peak demand.When this excess demand approaches zero,the system should consider adding another generation unit.This occurs in 1985.The KW capacity of any wholesale supplier or cogenerator has not been considered in this computation,although provision for a supplier of firm power could be readily added. SYSTEM LOAD FACTORS: Table 5B,System Load Factors,identifies the load factors for each category of demand by rate class. The load factors are input for 1983 and 1988.The load factors for the intervening years are interpolated.The load factors for 1993,1998,and 2003 are the same as for 1988.This method is used for all rate classes.The selection of these input load fac- tors are critical to the accuracy of the complete model.Close attention should be paid to historic and current load factor information.Present data are dependent upon the judgment of the rate designer involved with this study.As the system matures, more reliance can be put upon the available historic data. CONCLUSION: Based on this assumptions and factors as stated above,the system projected peak demands are as shown in Table 5A. TASK 2:3 Analyze the existing service area to determine the economic viability of system expansion to currently unserved consumers and_the willingness of those potential consumers to purchase power from the City including the rates that potential consumers would consider eco- nomic and the amount and timing of potential purchase of electricity from the City. Through discussions with the utility manager and the public works director the following list of potential customers were identified. Based on assumed peaks and load factors as listed,annual KWH require- ments were calculated. Annual Load Projected Annual Customer Load Factor kw KWH Boat Harbor Firm 25%250 438,000 City Dock Firm 25%100 175,000 Airport Firm 50%75 295,650 UNISEA Interrupt 50%950 3,700,000 Process 10%1,500 1,314,000 Standard Oil Interrupt 50%105 413,910 Eastpoint Sea Interrupt 20%100 131,000 Process 10%860 753,360 Pacific Pearl Interrupt 45%100 350,400 Process 10%570 499,320 Panama Marine Interrupt 45%100 350,400 Pan Alaska Interrupt 30%1,750 3,832,500 American Presid.Interrupt 453%120 420,480 Process 10%750 657,000 Sea Alaska Interrupt 50%150 591,300 Process 10%1,750 1,533,000 Strawberry Hill Firm 50%50 197,100 II -1 From discussion with the electric utility manager and the Director of Public Works,four of the above are considered to be potential custo- merss the Boat Harbor,the City Dock,the Airport and the UNISEA System.These potential customers are shown joining the City's.system in 1984 (the first three mentioned)and the UWNISEA System in 1985 (Tables 3 and 4). The willingness of these potential customers to hook-up to the City's system and the rates that they might be willing to pay is dependent on several factors.Typically,a business that must provide its own power needs does not segregate its accounting for the related costs in a manner that will provide a true cost per KWH.In most cases,costs of labor,capital investment,maintenance,etc.,relating to self- generation are combined into other cost centers.In addition,the circumstances of each of these potential customers is,in all likeli- hood,different with respect to condition of equipment,capacity v/s needs,availability and quality of maintenance requirements')and response to emergencies,etc.Therefore,each potential customer's concept of an attractive rate will differ.However,the rates offered should be cost based as is developed in the accompanying tables. There are,however,two incentives that should be considered by these potential customers: e Since certain utility costs are fixed,the costs per KWH decreases as KWH sales increase, e Establishment of an interruptable rate. The interruptable rate is discussed more fully in Task 6.Generally, such a rate recovers fuel cost,customer cost and a small return such as one or two cents per KWH.This type of arrangement should be attractive to the potential customer who has sized his equipment to handle his peak requirements but experiences periods of time that require self-generation at very inefficient load levels.Thus,the City could offer power during the low load level periods at attractive rates provided that these periods coincided with non-peaking periods on the City's system.The City would determine the periods of availa- bility of power under these rates and control the flow of power. II-3 TASK 3:3 Analyze the service area with respect to existing electrical genera- tion systems in order to determine cogeneration potential.Estimate the City's avoided costs (broken down into energy and capacity avoided costs)and provide an estimate of the value of cogenerated power to the City.Analyze the effect of the City's cogeneration policy ordi- nance on the economics of cogenerated power and,if appropriate,make recommendations for revisions to the ordinance. CONSIDERATIONS: The City's electric utility is not a regulated utility. Therefore,the order issued by the Alaska Public Utilities Commission pursuant to federal regulations (PURPA)relative to cogeneration are not requirements that the City needs to comply with.However,there may be advantages to the City of entering into cogeneration or power purchase agreements.There are several potential suppliers of power that will be within the City's distribution system when it is completed (see Task 2--interrup- table loads).In addition,it is our understanding that the City has been approached regarding purchasing power from a potential privately developed hydroelectric facility and a wind generation facility. There are numerous factors to be considered before entering into any agreement to purchase power.Among these are: e Firm power or interruptable e The timing of power availability,i.e.,at which points in the systems daily,monthly and annual load curves. e Can the City avoid the investment of adding more genera- tion capacity? III -l e Is the cogenerated power such that City equipment would be operated at inefficient loads? e Would the power be provided in such a manner that the City could overhaul or maintain their production units on a more frequent basis and thereby prolong their use- ful lives? e Responsibilities for safety requirements on suppliers facilities. e Is the pricing of such power of any advantage to the City and it's consumers? e Are there social or political considerations? e Long-term consideration of non-fossil fuel sources of energy. e Engineering standards. The primary considerations should be the engineering integrity of the system when and if any cogeneration is attached and the purchase power rate should not exceed the cost of power generated by the City's utility.The controlling document in this case should be standards which are to be developed by the Director of Public Works pursuant to ordinance No.82-84.Cogeneration offers made to the City must be considered on a case by case basis and should include the analysis and advice of a qualified electrical engineer. In summary,appropriate cogeneration is a viable source of energy assuming it meets (1)engineering considerations and (2)economic considerations necessary to make it attractive.However,in no III -2 case should it be considered at the expense of he existing con- sumers if alternatives are available. AVOIDED COSTS: On August 20,1982,the Alaska Public Utilities Commission (APUC) in Docket U-81-35 Order No.5 adopted regulations to encourage the development of cogeneration and small power production in Alaska. The regulations,3AAC 50.750--3AAC 50.820 are used for the basis to compute avoided costs below and in the accompanying section relating to the City's Ordinance No.82-84. This section of this report addresses the purchase of non-firm power only.Non-firm power is defined in the regulation as electric power generated by the qualifying facility (OF)that is supplied to the electric utility in unpredictable quantities and at unscheduled times and intervals,and will enable the electric utility to avoid energy related costs.The regulations state the following: e For purchases from a qualifying facility which supplies non-firm power,rates shall be based on the cost of energy which the electric utility avoids by virtue of its interconnection with the qualifying facility. e Unless otherwise modified by the commission,avoided energy costs,expressed in cents per kilowatt-hour, shall be determined from the sum of fuel and variable Operation and maintenance expenses and/or the energy portion of purchased power expense for a 12-month period,approved by the commission,updated by sub- sequent fuel costs,divided by the number of kilowatt- hours sold for the same time period.Expenses)and III -3 kilowatt-hours sold associated with hydroelectric generation shall be specifically excluded from the com- putation of avoided energy costs. e Until such time as the OF's interconnected to a utility's system contribute ten percent of its total energy requirements,the Commission will allow,but not require a utility to set variable 0 &M expenses at Zero.However,when the ten percent energy threshold has been reached,the utility will be required to reassess the extent to which variable O &M expenses are avoided by its purchase of energy from OF's and to recalculate its avoided cost.This approach recognizes that,given the size and operating