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HomeMy WebLinkAbout09222014 City Council Work Session Notes - Electric Rate Study WORK SESSION NOTES ON I fr -tviC, 44,(Stiefttl Purpose: rt OW) d YaFi e le do role, shicel Present: I-6 4 n f b +JJ ,�.ouncil Members Present: a Y eti I eI Iv‘o i u j rr.S a GGtr a day Da lin Called by: Time 5'3& 49 Date a' Z 1 r 1--614 ****************************************************** John -FrericiA_, r • NvoPi, oy , ." "` , piitt, mbavel ria tiafibityitgailCO. T. x 1u3S LN,A,,...,43 cI 2-/s,s\\`-k 9/19/2014 SES Cost of Service/ Rate Study September 22, 2014 the Financial Engineering Company Today's Agenda • Terms • Cost of Service Analyses — Why — How • Current Rate Structure • Recent Rate History • Analysis and Findings • Recommendations 1 9/19/2014 ' Terms • Energy — The amount of electric consumption over a given period — One 100-watt light bulb on for 24 hours=2,400 watt-hours, or 2.4 kilowatt hours(kWh) — 1,000 kWh =1 MWh • Demand (Peak) — Maximum rate of electric consumption during a period — Typically measured over a 15-minute period,sometimes instantaneous — One 100-watt light bulb on for 24 hours+one 100-watt bulb on for one hour — Peak demand=200 watts — 1,000 kW= 1MW Terms • System Peak (Demand) — The peak demand of the system as a whole during the billing cycle — SES system demand (2013): 8.5—10.4 MW — Note: CEA bill based on both monthly energy used and monthly system demand • Coincident Peak — The demand of a rate class at the time of the system peak — Must be estimated • Non-Coincident Peak — The peak demand of a rate class — Non-Coincident Peak>=Coincident Peak 2 9/19/2014 Terms • Income Basis — Revenue requirements based on using the traditional accounting methodology — Depreciation (non-cash) is included in expenses — Principal on debt is not included • Cash Basis — Revenue requirements based on projected cash flows — Depreciation is not included — Principal on debt is included Purpose of Cost of Service Analysis • Ensure utility recovering sufficient revenues • Allocate utility costs to each rate class in a fair and equitable manner • Goal is for "cost causer" to be "cost payer" • Industry standards established for allocation of costs • Not an exact science • Rate regulated utilities must perform these studies 3 9/19/2014 Process • In very general terms, the revenue require- ments of a utility are allocated to each customer class as follows Cost Component Allocation Basis Fixed Generation Coincident Peak Variable Generation Energy Non-Coincident Peak/ Distribution Number of Customers Meter Reading,Customer Number and type of Service customers Administrative All of the above Current Rate Structure CEA Bill SES System Costs SES Bill Customer Charge Customer Charge Demand Charge Energy Charge Energy Charge Non Fuel Bradley Lake Credit Costs CrDemand Charge AVTEC Credit (LGS and Special Contract Only) I _ Fuel and Purchased Power Cost Generator Fuel Fuel Cost Adjustment Adjustment 4 9/19/2014 Recent History • Last cost-of-service study performed in 1993 • Rates now adjusted as follows: — Base Rates • Annually based on CPI • As required for changes in CEA Base Rates — Fuel Cost Adjustment • Monthly based on CEA Fuel/Purchased Power Cost Adjustment bill in previous month Current Rates Residential Sm Gen Svc Lg Gen Svc Special Street Contract Lights Customer(S/month) 19.60 39.20 39.20 39.20 Energy( Wb) 1st Block 0.12036 0.13890 0.09939 0.16391 2nd Block 0.05968 Demand(S/kW-month) 20.79 Fuel Cost Adjustment(May) 0.05971 0.05971 0.05971 0.05971 0.05971 5 9/19/2014 Analysis and Findings • Assumptions — Based on 2013 billing determinants (number of customers, energy and demand sales) — Revenue requirements based on FY 2015 Budget with following adjustments: • Increase purchased power costs to reflect CEA's latest rate adjustment • CEA Fuel/Purchased Power costs excluded (recovered through Fuel Cost Adjustment and not base rates) • Included PILT,System Permit,and State Lobbying expenses • Excluded capital outlays • Note: Capital outlay recovery is made over time through depreciation which is already included in the budget • Included target margin of$300,000 3015 Adlusn.enes Re Dadra Sly G....a... 155,751 155,151 Substanm 323.701 323701 Trmsm.astoe Ops 71361 72.261 Dnmbmet DCM Leber 0A15I 63,610 63,610 Caput Ouda5 165,096 (165,960) psmLwoe 0G5.1 521610 (463,000) 63,610 Wholesale Poser Cons Purchased PowerCFA 1,773.00a 1,192,411 Purchased Power•Fuel 3,066,000 (3,066,000) Income Basis Total 4,841,000 (3,046.519) 1,793411 Wort Orden (15183) 45,583 Standby 90.434 90434 Meter Seesxes 95366 91.566 General Labor O&M 1,793,671 1$3,670 Depectanoo 1,774,036 1,774.028 Gen Gosx Main Fee 166536 160}58 PELT 915,291 915,391 Reda..PELT to T Fs (915391) 915,291 Motor Pool Rea-Cap Oaths 90,000 90,000 decent Svnea Potash Fee - 303000 300.000 Fed State Loans, - 40,519 40319 CgaW Outlet 100,000 (100,096) - CapalEqlopmeru 34.000 (330001 Tout 4,1561.56 3123,610 5,261.986 Admin Enameema_ Labor 06:501 648,416 640416 Depeeaeoo 3.210 3,210 Motor Pool Rea•Cap Outlay 83,000 85,000 Caput Egepmau A000 (0960) Total 756.696 (30.096) 736,696 Debt Sensce Labor 32,478 32.478 BondPmmpal 100,000 (400,000) - Rona loosest 273,161 273.261 Moor of Issuance Costs 3425 3423 Tout 734,164 (403000) 331.161 Other Expenses(Revenues) Amon of CIA-General (1.033760) (1,030.760) .3met of Bund Penmen en (8366) (8.366) Other Espenses(Re,enues) (51,000) (151,000) TOW (1,190,126) - (.193126) Tout Revenue Requirements Before Magus S 10311,'30 S (2762,396)S 7,756334 Trager Slagm 300,000 300002 Total R.se..e Reeeiseaeos 10311,739 6.662.3996 1.668.334 6 -4 9/19/2014 Cask Finn Net Magor(income Approach) S 300,000 Increase for Non Cash&apenses(Revenues) Cash Basis Depreciate=(5400) 1,774,028 Depreciation(5110) 3,210 Amort of Issuance Costs(5450) 8,425 .amort of CIA(4100) (1,030,760) Amon of Bond Premum ($366) Less Ptmcapal on Debt (400,000) CaptulEgtnpment Outlays (617,000) Net Cash Flow 5 31,607 Debt Service Coverage Ratio Net Margins(Income Approach) S 300,000 Add Demo/non 1,777,308 Amon of issuance Costs 1,425 Interest on Debt 273,261 Less Amon of CLA Revenues (1,030,760) Amort of Bond Prelim.Revenues (1,366) Net Cash From Operations S 1,319,168 Debt Service Pensopal S 440,000 Interest 273,261 Total S 673,261 Debt Sentce Coverage R116o 1.96 Results Special Sate Residential Sni Gen Set Ig Cs.Svc C Your .Allocated Cast of Seceiee Energy A 01 01 Energy Sales S 616,131 S 395,322 S 907499 S 364,499 S 3,692 12,217,143 Demand CP 4_0201 CP - - - - - 12 CP A0202 12 CP 644,666 324,063 2,264,794 619,171 3,005 3,11113,619 NCP A0301 NCP 163,411 59692 319375 103,901 1,851 631,610 12 NCP 4_0302 12 NCP - - - - Customer Meters 4_0401 Meter 530,171 134,600 24,411 513 - 619,694 Metes Coo A 0407 Meter Cost - - - - - Meter Rea0asp 4_04 03 Alper R adsg 396,669 100,712 27.397 576 - 325,373 Bs&ng A 04 04 &bag - - Detect IL Detect 4_1001 West-SL - - - - 29,125 19,825 Arent A1002 Detect - - - - Direct 3 4_1003 Detect3 - - - • - -Total S 2,331,145 S 1,013,30* 5 3,553,665 