conditions of Alaskan electric utilities,it is extremely unlikely that OF's will materially affect O &M costs until they contribute at least ten percent of a utility's total energy requirements.Therefore,it attempts to reduce the utilities'computational burden accordingly. According to the direction furnished in the above regulations and tariffs filed with and approved by the APUC relative to the purchase of non-firm power,the calculation of avoided energy costs is accomplished as follows: Current price of fuel x Fuel consumed previous 12 months KWH sold during the previous 12 months Note (1)KWH sold should be decreased for purchased KWH,if any. Note (2)Assumes avoided O &M at OQ. Accordingly,the avoided energy cost for the City of Unalaska Electric Utility as of June30,1984 is: III -4 Fuel consumed during previous 12 months 287,884 gals. Latest fuel price x $.876 Cost of fuel S$252,186 KWH sold during previous 12 months -2,858,222 Avoided energy costs per KWH Ss -0882 ee Considering the substantial changes currently in process relative to the City's distribution and production systems along with the potential of substantially increasing the KWH sales,the avoided energy cost for non-firm power purchases should be expected to change significantly.Production efficiency and line losses will not be the same as indicated from historical statistics. Accordingly,statistics relative to KWH sales,fuel consumption gallonage and average fuel purchase price (for each respective month)should be maintained for each of the preceeding twelve months on a schedule which updates this informaiton monthly.The avoided energy cost can then be recalculated at any time.In addition,there are other uses for this schedule as mentioned further in this study. AVOIDED CAPACITY COSTS: Avoided capacity costs relate to purchases of firm power for base load or peaking purposes.Such purchases are usually based on long-term contracts which provide for demand guarantees and true- ups.Typically,the need or desirability to consider and/or enter into such contracts is based on system planning results in which load growths and capacity reserves are estimated.This planning process is complicated by uncertainty and technological constraints.Load growth may be slower or faster than expected leading to demand that is higher or lower than anticipated. Determination of target reserve capacity is extremely complex due IIt -5 to technological constraints such as fixed unit sizes,lead time requirements,and marketability of off-peak power. In considering the generation planning,three cases are likely: Case 1:The utility has a unit planned or under construction but has the ability to cancel the unit,defer the on-line date,or to alter the size of the unit by either down- sizing the unit or by selling or leasing part of the unit,as a result of the cogenerator's supply. Case 2:The utility has a unit under construction,but the unit cannot be altered or deferred. Case 3:The utility has an adequate supply of generation capacity now and for the foreseeable future. Combinations of these are possible.For example,a utility with one unit virtually completed and ready to go on-line and other units on the planning board would be a combination of Case 1 and Case 2. The results of Table 5A indicate that Case 3 is an accurate description of the City's electric utility.This comment, however,should be qualified for the following reasons: e The 1.4 MW unit is included in Table 5A (lot test unit). The unit has not been installed and costs for transpor- tation,installation,related equipment requirements, and purchase price at the end of the two year test period have not been provided by the City. e Additional capacity on Table 5A is reflected by the 2-2.8 MW units pursuant to instructions from City mana- III -6 gement.These units are apparently available at bargain purchase prices and it is anticipated that grant funds will be utilized to acquire,transport and install them. Accordingly,costs have not been included in the study to reflect depreciation or return. e The 600 KW unit purchased in 1984 and the 300 KW unit rebuilt in 1984 have not been installed but are included in Table 5A as available capacity. e Large power loads as listed in Task 2 may become firm power customers of the utility but have been included only to the extent shown in Task 2. To illustrate the estimated effect of adding all of the estimated loads listed at Task 2,graphs are prevented at appendix 4.It should be noted that significant excess capacity remains even after adding these loads assuming the capacity additions reflected in Table 5A. Typically,avoided capacity costs are computed based on the decreased revenue requirement resulting from avoided investment, carrying costs and operation and maintenance costs,including insurance.The computation is based on the estimated costs of a planned unit or a recently installed unit.Operation and main- tenance materials,are determined based on records maintained for specific units. Therefore,considering the above comments,the City has not pro- vided sufficient information to compute an estimated avoided capa- city cost.Technically,a unit financed entirely by grant funds would result in a zero avoided carrying costs.Only avoided Operation and maintenance costs would be considered in these cir- IIt -7 cumstances.Should the City desire a computation on a hypotheti- cal unit or on the basis of a planned unit not made known or on the 600 KW unit acquired in 1984 and not installed,then the following information or assumptions are required: KW rating Assumed annual operating percent Financing cost rate Return required if more than interest cost Annual operation and maintenance cost Insurance cost Estimated life Capitalized interest,if any Inflation rate The City is currently considering purchasing power from a proposed privately owned hydroelectric project.It does not appear to be economically appropriate to purchase such power as long as the City can provide its own capacity requirements through grant funds or extremely low cost loan funds.However,the availability of such a long-term facility not subject to variations in costs relating to fossil fuels may be desirable should the present plans of the City not materialize as anticipated or alternate uses of grant funds be considered. In this case,several new issues are presented that will require the consulting services of our electrical engineer.These issues include: e The avoided KW costs relating to hydro cogeneration are typically based on the estimated lowest KW available from the cogenerator.Possible variations might occur if the system peak period coincides with the hydro peak III -8 which is possible with the addition of significant fish processing loads. Should wind cogeneration be installed and situated to economically provide for excess power and power fluc- tuations utilization in pumping recycled water for hydro storage,the KW characteristics of the hydro will change. The term of a contract in this situation will probably encompass the life of at least two diesel units. Therefore,inflation factors would need to he estimated for replacement cost purposes. Determination of when a cogenerator begins to accrue or earn a capacity value.This can occur when the coge- nerator unit comes on line,or at a later date, depending on the utility's reliability level or the scheduled on-line date of the next available unit. The timing of payments determination,i.e.,on-line date on avoided planned unit on-line date results'in financing problems for the cogenerator relative to on- line date of the planned unit and discounted payments relative to the cogenerator on-line date. The payment pattern to the cogenerator can be based on either of the following: 1)Payments that reflect the avoided revenue requirement relating to the associated unit. This would result in decreasing payments over time to reflect decreasing interest costs. Iti -9 2)Any other payment pattern provided that the present value of the total payment stream is equal.to the present value of the avoided cost stream over the life of the utility unit. There are several valid arguments for either of the above options. COGENERATION ORDINANCE: The Cogeneration Ordinance should address all of the provisions required by the APUC for cogeneration tariffs since both documents provide rates,rules and regulations to the general public,con- sumers and potential suppliers of power.Primarily,these requirements include: e Avoided energy cost rate stated in cents per KWH (non-firm power). e Notice that avoided cost will change with changes in fuel cost and generation efficiency. e Recovery of interconnection costs,if any. e Rates for sale of power to interconnected facilities including supplementary power,back-up power,main- tenance power,and interruptable power. e Disconnection rights. The above do not include regulations or rules relative to safety requirements since APUC felt that such rules needed to be deve- loped. The ordinance should also address purchases of firm power.This section should state that the purchased power rate shall be based III -10 on the costs of energy and capacity which the electric utility avoids by virtue of its interconnection with the qualifying faci- lity.Each proposed interconnection should be considered on a case by case basis and be subject to a negotiated contract. Attached as appendix 2 to this document is the cogeneration tariff of Kotzebue Electric Association to provide guidance to you for amending your ordinance.This tariff has the most provisions of all the tariffs reviewed.Included in appendix 2 is 3AAC 50.820 DEFINITIONS.These definitions should also be incorporated in the Ordinance for clarity.This can be done by reference,if desired. TII -ll TASK 4:3 Analyze the waste heat recovery potential for sale and consequent reduction of system operating costs. The task does not consider existing heat recovery systems at Unalaska. It appears that in the new generation configuration the existing heating loads will be taken off the waste heat recovery system and replaced by direct fired boilers. 