S 1,119,763 S 35,373 S 9056334 Billing Deteenlsuer Customer-Months 24,003 0,207 1,112 72 Fnes97(15611) 15,611 10,016 22,994 94 Demand(8W-mo) 71.150 Eden%Raw Customer 1960 3920 3920 3920 Eou. 1st Bloch 012036 0.13090 0.09939 0.16391 Ind Block 005968 Demand 20.79 Revesses From Fsiv68 Ret Customer S 416,139 S 246.842 44.766 S 1922, billy 1,878,955 1,3911' 1,942,590 15333 Demand - 1493'62 Total 5 2365.093 S 1.638.119 S 3,413 418 3 486,612 S 18,156 S 7.919,391 Yard L tl Revenues 23,740 Toll 0,013,138 Above(Beim,Cart at Service 1% 62% .1% 57% 53% -034% 7 9/19/2014 ` Observations • Overall rates very close to being adequate — $43,200 shortfall (0.5%) — Revenue requirements includes $300,000 margin • Small General Service rates set higher than allocated cost of service • Special Contracts and Street Light rates set lower than cost of service • Special Contracts expire at the end of 2015 Observations/Concerns • Special contracts set to expire at end of 2015. Change to Large General Service (as contemplated) will result in large rate increases to those two customers, and sales to these two may decrease. • Adjusting base rates by CPI could result in either under-recovery or over-recovery. • Including CEA's base rate charges in SES base rates could result in under-/over-recovery if relationship between demand and energy changes in future. 8 9/19/2014 Fuel Cost Adjustment • Current methodology in setting rate is: — Dollar amount of CEA bill (lagged by one month) — Divide by SES sales for month — Apply to next set of bills (billing cycle not equal to CEA) • Can result in over-collection if transitioning from low sales month to high sales month or under-collection if the other way. • Can also result in too high of FCA during low- usage months. Recommendations (Base Rates) • Option 1: City willing to • Option 2: City not set rates commensurate willing to set rates with budget commensurate with — Adjust across the board in budget 2016 based on budget and target margin — CPI increase in 2015 and — Revisit cost of service in late thereafter 2016 — Special Contracts: - Special Contracts: • Set up new Industrial rate or gradually move to LGS • Set up new Industrial rate or • gradually move to LGS Monitor sales • Monitor sales 9 9/19/2014 ` Recommendations (Fuel Cost Adjustment) • Initially set FCA for the month based on expected or actual CEA rate for month (adjusted up for losses) • Establish balancing account that tracks actual costs and revenues • Subsequent monthly FCA based on CEA rate +/- running total from balancing account / sales • Balancing Account is paper only — not an actual account • Consider including all CEA charges in fuel cost adjustment ?? Questions ?? 10 q//2 / 1-1 SEWARD ELECTRIC SYSTEM COST-OF-SERVICE AND RATE ANALYSIS STUDY DRAFT SEWARD ELECTRIC SYSTEM COST-OF-SERVICE AND RATE ANALYSIS STUDY Table of Contents Page INTRODUCTION Background 1 Terms 2 Financial 2 Power 2 II. COST-OF-SERVICE STUDIES Why Are Cost-of-Service Studies Performed 4 The Process 4 Functionalization 5 Classification 5 Allocation 6 III. SES SYSTEM Power Supply Costs 8 Rate Structure 9 Base Rates 9 Fuel Cost Adjustment 10 IV. BILLING DETERMINANTS AND REVENUE REQUIREMENTS Billing Determinants 11 Income or Cash Basis 11 Revenue Requirements 12 V. COST ALLOCATION Introduction 16 Allocation Factors 16 Results 17 VI. SUMMARY AND RECOMMENDATIONS Summary 19 Recommendations 20 Table of Contents SEWARD ELECTRIC SYSTEM COST-OF-SERVICE AND RATE ANALYSIS STUDY Table of Contents - Continued Tables and Figures Table 1 Classification of Revenue Requirements 6 2 Power Supply Costs 8 3 Current Base Rates 9 4 Historical Billing Determinants 11 5 Revenue Requirements - Income Basis 14 6 Revenue Requirements - Cash Basis 15 7 Allocation Results 18 Figure 1 Process 7 Appendixes Allocation A-1 Allocation of Revenue Requirements Classification 13-1 Classification of Revenue Requirements Functionalization C-1 Functionalization of Revenue Requirements C-2 Functionalization of Plant Direct and Indirect Allocation Factors D-1 Allocation Factors D-2 Classification Factors D-3 Functionalization Factors Other E-1 Derivation of Coincident and Non-Coincident Peak Table of Contents ii I. INTRODUCTION BACKGROUND Similar to other electric utilities, the Seward Electric System ("SES") has had to increase its rates from time to time. However how those rate adjustments have been implemented and more recently determining the amount of adjustment have differed from other utilities. For rate adjustments required due to SES' wholesale power supplier (Chugach Electric Association) changing its rates, adjustments to each rate class are made based on revenue responsibilities and other factors. Other rate adjustments, however, are made on an "across-the-board" basis where the rates for all rate classes are adjusted by the same percentage. Across- the-board rate adjustments are typically used by small utilities with only one or two rate classes and even larger utilities with several rate classes. However, those utilities with several rate classes will perform detailed cost- of-service studies from time to time to ensure rate fairness. The level of adjustment differs from other utilities, too. In addition to adjustments required due to changes in wholesale power supply rates, retail rates are also automatically adjusted based on the historical five-year average of the Consumer Price Index ("CPI"). The use of the CPI for setting the amount of adjustment could put the financial health of the Enterprise Fund at risk since it does not take into account the amount of revenues that are required to be recovered. If revenue requirements increase faster than the CPI, under-recovery will occur. Conversely if revenue requirements increase at a rate less than the CPI, too large of burden is placed on the electric consumer. Cost-of-service/rate studies investigate both of these issues: what revenue requirements should be used in setting rates and how should rates in each rate class be adjusted. As will be discussed later in this report, the various rate classes will each affect revenue requirements of the system in a different manner. In order to take this into account, utilities typically perform cost-of-service studies that allocate utility costs to each rate class based on how that rate class causes those costs. Rates are then set such that the "cost causer" is the "cost payer." These detailed studies are typically performed every few years with interim rate adjustments implemented on an across-the-board basis. SES' last cost-of-service study was performed in 1993. Given the length of time since that study and the discontinuity caused by the use of CPI in adjusting rates, staff believed it prudent to perform a detailed cost-of-service study. As such, the services of the Financial Engineering Company were I. Introduction Page 1 retained for performing the analysis, and this report summarizes the analysis and findings. TERMS Certain terms are used in this report that may not be familiar to those not closely