6 Expenditures made to-date in preparation of heat recovery systems at the new generation site are approximately $280,000. Only one current site is ready to accept energy from heat recovery as primary source of heat--City Airport. ANALYSIS OF CURRENT SITE: To connect the Airport to the proposed new generation site would take about one-half mile of thermal insulated transmission piping to the site and an equal amount of return facility.If one used a conservative figure of $50/foot for the installed system one would find the cost to be $132,000.The current fuel consumption at the Airport Site is 23 gallons of fuel per day.Assuming fuel cost of $1 per gallon and no other cost reflected,the total savings would Only amount to $8,400 annually.There appears to be no justifica- tion to include this in a "feasibility study". ANALYSIS OF POTENTIAL SITES: Near Term Under present conditions,and with present generation sizes the only potential use for the in-place heat recovery materials would Iv -1 seem to be within the generation plant itself.From an economics standpointthe heat (BTU)output of the generation is not great enough to allow for the transmission to distant points. It does seem appropriate to use the heat at the generation site and if other uses of the building facilities which house the generators can be developed in a compatible manner,the City could expect to begin to recover some of the funds expended on the deve- lopment of the heat recovery system. Long Term With the system in-place the chances are good that the facilities will be available for use in adjacent camps,processing plants, and housing developments.However,with current generation sizing and loads and the cost of development of the outside facilities necessary to connect services of this type may not fit into the feasibility. There are potential uses for waste heat that can be developed to specifically fit the availability of heat at the site.This could be in the form of greenhouse facilities or some sort of heat pro- cess requiring temperatures in the 180 degree range. SOME NOTES OF CAUTION: The current heat recovery system in the City of Unalaska is an interesting case study.The idea of providing heat to the public buildings and the school fits well into the feasibility in the front end,however,as the system grew,the source and use deve- loped other problems such as noise which made the systems adjacent location unacceptable--one had to go.This situation is common in the history of heat recovery systems. Iv -2 Another problem that seems to follow heat recovery development is that the heat load may grow faster than the demand for the product that produces the "waste heat."Because the heat delivery system is in place it then becomes tempting and in some cases necessary to supplement the "waste heat"with some type of direct fired system.This supplemental supply is much more expensive and the ability to recover these cost becomes a complex problem of setting the proper rate for the BTU's used -one can no longer say that they are "excess"and a fixed fee to cover the installation and operating cost will not do the trick of recovering the true cost. Metering BTU's and spreading variable (fuel)cost in some manner becomes necessary. SUMMARY: A qualitive analysis of the subject .seems to indicate that the existing system should be restricted to on-site use as a source of heat.As the system matures and adjacent heat loads develop the system will be ready to meet the demands.Such loads should be assumed with caution.Considerable long term planning should go into may determination of connecting any heat load.Contractual arrangements should be developed to avoid situations wherein supplemental heat requirements may become an issue. The hard data is not available to produce a quantitative analysis of the issue.At best,a complete feasibility study of further development should be prepared.This would require projections based on growth assumptions which have not been made available at this point. This study has taken into consideration the facts that are available and has made provision for incorporating any future pro- jections that may become available.Until a full blown feasibi- lity study is completed the question of the effect of the "waste heat"facilities on the overall Unalaska Electric Utility will have to be "best guess." At the present the "best guess"is the primary value of the "waste heat facilities"that are or may be put in place will assist only in the dispursement of the engine heat developed in the generation of electricity.The long run value may be that the system was developed with the idea of waste heat in mind. Iv-4 TASK 5: Analyze the existing City electrical system,planned upgrades,coge- neration potential,and waste heat recovery potential and provide a capacity addition plan and a capacity retirement plan.Determine the rate requirements necessary for operation,maintenance and debt retirement. PLANT CONSTRUCTION: The study consultants were provided a tour of the City's electri- cal facilities.The City is currently involved in extensive distribution system additions and the relocation of the power house. The costs for these projects were arrived at by examining expen- ditures to date,and expected additional costs to complete as pro- vided by the utility manager,and assumed to be placed in service as follows: 1984 -Primary line construction $39,052 Secondary line construction 44,523 $83,575 1985 -Substation construction 600,000 Distribution project 1,775,648 2,375,648 1985 -Power house renovation 676,599 Generation placement 90,017 Machinery and equipment 10,614 777,230 1984 -Heat recovery system 334,141 Total known additions S$3,570,594 = PLANT ACCOUNT ASSUMPTIONS: The plant account assumptions are shown in Table 2A.The topmost section of this table identifies the assumed inflation rates used to trend up the previous years Plant balances.The second section identifies the dollars added to plant resulting from these infla- tion factors. The third section identifies large dollar additions to plant due to the known large dollar additions listed above.No distinction or allocation was made between grant funds or borrowed funds (see Task 3 comments relating to generation additions). The fourth section contains the total account balances as of year end.The account balance includes the previous year's balance plus plant additions from both the inflated dollars from section two and the large dollar additions from section three. Streetlights and meter costs were estimated for beginning plant and reclassified from the distribution lines account. PLANT ADDITIONS AND DEPRECIATION EXPENSE: The plant additions and depreciation expense tables track the account balances for each to the plant accounts from year to year. For each category of plant,the following information is accumulated:the ending balance of the current year,total plant additions from Table 2A are added to the beginning account balance,and plant retirements are subtracted from the beginning balances.The plant retirements,if any,are the only amounts input in this part of the schedule.No retirements were assumed. The depreciation expense is computed based on the plant balances, and the designated useful life as input.A half years depre- ciation is taken on both plant additions and retirements. Note that depreciation expenses has been computed on all plant additions regardless of the source of financing.Accordingly,any plant additions financed by grants,if any,have also been included in this computation and in calculating revenue require- ments in Table 6,Operating Expenses and Revenue Requirement.The City may wish to account for depreciation on grant financed faci- lities as a reduction to the computed depreciation expense and thus,remove this cost from revenue requirements. LONG-TERM DEBT: The City's debt to the Alaska Power Authority (APA)related to the plant additions reflected herein is $1,810,486.This debt is repayable over a 20 year term including interest at the rate of 2% per annum commencing on the first day of the calendar year following completion of the project and annual payments thereafter.However,an agreement dated November 30,1983 with APA provides for a repayment schedule that is contingent upon cer- tain occurances in future periods.Therefore a definite debt retirement schedule is not determinable.However,a level payment schedule would require approximately $110,700 in annual payments. Additional financing of $145,231 has been obtained from a bank which is repayable in monthly payments of $3,649 ($43,788 annually)including interest at the rate of 9.5%per annum and maturing in February 1988. One year's interest on these loans is calculated to be $47,947. RATE OF RETURN: The required return has been considered in the computation of forecasted revenue requirements in Table 6 in the following manners e Interest expense has been assumed to be the return com- ponent in the calculation of revenue requirements.This assumption is pursuant to the wishes of the City Council expressed at the presentation of a draft of this study. The draft study has used an 8%of rate base return. e Depreciation expense has been included in the study for all plant additions as stated earlier in this task. Since depreciation is a non-cash expense,its inclusions in the revenue requirements computation provides'the cash resources to fund principal debt retirement. REVENUE REQUIREMENTS AND COST ALLOCATIONS: The operating expenses and rate of return are allocated to classed of consumers using the guidelines suggested by the cost allocation Manual prepared by the National Association of Regulatory Utility Commissioners (NARUC).However,because the City's utility is not regulated by the Alaska Public Utility Commission,there are some discretionary changes that can be made by the City of Unalaska in determining the rates: e The individual operating expenses may be allocated to the individual customer classes on a different basis. e The rate of return may be set at another rate. The cost of service and revenue requirement schedules are biult up from the information in Table l. EXPENSE ASSUMPTIONS: the upper portion of Table 1,Expense Assumptions identified the inflation rates used to trend up the previous years operating expenses on Table 6 operating expense and revenue requirement. The percent increases for the years 1993,1998,and 2003 represent the compounded percent increase over the 5-year period. Note that the test year data in Table 6 reflects expenses for hte fiscal year ended June 30,1984.This information was updated subsequent to the draft presentation. The bad debt expense is computed using the ratio of the previous year's bad debt expense to the previous year's total operating expenses,and thereafter are trended from 1983 data. The fuel costs are computed using the most recent 1984 fuel cost available of .876¢/gal.This is projected to increase at a rate of 3%annually.The fule efficiency was determined to be 10 KWH/gal of fuel in 1983.This as held constant into 1984 and escalated up to 12 KWH/gal in 1988,and held constant after that. The fuel cost and fuel efficiency are used along with projected KWH produced (as computed in Table 4)to compute the projected annual fuel expense (on Table 6).Because this is a large com- ponent of total operating costs these parameters should be closely monitored. | The lower of Table 1 identified any large dollar additions to these operating expense accounts beyond the annual inflation fac- tor.After discussion with the Electric Utility Manager and hte Public Works Director,the model factors in the wages for an addi- tional employee in hte generation facility in 1984,and then an additional employee in 1985,Given the assumed growth in the system,additional employees were projected for 1985 as follows: 1 full time Administrative Employee $35,000 1 part time meter reader $6,000 Both sections of the table are used to project the future operating costs in Table 6.Table 6,Operating Expenses,adjusts the operating expenses during the test year ended June 30,1984, for known changes in operations,as well as for the projected changes per Table l. RETURN ON RATE BASE: The return on rate base is the amount of interest expense as discussed under Task 3.the rate of return computes the return the City realizes on its investment in the electric facility, i.e.,the amount invested in plant as well as the cash needed for 45 days of working capital. The return on rate base is added to the normalized expenses to arrive at the total revenue required by the utility to finance day to day operations.From this required revenue the other electric revenue is backed out to arrive at the revenue required from the sale of energy to customers. The last two lines of Table 6,average costs/KWH and the percent increase/years,are memorandum entries only. SUMMARIZED DATA FOR MENU SCHEDULES: This table is just a summary of the information used in the rate design computations in Tables 8 and 10. PLANT &COST OF SERVICE ALLOCATION TABLES: These two tables allocate the Revenue Requirement to the rate classes as prescribed in the above mentioned NARUC manual.The intent of this allocation process is to assign the costs that were incurred by the utility to that class of consumers that caused the utility to incur the costs.Or as the Alaska Public Utility Commission states the matter "the cost causer must be the cost payer." RATE DESIGN: This table uses the allocated revenue requirement to design the rates for each class.This table uses all the assumptions discussed above,and the usage statistics developed on all other schedules to compute the rates. Two versions of Table 10 are included in the study.The version for fiscal 1983 doesn't include any additional customers to the electric system.It represents what this rate should be,given the test year data and the known changes.The 1984 version shows what the rates should be if the additional customers noted on Tables 3 and 4,are added to the system. The customer charge is a monthly charge levied on all customers. It represents the fixed costs of reading meters,billing custo- mers,etc.that the utility will incur no matter how many addi- tional KWH are sold. The demand charge is a charge for each kilowatt used by large power consumers.Implementing this charge will require this class of customer to have demand meters rather than the current type of meters used.The demand charge is intended to send a price signal to these consumers that will encourage them to even out their demand for electricity on the City's electric system. The large difference in the electric rates between the two years is caused primarily by the three additional large power consumers who would significantly increase the energy usage of the system. The model can be updated to reflect any changes in these critical assumptions. RATE DESIGN ALTERNATIVES: The model provides for the development of rates on any revenue requirement that is developed in Table 6,Operating Expenses for Rate Design.Alternatives to the suggested rate design are numerous and include the arbitrary shifting of costs from one class of consumer to others based on managements decisions.The model provides for this alternative in Table 10,Rate Design although it has not been used in this study and was not suggested at the presentation of the draft report.Alternative rate designs that might be appropriate in this system are as follows: Flat rate with no customers charge Flat rate with no distinction between customers classes A declining block rate structure with a customer charge A declining block rate structure with a minimum charge Block rate structures are typically developed from the results of bill frequency analyses which determine the historical usage pat- terns at various levels.The model provides a target monthly revenue per customer for each class in Table 10.The model will accomodate the insertion of any rate design and calculate the revenues result and compare it to the above mentioned target. In this study,the information and current factors were used to arrive at the rates reflected in Table 10. The magnitude of usage on this system suggests that the customer charge and single energy charge are appropriate.Declining block rates are useful on systems which have high average usage by the residential class.This is not the case on this system and pro- bably will not be the case in the future due to the high cost of energy.The inclusion of a customer charge is appropriate in that it allows recovery of some of the utility's fixed costs regardless of usage. The recognition of rate classes in the rates is a step forward in providing equitable pricing to large users.These classes and the rate design suggested in this study,i.e.,a customer charge and Single energy charge,reflect the preferred methodology of the Alaska Public Utility Commission. CONCLUSIONS -RATE REQUIREMENTS: Present Rates: The City's present retail rates are a flat KWH charge for all KWH's sold to all classes of consumers.While such a rate is easily administered and readily understood by the consumer,this type of rate does not reflect the cost causal relationship on encourage the usage characteristics desired by the utility. Basis for Recommendation: The Alaska Public Utilities Commission in Docket U-83-47 adopted regulations (3AAC 48,500--3AAC 48.560)relative to cost of service methodology and pricing objectives in the design of electric rates.The regulations and guidelines were incorporated in the accompanying study.The regulations relating to this case state: fe)Pricing objectives for pricing electricity are: 1)The cost causer should be the cost pager 2) 3) 4) 5) The revenue requirement or utility financial need objective The equity objective which includes the fair- cost apportionment among customer classes The conservation objective The optional use objective which