associated with the power industry. These terms are described below. Financial Revenue Requirements. The total amount of revenues that must be collected from rates. This includes not only expenses but also margins (net revenues) that are required for capital expenditures and the inherent uncertainty in projecting both sales and expenses. Revenue requirements may also include certain cash items that are not considered "expenses" by accounting standards. Income Basis. Revenue requirements based on the traditional accounting classification of expenses. Depreciation (a non-cash item) is included but principal on debt service is not. Cash Basis. Revenue requirements that does not include depreciation but includes principal on debt. Debt Service Coverage Ratio ("DSC"). The amount of net cash recovered from operations prior to debt service divided by debt service. SES' minimum DSC, set in its bond covenants, is 1.30. DSC = (Net Income + Depreciation + Interest Expense) / (Debt Service) POWER Energy The total amount of power consumed over a given period. For example, a 100-watt light bulb, if left on continuously, uses 2,400 watt-hours of energy during a 24-hour period. During the entire year (8,760 hours), 876,000 watt-hours of energy are consumed. Units: The unit of measurement is typically kilowatt- hours (kWh) or megawatt-hours (MWh). 1 MWh = 1,000 kWh = 1,000,000 watt-hours Demand, or Peak Demand The maximum rate of consumption of power. Usually, this is measured over a 15-minute period, but instantaneous I. Introduction Page 2 demands are also used. If in the previous example a second light is turned on for one hour, then the peak demand is 200 watts. Units: The unit of measurement is typically kilowatts (kW) or megawatts (MW). 1 MW = 1,000 kW = 1,000,000 watts System Peak The combined peak demand of all utility customers placed on the utility. Units: kW, MW Coincident Peak The usage of power of a particular rate group at the time of system peak. Units: kW, MW Non-Coincident Peak The peak demand of a particular rate group. The non- coincident peak of a rate group does not necessarily happen at the time of the system peak. If the rate group's non-coincident peak occurs at the time of its coincident peak, then the two are equal, otherwise (as is usually the case) the non-coincident peak is greater than the coincident peak. Units: kW, MW Billing Determinants The amount of energy sales, demand sales, and number of customers for each rate group during a year. Units: kWh, kW-months, customer-months I. Introduction Page 3 II. COST-OF-SERVICE STUDIES WHY ARE COST-OF-SERVICE STUDIES PERFORMED? Utility management may ask why not simply set rates the same for each rate class? Why go through the process of a cost-of-service analysis? The short answer is fairness to all ratepayers. Take, for example, a utility that has numerous small customers and one large, industrial customer that operates for only a short period of time each year. Assume further that the industrial customer's load is large enough to require the utility to add several additional generating units. A single rate for all customer classes may result in other rate classes paying for the additional generation since the industrial customer operates for only limited times. A cost-of-service analysis, however, would properly allocate the additional generation costs to that customer and allow for its rates to be set to recover those additional costs. The goal of a cost-of-service analysis and subsequent rate design is to allocate a utility's revenue requirements to each rate class such that the "cost causer" is the "cost payer." Since SES rates der by customer class, there is recognition that each class affects the system differently. The question is, however, whether these rates are set close to each class' allocated cost of service. THE PROCESS Although not an exact SCience, standard industry practices have been established to help ensure that rates are not arbitrary or capricious toward any one or more rate classes. In very general terms, the analysis is performed in a multi-step process. These steps are: 1. Projecting the amount of customer months, energy sales, and demand sales. (Billing Determinants) 2. Projecting the utility's revenue requirements. (Revenue Requirements Analysis) 3. Allocating the revenue requirements to each rate class (Cost of Service Analysis) 4. Designing rates that will recover each rate class' allocated cost of service (Rate Design) The first two steps are relatively straightforward, although the uncertainties in projecting either can lead to under- or over-collections. IL The Process Page 4 Once the revenue requirements are projected, the next step is to allocate these costs to each rate group. In an effort to standardize the methodology in allocating costs, the National Association of Regulatory Utility Commissioners for electric utilities published a manual (the "NARUC Manual") that prescribes a multi-step process that Functionalizes, Classifies, and Allocates the revenue requirements. Although SES rates are not subject to review by the Regulatory Commission of Alaska ("RCA"), the methodologies set forth in the NARUC Manual and used herein are the same as that required by the RCA for regulated utilities. FUNCTIONALIZATION A utility's production, transmission, distribution and consumer accounts expenses are functionalized through the Uniform System of Accounts. Administrative and General expenses, interest expenses, and other items are functionalized as either production, transmission, distribution, or consumer accounts using the labor components of expenses already functionalized, functionalized plant in service, and other factors. CLASSIFICATION jj Once the revenue requirements are functionalized, they are then classified as either demand-, energy-, or customer-related. At the risk of over-simplification, the NARUC Manual prescribes the functionalized revenue requirements to be classified as shown in Table 1. Detailed classification methodologies for the various line- item expense codes are provided in the NARUC Manual with the goal of classifying in a fair and equitable manner. For example, fuel is classified as energy since it is directly proportional to the amount of energy required by the utility. The fixed costs associated with generators (i.e., depreciation, interest on debt, etc.) are typically classified as coincident demand related since the utility must install generation to meet the system coincident peak. The manual is published for the use of all utilities nationwide and acknowledges that certain deviations from the methods prescribed may be warranted due to local conditions. II. The Process Page 5 Table 1 SES COST OF SERVICE STUDY Classification of Revenue Requirements Functionalized Classification Revenue Demand Requirement Coincident Non Energy Customer Coincident Production x x Transmission x Distribution x x ALLOCATION The final step in the cost-of-service analysis is to allocate the classified revenue requirements to each customer class (or rate group) based on each class' respective use of the allocation. For example, energy is typically allocated based on sales. If a particular class accounted for 30 percent of the sales, then 30 percent of the costs classified as energy-related would be allocated to that class. Energy- and customer-related expenses are fairly straightforward, but demand allocations become much more complex since there are a number of different methods that can be used. Some form of the coincident and non-coincident peaks are typically used, with such forms including the annual peak, average of the four peak months, average of the twelve months over the year, average of the three summer and three winter peak months, and so on. Complicating the matter is that a great deal of load research must be conducted in order to estimate with any precision these class peaks. Such research can be expensive, and the benefits of obtaining the data can quickly be eroded by the associated costs. Load research of comparable utilities and an analysis of billing demands can be used in lieu of the expensive load research. After the revenue requirements have been allocated to each class, the existing rates are applied to the billing determinants (number of customers, energy sales, demand sales) to determine if the rates recover less than or more than the allocated cost of service. Rates are then adjusted accordingly. The overall process just described is summarized in Figure 1 on the following page. IL The Process Page 6 Figure 1 SES COST OF SERVICE STUDY Process Billing Determinants • Revenue • Functionalization Prod, Dist, etc. cv • . i Classification of Costs Demand, Energy, Customer O U Allocation of Costs Rate Class Adequacy of Rates/ Rate Design / ///eej/�// %i % iii II. The Process Page 7 III. SES SYSTEM POWER SUPPLY COSTS SES receives all of its power supply from Chugach Electric Association ("CEA" or "Chugach"), although back-up generation is maintained in the event of service disruptions. The monthly CEA bill for power consists of a relatively small customer charge, an energy charge, a demand charge, and fuel cost adjustment. The first three rates are modified through a general rate proceeding with the RCA, whereas the fuel cost adjustment ("FCA") is adjusted monthly based on CEA's fuel costs and generating efficiencies. CEA reduces the overall bill by a fixed amount each month in recognition of SES' share of the Bradley Lake Hydroelectric Project. Power supply bills since January 2013 are summarized in the following table. Other Adjustments in Column L include: 1) small credits for wind energy excess to AVTEC's requirements being sold to CEA at CEA's avoided cost rate, and 2) other adjustments made by CEA from time to time. Table 2 SES COST OF SERVICE STUDY Power Supply Costs A B C D E F G H I 7 I` L M N 0 P Chugach Bill Total Bill Without FCA Demand Charge Energy a FCA Adjustments Cust Rate Amount Rate Amount Subtotal Total S Sales (MWh) S kWh (S) MEW) OM S (SEM%) h) S S BradleyOther Bill Jan-13 S 300 S 8.40 10,204 S 85,714 50.00572 5,667 S 32,413 S 205,842 S 324,268 S (14,439) S (266) S 309,564 S 103,722 5,154 S 0.020 Feb-13 300 11.12 9,244 102,793 0.00757 5,133 38,858 248,993 390,944 (14,439) (138) 376,367 127,375 4,971 0.026 Mar-13 300 11.12 9,409 104,628 0.00757 5,602 42,408 250,137 397,473 (14,439) (251) 382,784 132,647 4,577 0.029 Apr-13 300 11.12 9,372 104,217 0.00757 5,401 40,885 236,912 382,314 (14,439) (329) 367,546 130,634 5,383 0.024 May-13 300 11.12 8,965 99,691 0.00757 5,162 39,073 320,998 460,062 (14,439) (92) 445,531 124,533 4,317 0.029 Jun-13 300 11.12 9,329 103,738 0.00757 5,900 39,363 259,433 402,835 (14,439) (27) 388,369 128,936 4,478 0.029 Jul-13 300 11.12 10,055 111,812 0.00757 5,917 44,794 273,242 430,148 (14,046) (77) 416,025 142,783 5,126 0.028 Aug-13 300 11.12 10,364 115,248 0.00757 6,089 46,097 328,778 490,423 (14,046) (132) 476,245 147,467 5,991 0.025 Sep-13 300 11.12 9,071 100,870 0.00757 4,852 36,730 302,433 440,332 (14,046) (443) 425,843 123,410 4,605 0.027 Oct-13 300 11.12 8,489 94,398 0.00757 4,926 37,287 238,484 370,468 (14,046) (142) 356,281 117,797 4,434 0.027 Nov-13 300 11.12 9,081 100,981 0.00757 5,049 38,220 196,214 335,715 (14,046) (554) 321,114 124,900 4,429 0.028 Dec-13 300 11.12 9,209 102,404 0.00757 5,509 41,706 240,643 385,053 (3,732) (487) 380,834 140,191 4,485 0.031 Jan-14 300 12.63 8,964 113,215 0.00861 5,372 46,250 225,869 385,634 (14,046) (107) 371,482 145,613 5,129 0.028 Feb-14 300 12.63 9,482 119,758 0.00861 5,013 43,161 240,390 403,609 (14,046) (24,454) 365,109 124,719 4,570 0.027 Mar-14 300 12.63 9,437 119,189 0.00861 5,494 47,300 232,069 398,858 (17,324) (200) 381,334 149,265 4,573 0.033 Apr-14 300 12.63 8,297 104,791 0.00861 4,956 42,674 247,704 395,470 (15,685) (87) 379,698 131,994 4,742 0.028 As will be discussed in the next section, SES passes the FCA (Column I) on to its customers through its own Fuel Cost Factor. All other costs, summarized in Column N, are included in the SES base rates. Therefore, it is important to note the variability of these costs (in $/kWh) as shown in Column P. This variability is a function of several factors including the CEA billing rates, the SES system peak demand as compared to energy sales, III. SES System Page 8 • and other adjustments CEA may charge from time to time. How this variability may affect the appropriate collection of revenues is discussed in the following section. RATE STRUCTURE BASE RATES SES has three primary rate groups, two additional sets of rates for Yard Lights and Street Lights, and two special contracts. In 2012, SES implemented a policy whereas rates would be adjusted each year based on the five-year historical CPI as well as any changes in CEA's rates. Rates charged since 2012 are summarized in Table 3. CPI adjustments are passed through on an across-the-board basis whereas adjustments due to CEA rate changes are passed through on more detailed allocations. Table 3 SES COST OF SERVICE STUDY Current Base Rates 2012 2013 2014 Rates %Increase Rates I %Increase Rates %Increase Residential Customer(S'month) 13.19 19.10 5.0% 19.60 2.6% Energy(S'kWh) 0.10853 0.11610 7.0% 0.12036 3.7% Small General Service Customer(S'month) 3639 38.21 5.0% 39.20 2.6% Energy(S'kWh) 0.12525 0.13399 7.0% 0.13890 3.7% Large General Service Customer(S'month) 36.39 38.21 5.0% 39.20 2.6% Energy(S,kWh) First 200 kWh'kW 0.08961 0.09587 7.0% 0.09939 3.7% Additional 0.05380 0.05756 7.0% 0.05968 3.7% Demand(S.kW) 1537 18.79 223% 20.79 10.6% Yard Lights(S'month) 175 Watt 8.18 8.59 5.0% 8.81 2.6% 250 Watt 12.13 12.74 5.0% 13.07 2.6% 400 Watt 24.89 1,000 Watt 62.23 Street Lights Customer(Vmonth) 36.39 38.21 5.0% 39.20 2.6% Energy(S kWh) 0.14780 0.15811 7.0% 0.16391 3.7% Base rates are set to recover costs incurred in operating and maintaining the system as well as the power supply costs in Column N of Table 2. Recovering the power supply costs through the base rates poses certain risks for SES. CEA adjustments to its own base rates, changes in Bradley Lake costs, or even changes in the SES system peak as a function of its energy requirements may create revenue surpluses or shortfalls without III. SES System Page 9 corresponding adjustments to the base rates. For this reason, many utilities include all of its purchase power costs in the fuel cost adjustment. FUEL COST ADJUSTMENT In addition to the Base Rates summarized above, SES charges a Fuel Adjustment that includes: 1. The Fuel Cost Adjustment charged by CEA. 2. Costs of operating and maintaining SES' standby generation when such costs exceed the budgeted expenses. 