includes con- Sideration of efficiency The Commission has expressed its'preference of the three part rate as follows: fe)Customer charge °Flat energy charge fo)Demand charge (for customers over 7500 KWH/mo on 20 KW in 3 consecutive months) Recommendation: Based on the results of the accompanying study at Table 10,the rates that should be adopted to recover the revenue requirement for the test year ended June 30,1984 which reflects the sale of 3,698,796 KWH are as follows (rounded): Customer Energy Demand Charge Charge Charge Residential $17 29.2¢/KWH S$0 Small Commercial $25 23.3¢/KWH $s 0 Large Power $34 15.3¢/KWH S15/KW Street Lights s 0 20.0¢/KWH $0 Interruptable S$0 15.3¢/KWH Ss 0 Heat Recovery $457 0 $s 0 Demand Ratchet 75% Vv 10 It should be noted that the KWH statistics furnished by the City indicate that KWH sales increased approximately 27%for the period January through June 1984 over the like period in 1983.Single this represents a substantial change and additional large power customers are now within the systems service area,it is recommend that the revenue requirement and the resulting effect on rates be redetermined at least on an annual basis. The City should also consider implementation of a fuel cost adjustment provision in its'rate ordinance.In a period of declining fuel prices,the utility overrecovers its revenue requirement and the reverse is true in a period of escalating fuel prices.The formula for computing this charge or credit is as follows: [¢/gal base cost]-[¢/gal current cost]=¢/KWH FCRA KWH sold per gallon of fuel based on a moving 12 month average Note:The revenue requirement determined herein is based on a fuel price of 87.6¢/gal (base cost). CAPACITY ADDITION PLAN: The first step in the process of the determination to add genera- tion capacity is to project future demand requirements and compare the result to available (and planned)firm demand capacity. This step is accomplished in the accompanying Table 5A.The results of the computations in Table 5A,given the planned addi- tion of 5.6 MW diesel generation (Currier letter 9/13/84)and load assumptions discussed in Task 1,indicate that additional genera- tion capacity will not be required through the year 2003,even if the test cat unit is removed from the system. yoll The critical point with this schedule is the unknown existing at the time of conducting this study relative to the large potential customers available to the system.Providing full service to any of these potential customers not included in the assumptions at Task 2 could create significant variations in the results at Table 5A.A graphic comparisons is provided at appendix 3 to provide a "worse case scenario."Table 5A should be updated annually so as to incorporate changed conditions and current assumptions. CAPACITY RETIREMENT PLAN: A capacity retirement plan is a new term to the consultants involved in this study.It is anticipated that such a plan involves the monitoring and recording of information relative to each production units efficiency performance,utilization,repair and maintenance performed and the related cost. It is assumed that,except for very large systems,a capacity retirement is an integral part of the capacity addition process. In this process,the statistical information listed above enters into the decision process relative to sizing of capacity additions other considerations may include: fe)Powerhouse space availability fe)Logistics fe)Salvage value,if any,of existing units fe)Physical depreciation v/s accounting depreciation CONCLUSION: In the City of Unalaska's case considering the present and near- term changes taking place in the system,the utility should adopt a format and procedures that will provide for the accumulation of the statistical date mentioned above and for summarizing these stat- istics into monthly reports. TASK 6: Analyze rate structure and load management alternatives based on the existing system,planned upgrades,and capacity addition and retire- ment plans in order to determine options that would levelize daily peak capacity demands and stabilize load factors. RATE STRUCTURE ALTERNATIVE: Rate structure features that could be considered in an effort to levelize daily peak capacity demands and stabilize load factors include the following: e Time of day rates e Demand charge for large power customers e Interruptable rate TIME OF DAY RATES: Time of day rates could be a potential approach to levelizing daily peaks.However,the determination to utilize this type of rate should be based on historical daily load curve statistics. This information is not presently available.In addition,the substantial charges presently occuring with the City systems will, in all probability,have considerable effects on these daily sta- tistics had they been maintained.Therefore,it is recommended that a time of day rate not be considered until the system has Operated through a full years'operating cycle with daily load curve data accumulated. If this is to be considered in the future,metering should be developed now so that daily peak information could be taken on each class of service.This type of equipment will be expensive vI-1l but necessary if one is to prove up the need and correctiness or time of day rates. DEMAND CHARGES: Demand charges,for large power customers are considered to be an efficient and effective means to minimizing peak demands.This is accomplished by the installation of demand meters including a demand charge in the rates. The manner in which a demand charge accomplishes this goal is that a price signal is sent to the customer imposing large demands on the system.This becomes even more evident if an annual ratchet provision is included in the demand rate.The ratchet provision requires that the customer be billed each month for at least a percentage of the highest peak recorded on his meter during the proceeding 12 months (billed demand).Generally,the percentage is 70%to 80%and it is not out of the relm of possibility to impose a 100%ratchet where fixed costs are high,such as in this case. INTERRUPTABLE RATE: To optimize load factor stability,the City needs to encourage use of interruptable loads.There could be large loads as projected in the study at Task 2 or could be relatively (at some point) small loads such as controllable electric heat.However,it is not recommended that experiments into controllable electric heat made until the City's system is operated in a stabilized condition for a full year's operating cycle.Relatively small interruptable loads could also be established by in-line electric heaters on hydrophonic systems.This would require facilities investment by the utility (including a second meter)and dispatch control by VI -2 City personnel.For further information regarding these systems, see appendix 3--Paper prepared for the Alaska Power Authority by Robert Retherford. The rate offered is generally established at an amount per KWH that recovers energy costs,customer costs,and a small return component.Typically,a demand component is not included.Such a rate would have to be attractive when compared to oil or other fuel in the area. The objective of this rate is to encourage customer use of the system to take advantage of existing capacity (and planned capacity)to maximize production efficiency.Control of usage under this rate is accomplished through dispatching by City per- sonnel or by contractual arrangement relating to specific periods of time. Inclusion of this type of rate in the City's ordinance of electric rates is recommended.The recommended KWH charge is included in the conclusion in Task 5. LOAD MANAGEMENT ALTERNATIVES: Load management alternatives relative to mechanical means,produc- tion unit sizing,etc.are subjects that are best addressed by electrical engineers and are not within the expertise of the con- sultants engaged in this study. Load management alternatives relating to cost driven techniques are addressed under the section'entitled "Rate Structure Alternatives." VI -3 4EZwertUNALASKA POWER SYSTEN FEVENUE REQUIREMENT PROJECTIONS TABLE 1 EXPENSE ASSUMPTIONS eis 1984 1985 1986 1987 1986 1989 1993 1998 2003 #ETHOD. EXPENSES-ANNUAL INFLATION RATES ant ADMIN &GENERAL -SALARIES 82 3 3 3 3 3 15.93 15,93 15.93 3 2/PERIOD PRRTS-WAGES ats 3 3 3 3 3 15,33 15.93 15,93 3 Z/PERIOD CUSTOMER ACCOUNTS BAD DEBTS th NA NA NA NA NA NA NA NA NA CUSTOMER ACCOUNTS-METER READING ars 3 3 3 3 3 15.93 15.93 15.93 3 X/PERIOD DISTRIBUTION-WAGES tes 3 3 3 3 3 15.93 45.93 15.93 3 X/PERIOD DISTRIBUTION-TOQLS &MATERIALS at 5 5 5 5 5 27.63 27.63 27.63 5 %/PERIOD ENGINEERING EQUIP-WAGES tae 3 3 3 3 3 15.93 15.93 15.93 3 4/PERIOD ENBINEERING EQUIP-DIESEL FUEL &PARTS ses 3 5 5 5 5 27.63 27.63 27.63 5 %/PERICD GENERAT ION-WAGES 338 3 3 3 3 3 15.93 15.93 15,93 3 £/PERIOO GENERATION-DTHER SUPPLIES 333 5 5 5 5 5 27.63 27.63 27.63 5 %/PERIOO GENERATION-UTILITIES &CONTR.SERV.gat 3 3 3 3 3 15.93 15.93 15.93 3 4/PERIOD GENERATION-AATERIALS see 5 5 5 5 5 27.63 27.63 27.63 5 4/PERIOD GENERATION-LEASED EQUIP. : sit 6 e 6 e 8 0.08 208 0.08 @ S/PERIOD GENERATION-AUTO PARTS,GAS &WAGES ste 4 4 4 4 4 21.67 21.67 21.67 4 3/PERIOD HEAT RECOVERY set 3 3 3 3 3 15.93 15.93 15.93 3 %/PERIOD FUEL COSTS-$/6AL 33 3 3 3 3 3 15.93 15.93 15.93 3 4/PERIOD PURCHASED POMER gst i 1 i i {1.6 1.10 1.16 1 X/PERIOD INSURANCE tes 4 4 4 4 4 21.67 21.67 21.67 4 X/PERIOD SAH HEHE get 1985 1986 1987 1968 1989 1993 1996 2083 EXPENSES-DIRECT DOLLAR ADDITIONS tts ADMIN @ GENERAL-SALARIES ass 6 3,ee e 6 (]0 9 6 PARTS-WAGES sie e e e e e e e @ CUSTOMER ACCOUNTS-BAD DEBTS rae é @ @ Q e 8 e ® CUSTOMER ACCOUNTS-METER READING ase 8 6,088 8 6 e e e 6 DISTRIBUTION-WAGES 333 6 8 ®6 e t )6 0 DISTRIBUTION-TOOLS &MATERIALS ee e 8 8 Q ®e 8 6 ENGINEERING EQUIP-WAGES ant @ e 6 e J 6 8 e ENGINEERING EQUIP-DIESEL FUEL &PARTS ee )6 e @ e @ a 8GENERATION-WAGES ns 30,000 38,008 8 e )e @ e GENERATIONHOTHER SUPPLIES ae Q @ 6 6 a 6 6 e GENERATION-UTILITIES &CONTR.SERV,oe ¢Q q 6 @ e 6 6 GENERATION-MATERIALS gst @ @ Q Q e t)Q 6 GENERATION-LEASED EQUIP,tes 8 Q 8 6 e 6 ()8 GENERATION-AUTO PARTS,GAS &WAGES oie ®t)q Qa a 6 e e HEAT RECOVERY HH qa 10,008 6 e )e é 6 PURCHASED POWER CENTS /KWH bas 0.08 0.08 0.00 0.08 6.08 0.0 0.08 6.08 INSURANCE gs:e @ e e 9 6 ¢6 FUEL COSTS-$/GAL tn 1.28 6.68 6.9 6.93 6.596 0.99 1.14 1,33 1 FUEL EFFICIENCY-KWH PRODUCED/GAL ars 10.8 18.5 11.8 11.5 {2.8 12.6 12.6 12.