3. A monthly charge of $31,596 which reflects the recovery of a $1,895,754 revenue shortfall due primarily to a storm event in 2010. This amount is being recovered over a 60-month period through May 2016. The rate charged by SES, in $/kWh, is equal to the sum of the three items above (in dollars) divided by the energy sales for the month. Over the past 12 months, the FCA has ranged between 00.050/kWh and $0.072/kWh. The CEA fuel adjustment is billed to SES on a one-month lag; and SES, in turn, lags the pass-through by a month to its customers. It is noted, too, that SES bases the FCA on the dollar amount charged by CEA, not the rate adjusted for losses. Thus when months with high energy sales are followed by a months with lower sales, the lag will result in a relatively high FCA being charged during the months with low energy sales. Another method that is commonly used is to establish a balancing account. The FCA for a month is based on the estimated rate for fuel and purchased power, and over-/under-recoveries are tracked monthly and included in the costs to be recovered in the following month. A review of CEA's billing records shows that energy requirements can vary by up to 20 percent from one month to the next. III. SES System Page 10 IV. BILLING DETERMINANTS AND REVENUE REQUIREMENTS BILLING DETERMINANTS The number of customers, energy sales, and billing demands by customer class for the past two years are summarized in the following table. Energy sales in 2013 were approximately 1.3 percent lower than the previous year, and wholesale power purchases for 2014 indicate that sales in 2014 may be lower still. For purposes of this analysis, 2013 billing determinants are used, although the sensitivity of revenue adequacy in rates will be tested later in this report. Table 4 SES COST OF SERVICE STUDY Historical Billing Determinants Average Number Energy Sales Billing of Customers (MWh) Demand 2012 2013 2012 2013 2012 2013 Residential ,,,,, 2,058 2,067 16,488 15,611 Sm Gen Svc/Harbor 522 525 10,095 10,016 Lg Gen Svc 93 95 23,657 22,994 74,708 71,850 Special Contract 2 8,402 9,235 21,497 21,879 P Street Lights ; 96 94 Total 2,675 2,689 58,738 57,950 96,205 93,729 INCOME OR CASH BASIS? If SES were regulated by the RCA, the Income Basis would be used in setting rates. although the adequacy of cash flow would be tested. But SES is not rate regulated, and it therefore has a degree of latitude in setting revenue requirements and rates. The question then becomes which is better: the Income Basis or the Cash Basis? The primary difference between the two is that the Income Basis uses depreciation expenses to recover the cost of assets whereas the Cash Basis uses principal on debt and actual cash disbursements. Therefore for non- debt funded assets, cost recovery is spread out over time with depreciation whereas current ratepayers pay for the asset via the Cash Basis. But what about high-cost assets that are funded from cash reserves or from the General Fund? Inclusion of those costs in revenue requirements using IV. Billing Determinants / Revenue Requirements Page 11 the Cash Basis could cause rates to spike in certain years. Furthermore, today's ratepayers would be paying for assets that will be used by ratepayers of the future. Recovery of high-cost assets with depreciation but using the cash approach for smaller assets can lead to confusion. The Income Approach is therefore used in this analysis, although the adequacy of net cash flows is also tested. REVENUE REQUIREMENTS Revenue requirements are taken from the 2015 budget with certain adjustments made for this analysis. The revenue requirements and adjustments are summarized in Table 5 at the end of this section, and a more detailed summary is provided in Appendix A-2 to this report. Adjustments made are explained as follows. 1. Capital Outlay. Capital outlays are not considered an expense in the Income Approach. Instead these expenditures add to plant and correspondingly increase depreciation expenses. For the Income Approach, Capital Outlays are excluded. 2. Purchased Power - Base Rates. CEA increased their retail and wholesale base rates in January 2014, and costs for Bradley Lake were also adjusted. Based on the amount of energy and demand purchased by SES in 2013, the purchased power expense would be $17,411 more than that budgeted. 3. Purchased Power - Fuel. Although this is considered an expense, it is passed through directly via the Fuel Cost Adjustment and not through Base Rates. Consequently, it is excluded from the allocation analysis. 4. Work Orders. On an annual basis, this amount may be a negative or positive number. However over a longer period of time, expenses should approximate billings. Consequently, this amount is set to zero. 5. Depreciation. This non-cash expense is included as an expense in the Income Approach but excluded in the Cash Approach. 6. Payment in Lieu of Taxes. SES' budget transfers this expense to another account, but the expense is nonetheless incurred by the utility. Accordingly, Payment in Lieu of Taxes is included in the revenue requirements. 7. Motor Pool Capital Outlay. This represents a charge assessed to various City utilities for vehicle replacements, with the actual replacement not necessarily occurring at the same time as the assessment. Although labeled as a "capital outlay," the costs are imposed on SES each year and should be included in both the Income and Cash Approaches. IV. Billing Determinants / Revenue Requirements Page 12 8. Electric System Permit Fee. This amount was transferred out of the Electric Enterprise Fund budget and instead included in the General Fund budget. The amount is included as a revenue requirement. 9. Federal/State Lobbying. Similarly, the Electric Enterprise Fund's allocation of federal and state lobbying expenses was included in the General Fund budget. This amount is included with the overall revenue requirements. 10.Bond Principal. Principal payments on debt are not included as an expense in the Income Approach since the inclusion of depreciation on the assets funded with debt would be a double counting of expense. The amount is excluded from the Income Approach but included in the Cash Approach. 11.Amortization of Issuance Costs and Bond Premium. These are non- cash expenses that recover costs of incurred when issuing debt. Consequently, these are included in the Income Approach and excluded in the Cash Approach. 12.Amortization of Contributions in Aid of Construction. When installing certain capital assets, SES may receive funds from customers or others to help fund the assets. Essentially the opposite of depreciation expenses, these funds are recognized over the life of the asset. A non-cash item, it Is included in the Income Approach and excluded in the Cash Approach. 13.Target Margin. There are certain inherent inaccuracies in the projection of both revenues and revenue requirements. Actual expenses may he higher or lower than projected as might be actual billing determinants (energy sales, billing demands, etc.). Accordingly revenue requirements for regulated utilities include return on rate base or projected net revenues that will provide higher margins (profits) than that required by lenders. For unregulated utilities such as SES, revenue requirements can simply be increased by an appropriate net margin. For purposes of this analysis, a net margin of $300,000 is added to the revenue requirements. This amount represents the approximate amount required to support the cash flows required when taking into account budgeted small capital outlays. A smaller target margin could be used and instead use available cash in the Electric Enterprise funds. Total revenue requirements and adjustments are summarized on the following page and provided in detail in Appendix B-1. The cash flow from operations and debt service coverage ratio are summarized in Table 6. N. Billing Determinants / Revenue Requirements Page 13 Table 5 SES COST OF SERVICE STUDY Revenue Requirements -Income Basis Dept 2015 Adjustments Net Adj Note Budget 5100 Standby Generation 155,751 155,751 5110 Substation 323,701 323,701 5220 Transmission Ops 72,261 72,261 5230 Distribution O&M Labor O&M 63,610 63,610 Capital Outlay 465,000 (465,000) - 1 Subtotal 528,610 (365,000) 63,610 5250 Wholesale Power Costs Purchased Power-CEA 1,775,000 17,411 1,792,411 2 Purchased Power-Fuel 3,066,000 (3,066,000) - 3 Total 4,841,000 (3,048,589) 1,792,411 5300 Work Orders (45,583) 45,583 - 4 5310 Standby 90,434 90,434 5380 Meter Services 95,566 95,566 5400 General Labor'O&M 1,293,670 1,293,670 Depreciation 1,774,028 1,774,028 5 Gen Govt Admin Fee 868,558 868,558 PILI 915,291 915,291 Reclass PICT to T Fs (915,291) 915,291 - 6 Motor Pool Rent-Cap Outlay 90,000 90,000 7 Electric System Permit Fee - 300,000 300,000 8 Fed.State Lobbying - 40,319 40,319 9 Capital Outlay 100,000 (100,000) - 1 Capital Equipment 30,000 (30,000) - 1 Total 3,156256 1,125,610 5231,866 5410 Admin Engineering Labor O&M 643,416 648,416 Depreciation 3,280 3,280 5 Motor Pool Rent-Cap Outlay 85,000 85,000 7 Capital Equipment 20,000 (20,000) - 1 Total 756,696 (20,000) 736,696 5450 Debt Service Labor 52,478 52,478 Bond Principal 400,000 (400,000) - 10 Bond Interest 273,261 273,261 Amor of Issuance Costs 8,425 8,425 11 Total 734,164 (400,000) 334,164 4800 Other Expenses(Revenues) Amort of CIA-General (1,030,760) (1,030,760) 12 Amort of Bond Premium (8,366) (8,366) 11 Other Expenses(Revenues) (151,000) (151,000) Total (1,190,126) - (1,190,126) Total Revenue Requirements Before Margins S 10,518,730 S (2,762,396) S 7,756,334 Target Margin 300,000 300,000 13 Total Revenue Requirements 10,518,730 (2,462,396) 8,056,334 IV. Billing Determinants / Revenue Requirements Page 14 Table 6 SES COST OF SERVICE STUDY Revenue Requirements - Cash Basis Cash Flow Net Margin(Income Approach) S 300,000 Increase for Non Cash Expenses(Revenues) Depreciation(5400) 1,774,023 Depreciation(5410) 3,280 Amort of Issuance Costs(5450) 8,425 .Amort of CIA(4300) (1,030,760) Amort of Bond Premium (8,366) Less Principal on Debt (400,000) Capital Equipment:Outlays (615,000) Net Cash Flow S 31,607 Debt Service Coverage Ratio Net Margins(Income Approach) S 300,000 Add: Depreciation 1,777303 Amort of Issuance Costs 8,425 Interest on Debt 273,261 Less: Amort of CIA Revenues (1,030,760) Amort of Bond Premium Revenues (3,366) Net Cash From Operations S 1,319,868 Debt Service Principal S 400,000 Interest 273,261 Total S 673,261 Debt Service Coverage Ratio 1.96 IV. Billing Determinants / Revenue Requirements Page 15 V. COST ALLOCATION INTRODUCTION Cost-of-service studies are not an exact science. As described in Section II of this report, revenue requirements are classified as energy related, demand related, customer related, a combination thereof, or directly assigned to a rate group. Once the classification is completed, the costs are then allocated to each rate group based on estimates of each rate group's contribution to the classifier. The NARUC Manual was established to set forth guidelines in classifying the various revenue requirements, but the manual acknowledges that local factors must dictate during the classification process. During the allocation process, factors that represent each rate group's contribution to total energy sales and the total number of meters can readily be developed. But contributions to coincident and non-coincident demands are not so straightforward and must be estimated. All in all, the results should not be taken as exact numbers but rather guidance on whether rates are set too high or too low. ALLOCATION FACTORS Revenue requirements are based, in part, on the 2013 billing determinants described in the previous section. These, then, form the allocation factors for both energy- and meter-related expenses. Demand-related expenses are allocated based on estimates of each class' contribution to the coincident peak and the non-coincident peak. For a large utility, these estimates are developed through detailed load research where the hourly usage of customer sample groups are monitored over at least a year. From this, estimates can then be made for rate classes as a whole. This load research, however, is relatively expensive, and the benefits of gaining the information are quickly eroded for small utilities such as SES. Therefore, other methods are used, such as reviewing billing demand records for large customers and using load research data from nearby utilities. For this analysis, the load research data developed by Anchorage Municipal Light & Power ("AML&P") is used as guidance and modified where deemed appropriate. CEA has not completed its detailed load research based on individual meter data, and the data it does have is not in a format conducive to use in this study. It must be remembered that the load research is used V. Cost Allocation 16 , to estimate load patters, not actual loads. Although AML&P is much larger than the SES system, its compactness is believed to make it a better indicator of SES load patterns than CEA's. The allocation factors used in this analysis are summarized in Appendix D-1 and how they were estimated in Appendix E-1. RESULTS The results of the analysis are summarized in Table 7 on the following page with details provided in the following Appendixes. Appendix A: Allocation of Revenue Requirements Appendix B: Classification of Revenue Requirements Appendix C: C-1: Functionalization of Revenue Requirements C-2: Functionalization of Plant The table summarizes the allocated costs to each rate group as well as projected revenues. From this, current rates can be evaluated with respect to the overall adequacy and how close each rate group is to its allocated cost of service. It is also important to remember that the revenue requirements and projected revenues are exclusive of CEA's fuel cost adjustment expenses and SES' revenues from its own fuel cost adjustment. The following assumptions were made in projecting the revenues. 