@ INTERPOLATED 1964-68 UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 2A PLANT ACCOUNT ASSUMPTIONS19641985 1986 «1987 1988 1989 1993 1998 2083 HETHOD. PLANT ACCOUNTS-TRENDEDGENERATION 1 1 i 1 1 1 5.10 5.16 5.18 1 HEAT RECOVERY 2 2 2 2 2 2 10.4 10.41 10.41 2 DISTRIBUTION LINES 1 1 1 1 1 1 5.18 5.10 5.10 !TRANSFORMERS 6 Fs 22 )wD w 6 6 &PERCENT INCREASE IN NON-CO DEMAND PEAKPETERSe3998333444PERCENTINCREASEKWHSALES GENERAL PLANT 4 4 4 4 4 4 21.67 21.67 21.67 4STREETLIGHTS44444421.67 21.67 21.67 4 TRENDED $ADDITIONSGENERATION @ 65,649 5,706 13,535 13,678 13,807 71,138 74,763 «78,576 HEAT REDOVERY e 199 «684,882s,LA 7,264 38,557 «42,578 «47,081 DISTRIBUTION LINES @ 10,713 12,272 58,006 =57,862,721.2,M12-378,AIT =423,432TRANSFORMERS@916924758Te7494,578 5,061 5,672PETERSe20920148146143142129118 GENERAL PLANT @ e ))a @ 8 e eSTREETLIGHTS7)200 208 216 225 234 1,318 1,683 1,951 PLANT ACCOUNT LAAGE DOLLAR ADDITIONSGENERATION )®777,238 e )e e e e HEAT RECOVERY @ 334,141 8 e 7))e e e DISTRIBUTION LINES 8 83,575 2,375,648 6 @ e )e ) GENERAL PLANT )7)@ 7]e @ e )STREETLIGHTS e e )e e 6 e e r) PLANT ACCOUNTS: GENERATION 564,914 564,914 570,563 1,353,499 1,367,034 1,360,704 1,354,511 1,465,645 1,540,408 1,616,984 HEAT RECOVERY 7,98 7,960 2,260 349,085 356,067 363,188 =378,452 409,009 «=451,579 498,579 DISTRIBUTION LINES 586,186 (57,358)528,836 «623,124 3,011,044 3,069,049 3,126,911 3,184,632 3,527,045 3,985,48f 4,328,914TRANSFORMERS38,046 38,046 38,961 «39,885 40,635 41,384 =42,133 46,703 SI,76457,436METERS@52,3598 «=52,358 «52,559 «52,848 «52,997 53,142 53,285 «=53,427 «(53,557 '53,B74 GENERAL PLANT e e e e e 8 a 8 e eSTREETLIGHTSe5,000 5,000 «5,288 «5,408 5,624 =5,BAD 6,083 7,401 9,005 18,956 1,157,@86 1,197,086 1,632,647 4,611,768 4,891,485 4,971,179 5,@51,@97 5,589,238 6,011,793 6,568,543 ACCUMULATED DEPRECIATION 231,793 386,842 491,421 762,507 1,038,207 1,318,536 2,797,459 4,414,068 6,182,188 NET PLANT 965,293 1,323,805 4,320,348 4,126,898 3,932,972 3,732,562 2,711,762 1,597,725 386,355 DEPRECIATION EXPENSE COMPUTATION UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 28 DEPRECIATION EXPENSE COMPUTATION USEFUL LIFE 1 2 3 4 5 1993 1958 2083 GENERATION PLANT B.0.Y.PLANT BALANCE 375,5@9 381,158 1,164,094 1,177,629 1,191,299 1,285,106 1,276,24@ 1,351,083ADDITIONS5,649 782,936 13,535 13,678 13,887 71,138 74,763 «78,576RETIREMENTS8)6 e e e e e E.G.Y.PLANT BALANCE 3B1,158 1,164,094 1,177,629 1,191,299 1,285,106 1,276,248 1,351,683 1,429,579 DEPRECIATION EXPENSE 15 YEARS B.0.Y.BALANCE 25,034 25,411 77,686 «78,589 =79,428 «88,348 BS,883 =,067ADDITIONS188-26,098 451 456 468 2,371 2,492 2,619RETIREMENTS@@eeee6' E.0.Y¥.BALANCE 25,222 51,588 76,057 70,966 79,608 82,712 87,575 92,686 HEAT RECOVERY PLANT B.0.Y.PLANT BALANCE 44,174 378,474 385,319 392,308 =399,422 «486,685 445,242 «©487,812ADDITIONS34,3006,84S 9827,12 7,264 38,557 42,578 «47,08tRETIREMENTSe)®e e e e e £.0.Y.PLANT BALANCE 378,474 385,319 392,388 399,422 «406,685 445,242 «=487,812 ©534,813 DEPRECIATION EXPENSE B.0.¥.BALANCE 1@ YEARS 4,417 37,847 38,532 39,238 =39,942 «0,669 «44,528 48,78ADDITIONS16,715 we M9 356 363 1,928 2,128 2,358RETIREMENTSe])8 e e e e E.0.Y.BALANCE 21,132 38,190 38,881 «39,586 48,385 =42,596 46,653 S131 DISTRIBUTION PLANT B.0.Y.PLANT BALANCE 390,332 404,628 2,872,548 2,938,545 2,908,407 3,046,128 3,388,541 3,766,977ADDITIONS94,288 2,387,920 58,006 57,862 97,721 342,412 «378,437 «423,432RETIREMENTS8ee)9 e 8 e £.0.¥.PLANT BALANCE 484,628 2,872,540 2,938,545 2,988,407 3,046,128 3,308,541 3,765,977 4,198,418 DEPRECIATION EXPENSE B.0.¥.BALANCE 20 YEARS 19,517 24,231 143,627 148,527 149,428)«152,386 169,427 188,349ADDITIONS2,357 59,698 =:458 1,447 1,443 8,568 9,461 1,586RETIREMENTS67]e ))))@ E.0.¥.BALANCE 21,874 3,929 145,077 147,974 158,863 «168,867 «178,888 =,935 TRANSFORMER PLANT B.0.¥.PLANT BALANCE 30,046 =«38,962 39,885 48,635,384 42,133 46,704 51,764ADDITIONS9169247587587494,570 5,061 5,672FETIREPENTS@)@ ))e @ @ E.0.¥.PLANT BALANCE 38,92 39,885 48,635 41,384 42,1335,784 S764 57,436 DEPRECIATION EXPENSE B.0.¥.BALANCE 18 YEARS 3,085 3,69 3,989 4,663 4,138 4,213 4,670 5,176ADDITIONS%rr3 37 2 37 229 253 284RETIREMENTS@)8 8 e e é e E.0.Y.BALANCE 3,858 =3,342 4,181 4,176 4,442 4,923 5,468 UNALASHA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE eC DEPRECIATION EXPENSE COMPUTATION (CONTINUED) USEFUL LIFE METERS B.0.¥.PLANT BALANCE ADDITIONS RETIREMENTS E.0.¥.PLANT BALANCE DEPRECIATION EXPENSE 10 YEARS B.0.Y.BALANCE ADDITIONS RETIREMENTS E.0.Y.BALANCE GENERAL PLANT B.0.¥.PLANT BALANCE ADDITIONS RETIREMENTS E.0.¥.PLANT BALANCE DEPRECIATION EXPENSE B.0.Y.BALANCE 5 YEARS ADDITIONS RETIREMENTS €.0.¥.BALANCE STREET LIGHTS B.0.¥.PLANT BALANCE ADDITIONS RETIREMENTS E.0.¥.PLANT BALANCE DEPRECIATION EXPENSE 8.0.¥.BALANCE 13 YEARS ADDITIONS RETIREMENTS £.0.¥.BALANCE TOTAL PLANT BALANCES B.0.¥.PLANT BALANCE ADDITIONS RETIREMENTS £.0.¥.PLANT BALANCE TOTAL DEPRECIATION EXPENSE B.0.¥.BALANCE ADDITIONS RETIREMENTS TOTAL DEPRECIATION EXPENSE 1 2 3 4 5 1993 1998 2003 46,200 46,409 45,698 46,847 46,992 47,135 47,277 47,4072e9290148146143142129118 )))]r)8 ®7] 46,409 46,698 46,847 46,952 47,135 47,277 47,487 47,524 4,628 =4,GAL 4,678 =4,685 4,699 4,714 4,728 4,7a 18 14 ?7 ?7 6 6 a a @ ]7)e a 6 4,630 4,655 4,677 4,692 4,786 4,721 4,734 4,747 r a ]@ ])]e @ )@ 7]]a )e 8 )]7)7])@ q )Q ])a @ )8 a e ®@ @ e @ e )'6 )@ )8 ) ®@ 8 )@ ®@ r) a e ])@ e @ e 5,000 ©5,288 5,408 5,626 5,049 6,083 7,481 9,005Fe)208 216 225 234 1,318 1,683 1,951 @ @ 8 ])@ )] 5,200 5,408 5,624 5,849 6,083 7,401 9,005 18,956 33 mT 361 375 398 486 493 628 7 7 7 7 8 "53 65 a 6 e )e @ 8 ) He 354 368 3ee 398 49 547 665 899,261 1,334,822 4,513,943 4,593,580 4,673,354 4,753,272 5,211,405 5,713,968 435,561 3,179,121 79,637 79,774 79,918 458,133 582,563 556,7587]@ 8 @ 8 é @ @ 1,334,822 4,513,943 4,593,588 4,673,354 4,753,272 5,211,405 5,713,968 6,278,718 57,726 96,373 268,784 273,389 «278,818 +282,648 +=388,525 337,714 19,323 85,206 =2,383,BIL 2,319 13,139 «14,3945,918 @ )@ @ 8 e @ r) 77,049 182,578 271,086 «275,700 288,329 «295,787 323,328 383,624 UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 3 PROJECTED CUSTOMER NUMBERS 1984 1985 1986 1987 1988 1989 1993 1998 2083 METHOD. @ OF CUSTOMERS-TRENDED {x INCREASE) GS-1 2 2 2 2 2 2 10.41 10.41 10.41 2 t/PERIOD 65-2 2 2 é 2 2 2 10.41 10.41 10.41 2 ¥/PERIOD w N/A N/A N/A WA N/A N/A N/A N/A N/A INTERRUPTABLE wa w/a Nw/A N/A w/a N/A W/A WA N/R HEAT RECOVERY N/A w/a N/A N/A wA WA N/A N/A N/A STREETLIGHTS N/A W/A WA WA W/A WA N/A N/A N/A @ OF CUSTOMERS-NUMBER OF ADDITIONAL CUSTOMERS (FROM %INCREASE) 6-1 W/A 6 6 7 7 7 %a@ 4 68-2 N/A 1 {1 1 1 4 4 4 wb w/a N/A WA W/A N/A N/A Ww/A WA WA INTERRUPTABLE WA N/A WA WA WA WA W/A W/A WA HEAT RECOVERY W/A w/A N/A WA N/A N/A w/A N/A w/A STREETLIGHTS Ww/A w/a WA WA W/A N/A N/A N/A N/A TOTAL N/A 7 7 7 7 7 48 a4 49 NUMBER OF ADDITIONAL CUSTOMERS (LARGE ADDITIONS) 65-1 N/A e 8 6 6 8 6 6 6 65-2 N/R q @ e 8 @ L)6 8 up e 3 )6 @ 6 6 6 6 INTERRUPTABLE 8 6 1 a 8 8 6 6 8 HEAT RECOVERY WA 8 6 @ t)@ @ @ @ STREETLIGHTS N/A @ 8 Q 6 Q @ @ @ TOTAL N/A C]8 8 6 6 e 6 6 TOTAL CUSTOMERS 68-1 314 Ki]326 333 348 aT 383 423 467 65-2 ®av 32 B 4 5 39 43 47 up 3 6 6 6 6 6 6 6 6 INTERRUPTABLE 8 Q 1 1 i 1 1 1 i HEAT RECOVERY i 1 i 1 1 1 1 1 i STREETLIGHTS i 1 i i 1 i |i | TOTAL 349 39 367 35 383 Re)431 415 5e3 UNALASHA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 4 PROJECTED KWH SALES ADDITNL LARGE POWER CONSUMERS (FIRM)KWHBOAT HARBOR ADDITIONAL INTERRUPTABLE LOADS (ANNUAL KUNISEA 19841985 136 =s-1987 1988 1989 1993 1998 2083CONSUMERKWHUSABE/MONTH65-1 472 488 583 519 534 550 558 550 558 INTERPOLATED 1984-8865-2 1,327 1,562 «4,796 2,031 2,265 2,508 2,580 2,508 2,508 INTERPOLATED 1984-88ip16,735 17,388 =18,041 «18,698 §=-19,347 28,088)28,088 «=28,888 =28,888 INTERPOLATED 1984-28 HEAT RECOVERY @ @ e )@ )e )@ INTERPOLATED 1984-88STREETLIGHTS2,500 2,700 2,998 3,100 3,300 3,508 3,500 3,500 3,500 INTERPOLATED 1984-88 36,500 «36,508 36,508 36,500 36,580 36,508 35,588 (36,500 CITY DOCK 14,680 14,688 14,608 14,680 14,608 14,680 14,600 14,688AIRPORT24,638 24,638 «24,638 «24,638 «24,638 =24,638 =24,638 24,638 TOTAL NEW LARGE POWER KWH/MONTH @ 75,738 75,738 75,738 75,738 75,738 75,738 75,738 75,738 3,700,080 3,780,008 3,700,000 3,700,000 3,700,000 3,700,000 3,780,2008 TOTAL INTERRUPTABLE KWH @ @ 3,700,000 3,700,008 3,702,008 3,700,008 3,700,000 3,700,008 3,700,008 KWH SALES 68-1 1,778,496 1,872,384 1,968,518 2,073,125 2,188,352 2,298,280 2,527,808 2,791,800 3,082,28868-2 477,720 582,915 689,741 804,197 924,283 1,058,008 1,178,008 1,298,008 1,418,000LP682,46@ 1,534,818 1,558,326 1,581,834 1,605,342 1,628,050 1,628,658 1,628,805 1,628,B5@INTERRUPT.