1. Base rates now in effect at the beginning of 2014 are used and do not include any adjustments for possible CPI increases in January 2015. 2. Energy revenues from the Large General Service class are based on all customers having monthly energy requirements equal to or greater than 200 kilowatt-hours/kilowatt of demand. 3. Revenues from the Special Contracts are based on rates contractually set for 2015. 4. Revenues from Yard Lights are equal to that recorded in detailed monthly billing records for 2013. The results show that overall, exiting rates are projected to recover revenues slightly under the total revenue requirements. Total revenue requirements are assumed to be $8,056,334, whereas projected revenues are $8,013,138, or $43,196 less than requirements. However it must be remembered that revenue requirements include a target margin of $300,000, so based on the requirements and revenues, SES would have a net margin of $256,804 (Income Basis). V. Cost Allocation 1 7 For individual rate classes, Residential and Large General Service rates are set relatively close to their allocated cost of service. Small General Service rates are set higher than cost of service, and Special Contracts set lower. In 2016, the Special Contracts are set to revert to Large General Service. A preliminary analysis shows that at that time, Large General Service rates might be slightly higher than cost of service (due to the additional revenues gained from the two customers), and Small General Service Rates would be closer to its cost of service. Table 7 SES COST OF SERVICE STUDY Allocation Results Residential Sm Gen Sic Lg Gen Svc Special Street Total Contract Lights Allocated Cost of Service Energy A.01.01 Energy Sales S 616,131 S 395,322 S 907,499 S 364,499 S 3,692 S 2,287,143 Demand CP A.02.01 CP - - - - - 12 CP A.02.02 12 CP 644,666 324,063 2,264,784 649,171 3,005 3,885,689 NCP A.03.01 NCP 163,488 58,692 309,575 105,004 1,851 638,610 12 NCP A.03.02 12 NCP - - - - - - Customer Meters A.04.01 Meters 530,171 134,600 24,411 513 - 689,694 Meter Cost A.04.02 Meter Cost - - - -Meter Reading A.04.03 Meter Reading 396,689 100,712 27,397 576 - 525,373 Billing A_04.04 Billing - - - - - - Direct SL Direct £10.01 Direct-SL - - - - 29,825 29,825 Direct 2 A.10.02 Direct 2 - - - - - Direct 3 A.10.03 Direct 3 - - - - - - Total S 2,351,145 S 1,013,388 S 3,533,665 S 1,119,763 S 38,373 S 8,056,334 Billing Determinants Customer-Months 24,803 6,297 1,142 72 Energy(MR%) 15,611 10,016 22,994 94 Demand(kW-mo) 71,850 Existing Rates Customer 19.60 39.20 3920 39.20 Energy 1st Block 0.12036 0.13890 0.09939 0.16391 2nd Block 0.05968 Demand 20.79 Revenues From Existing Rates Customer S 486,139 S 246,842 44,766 S 2,822 Energy 1,878,955 1,391,277 1,942,890 15,333 Demand - - 1,493,762 - Total S 2,365,093 S 1,638,119 S 3,431,418 S 486,612 S 18,156 S 7,989,398 Yard Light Revenues 23,740 Total 8,013,138 Above(Below)Cost of Service 1% 62% -1% S7% -53% -0.5% V. Cost Allocation 18 VI. SUMMARY AND RECOMMENDATIONS SUMMARY The analysis revealed that, based on the assumptions described herein, rates now in effect (but adjusted in 2015 for the two Special Contract customers) are projected to result in a revenue shortfall of approximately $43,200. However since the assumed revenue requirements include a target margin of $300,000, a net operating income would still result with current rates. For the revenue requirements to be attained, rates would have to be increased by approximately 0.5 percent on an across-the-board basis in January 2015. Projected revenues are based on the number of customers and energy/demand billings incurred in 2013. However, sales to date in 2014 indicate that 2014 sales may be less than the prior year. An erosion of sales by 1 percent (approximately 590,000 kWh) would decrease revenues by approximately $80,000. Therefore, all else being equal, net positive margins would result with up to approximately 1.8 million kWh less sales than in 2013). It is anticipated that without load growth, inflationary pressures on operating costs would create the need for a rate increase in 2016. Although overall rates are set relatively close to revenue requirements, the Cost-of-Service Study revealed that Small General Service rates are set higher than the allocated cost of service whereas Special Contracts are set lower. Street Lights are also set lower than cost of service, but the overall dollar amount collected from the rate class is quite small as compared to other classes, and therefore percentages can be amplified. The two Special Contract customers will begin to take power via the Large General Service rates in 2016 unless the contracts are modified or a new Industrial rate class is established. Based on the Cost-of-Service Study, however, an Industrial rate would be higher than the Special Contract rate that the two customers now use. With the higher rates of either the Large General Service or a new Industrial rate, usage by the two Special Contract customers may decrease. Part of the revenue requirements recovered with base rates include the customer, energy, and demand charges related to power supply purchases from CEA. Many utilities instead recover these costs through the fuel cost VL Summary and Recommendations 19 , yv adjustment. However since fuel cost adjustment charges are based on energy consumption, this would result in shifting demand charges into energy charges. As long as SES' load factor (average energy usage divided by peak demand) does not significantly change, maintaining these costs in the base revenue requirements, base rates should remain adequate. However, if load factors change or CEA implements revised rates, adjustments should be made to the base rates. As described in this study, there is a two-month lag in charging customers for CEA's fuel cost adjustment, and the total dollar amount is used instead of the billing rate adjusted for losses. Thus in periods of transition between months with low and high usage, low-usage months could have a relatively high fuel cost adjustment. Conversely, high-usage months could have a relatively low fuel cost adjustment. RECOMMENDATIONS Based on the analysis, findings, and summary above, the following recommendations are made with respect to the SES electric rates. 1. Leave rates as is through the end of 2015 with no inflationary adjustment in January 2015. However, rate adjustments might be required earlier than this due to: a. CEA adjusting its wholesale power rates. b. There is a significant change in the SES load factor. c. Inflationary and other pressures increase revenue requirements more than expected for 2015. 