@ ©3,700,000 3,700,000 3,700,008 3,780,008 3,780,000 3,708,008 3,700,008 HEAT RECOVERY q )7)e )a )e )STREETLIGHTS 30,000 32,408 «=34,608 «937,288 «=39,600 42,000 42,008 42,080 42,088 KWH-TOTAL SALES 2,888,675 4,020,517 7,951,385 8,196,356 6,449,577 8,711,058 9,068,658 9,452,658 9,663,658SYSTEMLOSS(x)71.3%O79 1.620 «7.75 7.87 8.08 8.08 8.00 8.08 INTERPOLATED 1984-88 SYSTEM LOSS (KWH)212,718 325,569 655,716 688,153 722,062 757,483 788,578 821,978 +57,657 KWH REQUIRED BY SYSTEM 3,101,394 4,346,086 8,687,101 8,844,589 9,171,639 9,468,533 9,857,228 10,274,628 10,728,707 KWH PURCHASED PURCHASED POWER @ @ )8 e 7)@ 7]aCO GENERATION @ @ )8 @ 7]))) TOTAL KWH PURCHASED @ 8 @ ]@ @ ))a KWH PRODUCED 3,101,394 4,346,085 8,607,101 6,844,5@9 9,171,639 9,468,533 9,657,228 10,274,628 10,728,787 DEMAND INSTALLED KW (SYSTEM)UNIT 1 UNIT 2 UNIT 3 UNIT 4 CAT TEST UNIT TOTAL INSTALLED CAPACITY LESS:LARGEST UNIT ALASKA FIRM CAPACITY KW 65-1 KW 65-2 KW-LARGE POWER KW INTERPTABLE KW-HEAT RECOVERY KW-STREETLIGHTS KW-SUM UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE SA SYSTEM DEMAND INSTALLED 1977 1981 1976 OVERHAUL °84 JUNE 1984 JUNE 1984 REBUILT Planned Planned COINCIDENT PEAK NON-COINCIDENT PEAK OF CLASS COINCIDENT PEAK NON-COINCIDENT PEAK OF CLASS COINCIDENT PEAK NON-COINCIDENT PEAK OF CLASS COINCIDENT PEAK NON-CDINCIDENT PEAK COINCIDENT PEAK NON-COINCIDENT PEAK COINCIDENT PEAK NON-COINCIDENT PEAK COINCIDENT PEAK NON-COINCIDENT PEAK SYSTEM AVERAGE DEMAND SYSTEM LOAD FACTOR ALASKA FIRM LESS TOTAL COINCIDENT PEAK 1984 1985 1986 1987 1988 1989 1993 1998 2083 688 620 620 bee i)620 688 i)600 600 6ae cee 6ae cae cae bee eee Gee 300 308 300 300 300 320 3ee 300 3ee 620 620 628 620 620 628 620 620 300 300 3ea 300 320 308 308 3aa 1,438 1,438 1,438 1,438 1,438 1,438 1,4382,808 2,500 2,808 2,800 2,8002,800 2,808 2,808 2,600 2,800 1,508 2,408 =-3,858 =3,856 (9,450 9,458 9,458 9,458 9,458 (60a)(628)(1,438)4,438)-(2,808)(2,888)=(2,888)=(2,888)«=(2,88) oe 1,888)2,428 2,428,658 6,658 6,650 6,658 6,658 677 668 661 657 655 654 724 797 888 1,015 972 936 918 889 a7i %2 1,062 1,173 156 179 2e2 224 245 266 297 7 358 218 237 254 278 285 )34 368 492 172 at?494 393 382 372 372 372 372 229 5Aa 523 5a2 age 465 465 465 465 @ e 422 4ze Per)422 422 422 422 @ e 422 422 4z2 422 422 422 422 e ®8 ']e )6 6 8 a e a 8 7]))e 8 7 7 8 8 9 18 10 16 18 8 8 a 9 9 18 10 10 18 1,011 1,272 1,697 1,785 1,714 1,724 1,822 1,928 2,041 1,478 1,764 =214428132,088 2,068 2,193 2,327 2,472 30 459 988 936 %65 994 1835 1079 1126 A S|ae 57.7%56.8%56.0%55.2x at 528 723 15 4,936 4,926 4,828 4,722 4,609 SYSTEM LOAD FACTOR 6-1 65-2 INTERRUPTABLE HEAT RECOVERY STREETLIGHTS UNALASKA POWER SYSTER REVENUE REQUIREMENT PROJECTIONS TABLE SB SYSTEM LOAD FACTORS COINCIDENT PEAK NON-COINCIDENT PEAK COINCIDENT PEAK WON-COINCIDENT PEAK COINCIDENT PEAK NON-COINCIDENT PEAK COINCIDENT PEAK NON-COINCIDENT PEAK COINCIDENT PEAK NON-COINCIDENT PEAK COINCIDENT PEAK NON-COINCIDENT PEAK 4@ INTERPOLATED 1984-88 3@ INTERPOLATED 1964-68 45 INTERPOLATED 1984-68 4@ INTERPOLATED 1984-88 5®INTERPOLATED 1584-88 40 INTERPOLATED 1964-68 108 INTERPOLATED 1984-88 108 INTERPOLATED 1984-88 1,008,008 INTERPOLATED 1984-68 1,80,08@ INTERPOLATED 1984-88 S@ INTERPOLATED 1984-88 1984 1985 1986 1987 1998 1989 1993 1998 2083 38 32 Rr)6 38 4a se 49Fs2224262838303 35 37 k)a 83 45 45 452528i437404048 rr 4a 4 46 48 58 58 5030234%3B rr rv rv) 100 108 108 108 108 108 100 108108108180108108100108100 1,000,008 1,000,000 1,000,000 1,008,008 1,000,000 1,000,000 1,000,000 1,000,0001,000,000 1,000,000 1,008,000 1,000,000 1,000,080 1,080,000 1,000,008 1,000,000 50 50 58 50 58 )50 se 45 46 47 48 49 58 58 58 5@ INTERPOLATED 1984-88 PER AUDIT 1963-4 COST OF SERVICE: ADMIN &GENERAL-SALARTES 245,825PARTS-waGeS 31,713 CUSTOMER ACCOUNTS-BAD DEBTS 24,268 CUSTOMER ACCOUNTS-HETER READING 3,007DISTREBUTION-WOGES 10,585 DISTRIBUTION-TOOLS &MATERIALS 7,019 ENGINEERING EQUIP-WAGES 18,255 ENS.EQUIP-DIESEL FUEL &PARTS 8,858BENERATION-WAGES 62,294 GENERATION-OTHER SUPPLIES 16,B23 BENERATION4ITILITIES &CONTR.SERV,34,82GENERATION-MATERIALS 28,585SENERATION-AUTO PARTS,BAS &WAGES 14,768 HEAT RECOVERY ) FUEL COSTS 318,348 PURCHASED POMER aDEPRECIATIO:EXPENSE 70,662 a ' ) @ )INSURANCE ) TOTAL COST OF SERVICE 879,13% RATE BASE COMPUTATION WORKING CAPITAL COMPONENT: NORMALIZED OPERATING EXP, LESS:DEPRECIATION TIMES 45/365 TOTAL W/C REQUIREMENTS NET UTILITY PLANT RATE BASERATEOFRETURN RETURN ON RATE BASE NORMALIZED EXPENSES REVENUE REQUIRED LESS OTHER REVENUE REVENUE REQUIRED FROM ENERGY SALES AVERAGE CENTS/KWH %INCREASE (DECREASE)/YEAR UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 6 OPERATING REVENUE NORMAL IZED ADJUSTMENT REFERENCE TEST YEAR1984 1985 1986 1987 1988 1989 1993 1998 2203 245,025 252,376 294,947 303,795 «312,989 «322,297 373,638 «=433,140 =582,128M,713 32,664 =33,644 34,654 =35,693 36,764 =42,628 «=49,488 =«57,27724,268 «24,748 =25,688 =26,1336,S916,994 «7,347 27,658 27,9183,007 3,97 (9,198,465 (9,758 10,042 =11,642 13,496 15,64610,585 18,983 11,238 11,5671,914 12,271 14,225 16,491 19,118 7,019 7,378 7,738 «=81258,532 8,958 =11,433 14,592 18,623 18,255 18,883 19,367 19,948 =28,545 1,163 24,583 2B,4 32,9716,89 8 ©=9,335 «9,BB S1,291 18,886 11,346 14,481 18,482 23,588 62,294 94,163 126,988 138,797 134,721 «138,763 «168,864 =-186,486 «216,188 16,823 17,664 18,547 19,475 20,448 21,471 27,403 «34,974 44,636 34,902 «35,949 37,028 «38,138 =«39,283 =48,461 46,95 54,376 63,037 20,585 21,614 22,695 23,838 «=25,821 «=6,272 «33,531 =«42,795 Ss 54,G18 14,768 15,359 15,973 16,612 =-«17,276 =«17,968 =21,868 =26,59 =«32,359 e @ 10,008 10,308 =10,689 «10,927 12,668 14,685 17,024 (58,154)252,186 380,717 739,621 758,619 763,422 «777,955 «938,886 «1,134,514 1,372,314 8 )°)@ 7)@ e )@78,662 77,049 182,578 271,086 275,708 +©288,329 «295,787 «323,328 ©«383,624 e )@ 7]@ r)8 )6 @ 8 e é e @ )@ e )))6 e )7]'er)e ))e ))e e')a ]@ e a )e e e )a @ @ e @ @ a 820,982 1,001,603 1,564,947 1,684,836 1,723,221 1,763,988 2,057,815 2,419,449 2,851,068 820,982 1,001,803 1,564,947 1,684,036 1,723,221 1,763,988 2,057,815 2,419,449 2,851,068 (70,662)(77,049)(182,578)(271,086)(275,780)(288,329)(295,787)(323,328)(383,624) 92,5@5 114,011 178,429 174,298 178,462 182,916 «217,236 «258,427 «=«387,9084 92,505 114,011 170,429 174,298 178,462 «182,916 «217,236 +=258,427 387,984565,293 1,323,805 4,328,348 4,128,898 3,932,972 3,732,562 2,711,762 1,597,725 386,355 1,057,798 1,437,616 4,490,777 4,303,196 4,111,436 3,915,478 2,928,958 1,856,152 694,259Rake1.0%1.6%1.0%0.5%1.2%2.0%5.2% 36,218 47,9457 45,734 42,638 «39,264 36,218 36,218)36,210 =36,218828,982 1,001,003 1,564,947 1,684,836 1,723,221 1,763,98@ 2,057,815 2,419,449 2,651,@68 857,192 1,049,758 1,610,641 1,727,466 1,762,465 1,800,199 2,094,025 2,455,659 2,887,278 (20,231)(13,131)13,131)(13,131)13,031)043,831)331),13EP 3,13) 836,961 1,036,619 1,597,550 1,714,335 1,749,334 1,787,859 2,080,894 2,442,528 2,874,147 28.97 25.78 =20.09 292 8,70 28.51 22.95 25.84 29.14HILL=--22.1%IK HO 0.5%11.9%12.6%12.8% UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 7 SUMMARIZED DATA FOR MENU SCHEDULES PLANT ACCOUNTS: COST OF SERVICE: GENERATION 564,914 HEAT RECOVERY 7,948 DISTRIBUTION LINES 528,636TRANSFORMERS38,046PETERS52,358 GENERAL PLANT eSTREETLIGHTS5,000 GROSS PLANT 1,197,086 SEZErc 22258 1984 ADMIN &GENERAL-SALARIES 245,025PARTS-WOLES 31,713 CUSTOMER ACCOUNTS-BAD DEBTS 24,268CUSTOMERACCOUNTS-METER READING 3,007DISTRIBUTION-WAGES 10,585 DISTRIBUTION-TOOLS &MATERIALS 7,019 ENGINEERING EQUIPHNAGES 18,255 ENG.EQUIP-DIESEL FUEL &PARTS 8,890BENERATION-WAGES 62,2% BENERATION-OTHER SUPPLIES 16,823 GENERATION-UTILITIES &CONTR.SER 34,982GENERATION-MATERIALS 28,585GENERATION-AUTO PARTS,GAS &WEES 14,768 HEAT RECOVERY a FUEL COSTS 252,106 PURCHASED POWER eDEPRECTATION:GENERAT ION 70,662 HEAT RECOVERY ) DISTRIBUTION LINES )TRANSFORMERS /METERS 0 GENERAL PLANT eSTREETLIGHTSeINSURANCE' KW 65-1 COINCIDENT PEAK NON-COINCIDENT PEAK KW GS-2 COINCIDENT PEAK NON-COINCIDENT PEAK KW LP COINCIDENT PEAK NON-COINCIDENT PEAK KW-INTERPT.COINCIDENT PEAK NON-COINCIDENT PEAK HEAT RECOVER COINCIDENT PEAK NON-COINCIDENT PEAK STREETLIGHTS COINCIDENT PEAK NON-COINCIDENT PEAK a OF Ku CUSTOMERS SALES68-1 314 1,778,49665-2 3 «ATT,Terv)3 682,458INTERRUPT.e e HEAT REC.1 7]STREETLIGHTS 1-32,008 RETURN ON RATE BASE 3,210 UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS FOR THE FISCAL YEA 1964 TABLE &PLANT ALLOCATION ELECTRIC UTILITY PLANT ALLOCATION TO FUNCTION-RATE CLASS {ALLOCATION PERCENT )(ALLOCATED PLANT } UN §)OF KH KW KW DIRECT Wg KH kw Kw DIRECT =-«-TOTALCONSUMERSCOINCID. WON-COIN CONSUMER COINCID.--NON-COIN PLANT ACCOUNTS:BENERATION 564,914 ex ox 1eex et ex e @ 564,914 e @ 564,984 HEAT RECOVERY 7,948 a a at ex 100%@ )@ e 7,948 7,940 DISTRIBUTION LINES 528,436 Set ox "x Ser ex 264,418 e ©264,418 @ 528,836TRANSFORMERS36,46 sen ex x Sen ex 19,023 e e 19,023 ©=-38,46METERS52,358 198%x "ex ex 52,358 8 a e @ =52,350GENERALPLANTaSenexSerex"x )e e )e 8 OTHER EQUIPMENT 5,008 et ex et ex 100%e )e e 5,008 5,000 GROSS PLANT 1,197,086 335,791 @ =5HA,914 283,441 12,94@ 1,197,886 or HoH Ku kW DIRECT PLANT +o KWH KW KW DIRECTCONSUMERSCOINCID. NON-COIN Tote.CONSUMERS COINCID.-NON-COIN PLANT MENU ALLOCATION: 6S-1 314 1,778,496 677 1,015 @ 875,849 Be,116 e 376,016 195,717 e t 98.62 61.6%66.9%69.1%ae =73.2% 65-2 E)477,728 156 218 @ 157,955 28,865 @ =87,033 42,57 ) x 8.6%16.5%15.4%14,8x oe |13.2% LARBE POWER 3 682,468 172 229 @ 143,124 2,886 @ =%,039 44,199 e x an 20.9%17.x 15.6%@.e%=12.0% INTERRUPTABLE 7 e 7]7))e @ @ e a e t 8.0%0.0%0.8%@.ex i HEAT RECOVERY 1 e )@ @ =13,982 962 @ e 6 =:12,948 t a 9.0%0.0%0.0%ae Let STREETLIGHTS !30,008 7 8 6 6,255 962 8 3,826 1,467 @ x 0.3%1.e%a7 Ost «100.0%. TOTAL 39 2,BBB,676 1,011 1,478 @ 1,197,836 335,791 @ 564,914 283,441 12,948 '100.0%100.Ox 100.0%108.0%=108.8X10.0% UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 9 COST OF SERVICE ALLOCATION FOR THE YEAR 1984 {ALLOCATION PERCENT } ao Ki KW KW DIRECT PLANT EXPENSE CONSUMERS COINCID.©NON-COIN COST OF SERVICE: ADMIN G GENERAL-SA 245,025 Set o Set o ex es PARTS-WAGES 31,713 Set a Set a er ex CUSTOMER ACCOUNTS-24,268 ex 100%ex 6 e%ex CUSTOMER ACCOUNTS-3,087 10at on *ex ex DISTAIBUTION-WAGES 18,585 3 100%ex e 6 es DISTRIBUTION-TOOLS 7,019 "10ex ex %*ex ENGINEERING EQUIP-18,255 ex ex 100%ex ex 6x ENG.EQUIP-DIESEL 8,898 ox ex 10%"x et ax GENERATION-WAGES 62,294 *x 100%ex ex 3 GENERATION-OTHER S 16,823 x a 100%e et GENERATION-UTILITI 34,982 %100%on ex ex GENERATION-MATERIA 28,585 "x 100%e " GENERATION-AUTO PA 14,768 et "Leek ee ex ox HEAT RECOVERY e ""et ex 100%ex FUEL COSTS 252,186 x 100%ex ex et x PURCHASED POWER r)et 10%ox ex et ot DEPR:GENERATION 70,662 "et x ex x 100% HEAT RECOVERY @ ex er a o ex 190% DISTRIBUTION 6 ex ex ex a x 10e% TRANSFOAMERS/e (x e x a ex 100% GENERAL PLANT a ex et ex ex x 100% OTHER EQUIPHE @ x et e ex e%100% INSURANCE e e%a a %ox 108% TOTAL OPERATING EX 828,982 RETURN ON RATE BAS 36,210 a ti ox et ex 108% FEVENE REQUIREMEN ©BST,$52 peseeeemeenees CITY OF UNALASHA ELECTRIC UTILITY REVENUE REQUIREMENT ALLOCATED TO RATE CLASSES ALLOCATION MENU: +O KWH Kid KW DIRECT --PLANTCONSUMERSCOINCIDENTNON-COINCID. 65-1 341,778,456 677 1,015 @ 875,849 1 90.ot 61.6%66.9%69,1%@ex =73.2% 68-2 30 477,728 156 218 @ 157,955 x 8.6%16.5%15.4%14.8%Bex =13.2% LARGE POMER 3 602,468 172 229 @ 143,124 x 0.3%20.9%17.0%15.6%0.x =12.8% INTERRUPT.)7]@ e @ @ 1 0.6%6.0%0.0%0.e%0.0%0.0% HEAT RECOVERY i @ ))@ 13,982ri0.3%eer 8.0x 0.0%0.0%1.2% STREETLIGHTS 1 30,000 7 8 ®6,255 x 0.3%1.0%6.7%0.5%100.0%0.5% -TOTAL 349 «2,888,676 1,011 1,478 @ 1,197,086 ALLOCATED EXPENSES: CIN $)OF KWH Kw KW DIRECT PLANT TOTALCONSUMERSCOINCID.-NON-COIN 122,513 @ =122,513 r))@ =245,02515,657 e 15,857 r)e 9 31,713@=24,268 e @ ®@ =.24,2683,007 @ e e )e 3,007@=18,585 )@ e '16,585©=7,019 @ @ e r)7,019 )@ 18,255 e e e 18,255 e )8,898 a r]]8,698r)6 =«62,294 7]a @ «62,254 e Q 16,823 )@ @ 16,823 e @ 34,82 8 @ @ «4,982 e @ 28,585 e @ @ =-28,585 e @ 14,768 6 )8 14,7687])@ 8 @ @ 7 @ =252,186 ))@ @ 252,186 @ )r]@ @ ]e e a @ e @ 70,662 78,662 e a @ )7])a 8 )8 6 7]e ) 7)Q )@ 8 )7] @ ]@ a a ®a @ @ 8 )e )) 6 ])))')6 @ )7)r)6 36,210 36,218 141,376 294,058 314,B86 @ @ 106,872 857,192 REVENUE REQUIREMENT ($)ALLOCATED TO RATE CLASSES +OF KW KW KW DIRECT PLANT TOTAL CONSUMERS COINCIDENT NON-COINCID. 127,198 181,045 218,788 a @ =78,193 597,144 12,153 48,638 48,513 a )14,182 123,397 1,215 61,329 53,533 ))12,778 128,854 )8 ))a 8 a 405 7))@ 7)1,241 1,646 485 3,854 2,133 a a 558 6,158 141,376 294,058 314,B86 @ @ 106,872 857,192 UNALASKA POWER SYSTEM REVENUE REQUIREMENT PROJECTIONS TABLE 1@ COST STATISTICS BY RATE CLASS FOR THE FISCAL YEAR 1984 (--- -------------RATE CLASSES:} HEAT6S-1 6S-2 LARGE POWERINTERUPT.RECOVERY ST.LTS.TOTAL BASE DATA: #OF CONSUMERS 314 3e 3 )1 1 349 KWH SOLD 1,778,496 477,728 682,468 @ ®38,000 «2,088,676KWHAVE/CONSUMER/MONTH 472 «1,327 16,735 ERR @ 2,508 6% KW COINCIDENTAL 677 156 172 a )7 1,011 KW NON-COINCIDENTAL 1,015 218 229 ))8 1,478 %OF CUST.CHARGE IN DESIGNED RATE 50x Tt 108%100%x ex %OF CO-PEAK IN DESIGNED RATE ex ox 5@%25x 25%ox DEMAND RATCHET ex ex Tt REVENUE REQUIRED 597,144 123,397 128,054 @ 1,646 6,158 57,192 LESS:OTHER REVENUE (14,093)(2,912)(3,041)@ 139)(145)(28,231) NET REVENUE REQUIRED 583,@51 128,485 125,813 )1,687 6,085 36,961 CUSTOMER COSTS 127,198 12,153 1,215 )405 485 141,376 FIXED COSTS 274,888 59,782 «63,269 a 1,282 2,545 481,527 ENERGY COSTS 181,045 48,638 61,329 @ 8 3,054 234,658 CUSTOMER $/CONSUMER/MONTH 33.76 0633.76 «=«33.76 ERR «33.76 33.76 FIXED $/CONSUMER/MONTH 72.93 165.84 1,757.48 ERR 100.19 212.16 FIXED $/KW:CO-PEAK/MONTH 33.04 0-31.93 (38.67 ERR ERR 3.97 FIXED $/KW:NON CO-PEAK/MONTH 22.56 22.23.00 ERR ERR 27.88 ENERGY CENTS/KHH 10.18 10.18 10.18 ERR ERA 18.18 10.18 AVERAGE CENTS/KWH-GROSS 32.78 ©25.22 BB ERR ERR 20.02 28.97 TARGET REVENUE (NO TILT)$/CONSUMER/MONTH $154.74 $336.68 $3,494.00 ERR $133.95 $500.48 AVERAGE CENTS/KWH 32.78 25.22 20.88 ERR ERR 20.02 RATE DESIGN (NG TILT) CUSTOMER CHARGE $16.88 $25.32 $33.76 $8.00 $8.08 $0.00 DEMAND CHARGE $0.08 ©$0.08 =$15.33 $0.08 ERR $0.08 ENERGY CHARGE IN CENTS/KWH 29.21 23.31 15.28 15.28 ERR 28.02 SHIHHINHHIHHIHHHIE IH HAE a dE HOE 08 0 0b Pb a 9h a a a a 0 HH EE TILT INS 8 @ @ a @ ')) TILTED REVENUE REQUIREMENT 563,051 128,485 125,813 @ 1,687 6,005 836,96! HHH HHI HE HHH IIE A a a A 0 A A HH Ht TARGET REVENUE (TILTED) $/CONSUMER/MONTH $154.74 $334.68 $3,494,88 ERR =$133.95 $500.48 AVERAGE CENTS/KWH 32.78 25.22 20.88 ERR ERR 28.82 RATE DESIGN (TILTED) CUSTOMER CHARGE $16.88 =$25.32 $33.76 ERR $9.8 $8.08 DEMAND CHARGE $9.08 $8.08 $15.33 ERR ERR $8,00 ENERGY CHARGE IN CENTS/KWH 29.21 23.31 15.28 ERR ERR 20.02 usandTha(Demand(inMegawatts)Electric fwith 3 large power cans Utility System umars addedJ Demand ?7 | ;+++ /i oe i no ;f! '/! =e 4 fi 5 }te.!;ee a -- -_-- Ud T --S T T T 1 T oy es s =."a ms fea <7 0 on oe ie1oSe4+1o85 Ions 1987 |os8e 13a2 13835 Paos Firm o System Demand Demand(inMegawatts)(Thousands)Electric Utility System Demand (with 11 large power consumers added)7 6 -/t//.+i hee nil5fofiffyi/f47/fi; =H /34 i{/+--_-_-_-_-++} cat a /anq /ae ;: a |1 abo "a ; " aO-+<-T T 7 T T T T 1984 1985 1986 1987 1953 19as 1993 1396 2003 Year ;AK Firm >System Demand BN Excess Capacity Demand(inMegawatts)(Thousands)Electric Utility System Demand (with 11 large power consumers added)6 ..6 -> 5 4 /Y . 4+//34 / 1 +/+1 1 |24 <Aa-*i ae ae aS if \ -i 4 \ >\\rn j 3 4 -a - 4 -4 T T T T T T T 1984 1985 1986 1987 1938 1989 1993 1998 2003 Year (without either EMB unit)AK Fiem System Demand A Excess Capacity Demand(inMegawatts)(Thausands)+tN0 T T T T T 1964 1985 1986 1987 1984 1989 19953 1998 ZO003 Electric Utility System Demand (without Z EMO units or other loads) eee >a 5 F >a"aTC -a >a *=ee a s-"4 T Year AK Firm >System Demand A Excess Capacity Introduction of Unalaska Town -History Population Commerce Present energy use (narrative) Geothermal Prospect What Geothermal Energy is Unalaska Geology Interview Tom Miller (USGS) Studies Completed Drilling Results Model of Resource Economics Acres Study Republic Costs Rate Study 788/104 Electrical upgrading of system ?7y.07.Ff-_ Areal shot of city (file footage) Individual shots of industry,people andtown(file footage) Footage of earth model.Footage of island are formation (file footage). Geological map (new footage).UnalaskaIsland(new footage). Interview (new footage). Map showing areas of work.Distance to town (new footage)(geologist interview). Rig and steam (filefootage).Existing interview (file footage). Graphic reproduction(new footage). Animation of powerproduction(filefootage). Scene of town (file footage).Graphicscomparison(new footage). Graphics (newfootage). UNALASKA FACT SHEET - PROJECT VIDEO Target Audience Primary -Design Engineering Staff of Feasibility Secondary - Other - Film Script Outline Script Introduction Aleut Legend of Makuskin(narration) Project Introduction -History of project -Objective of film -Project Director (short) (narration) 788/104 Study.Purpose is to provide film cover-age of site,resource characteristics, town,load,transmission routes and land status.This will allow staff to come up to speed very quickly and to design without going to field until checking finished work.Estimate 5-10%savings on cost of study as a result of video. Private Investment Groups.The general direction of the Alaska Power Authority is to include private investment into the Unalaska Geothermal Project.The video is a quick,professional orientation tool. The 20 minute film is worth several hours of briefings by Power Authority staff. The use of the video will allow the potential investors to gain a coherent understanding of the project and concen- trate their time on the financial aspects of the project. Educational T.V. Orient Board of Power Authority Document Project Update governmental agencies Orient licensing agencies Report to Legislature and Governor Scene Submit view of Makuskin (file footage) View of stream well from distance (file footage) Feasibility Study Interview Patty DeJong Status Interview Geologist on Transmission Lines; Describe geology and hazards. Summary Project Status and Future Plans Map to area (new Land footage). Film Footage of line corridors. Appropriate slide and scenery. The entire film will be 15-20 minutes long and cost between $15-20,000 dollars.The film may well be as important to eventual development as the feasibility study itself. 788/104