2. In 2016, rate adjustments should be implemented on an across-the-board basis. 3. Monitor usage by the Special Contract customers in 2016. 4. Update the Cost-of-Service study toward the end of 2016 for rate adjustments to be made in 2017. At that time, Small General Service rates can be moved closer to cost of service. 5. Consider a revision to the SES Fuel Cost Adjustment by: a. Basing the rate on the expected CEA Fuel Cost Adjustment rate for the month adjusted by the assumed losses. b. Establish a balancing account that tracks over- and under-collections. c. Adjust the SES Fuel Cost Adjustment with the over- and under-collections calculated in the balancing account. VL Summary and Recommendations 20 .4. (712_271 Li Ti o N cn h l I .. /0 : Co tivl c., i --/- lAA-lam_ 1 r. _.„ ,,, ., .„, ..,.. 1 , .,,, ,0 v-d_d_Att, ,, 0 ' NAV_ yr Gry ,+ yY n i_i161-6---/A-P" 'Ft >, ArigaffIN- cti 2-2- i _ u ,.. tit z 1/11 4 GBOS meeting highlights electricity rate increase , ,r; and school construction /''.1 '" N By Marc Qonadieu good. It has impacts that are k "r Turnagain limes Correspondent operational, and it also has e c'...)' impacts that are rate based." iThe GBOS met MondayIn short, the bad news, jr,,—,,• night, highlighted by a pre- he said, was that Girdwood , (..., C, i Z., sentation about upcoming residents could expect an —4 . changes to be implemented increase in electric rates by , . ; by Chugach Electric As- around 10 percent in the „ .; sociation, which includes near future. The reason for A\ ' ` electricity rate increases. the increase is due to loss o There were also updates on of wholesale power sales to ''" p...,:4 the progress of the Gird- Homer Electric Association { .. �i o wood K-8 School rebuild- and Matanuska Electric As- ing and the final list of the sociation. . Is, 2015 Capital Improvement "When they [MEA] Projects. leave," said Steyer, "we're rzq Phil Steyer of CEA started going to see a bump that's i' "("{ k I witgoing a presentation about up- going to be even bigger. We coming operational and rate predict, and we're trying ti changes that will affect Gird- hard to hold that increase to wood residents. maybe 10 percent. It's not "So we have these going to be easy because `") changes underway in the rail they contribute a lot." E belt," said Steyer. "People - p in '. always say change is good, See Page 7, q ..:,,` .. - but, in this case, it's not so GBOS Meeting E 4.7. , �� i i C 'a p'r. 0 Turnagain Times September 18, 2014 Page 7 GBOS Meeting Continued from page 1 HEA is now producing its "Your Facebook page is Kelley, the municipal liaison "Costs for extra work this past own power, he said, so it has very, totally, worthlessly in- for Girdwood, read a letter summer are still being quant stopped purchasing it whole- active," Leonard said. "There from Calvin Mundt, Project tified by the contractor, and sale from CEA. MEA is in were two outages in the last -Manager for the Anchorage once these costs are negotiat- the process of phasing out five weeks. I looked on the School District Facilities, ed and contract modifications its wholesale purchasing of Facebook page for days after concerning the progress of written, there will be a better power from CEA. This de- that and there was nary a word rebuilding the Girdwood K-8 idea of remaining contingency crease in wholesale power about it." School. Currently, the steel funds." sales by CEA means that rates "We use our Facebook page erection for the addition is The other main item of will increase due to fixed costs for power outage reporting," getting built with bolts being business at the meeting was of generating less power. , : Steyer responded, "but some- tightened and welds being the final list of Girdwood "The reason these things times that reporting doesn't placed. "The connections for Capital 'Improvement Proj- go up is we have a certain happen right away. What I try the elevated running track are ects for 2015. This list priori- amount of fixed costs that are to do is get something on there in place," Mundt wrote, "so tizes funding requests from spread across abroad number i after the fact." the option of building the ele- the Legislature, with empha of kilowatt hours," Steyer I Steyer said there were two vated track at a future date has sis being given to one project said. "When suddenly they go recent Girdwood outages been preserved." to.ensure it receives funding away,we don't have the same in a week caused by ravens The mention of the elevat- during tight budgetary times. number of kilowatt hours getting into an exposed part ed running track.as a future The GBOS designated the sales to spread fixed costs of the substation. The intru- option and not a current Comprehensive Road and across, and the unit price goes sion created an electric arc projectraisedquestions from Drainage Study as its top pri- up for everybody else. It's that shorted out the system -community members in atten- ority because its results will even worse when Matanus- and electrocuted the ravens. dance.They wanted to know if determine future growth and ka Electric leaves us because He said CEA is looking into something needed to be done development in Girdwood. they were a larger customer putting protective material on to advocate for construction This study will identify road than Homer [Electric]." the substation to prevent a re- _ of the elevated running track issues and assess drainage When it came time to ask currence. as it was originally planned. issues to specify where im- questions, audience member In other business, Kyle Whether or not the track provement is needed. The Lewis Leonard mentioned I can be completed depends on data from the study will allow some recent Girdwood power the calculation of summer cost road and drainage projects to outages and the lack of local I overruns for unexpected work be prioritized and funds to be information about them. He and what is left from contin- used more efficiently instead then delivered a critique of the gency funds. The final costs of on a case-by-case basis. CEA's Facebook page, which will not be available until No- There was also discussion is supposed to keep customers vember. about adding an amendment informed about outages. "The remaining budget to the CIP to include addi- appears adequate to complete tional funding for the Arlberg the project," Mundt wrote. Avenue extension. Girdwood resident Diana Livingston higher than expected cost stated that the project was of wetlands mitigation is likely to fall short of funding driving the cost overrun on the and unable to be completed Arlberg Extension,so the road as planned. She suggested has been shortened as a result. adding this request to the CIP The cost of wetlands mitiga- while also requesting funding tion for the extension is esti- for a parking lot, restroom fa- mated to be between a half- cilities, and a trailhead at the million and a million dollars, end of the extension. while further extension of the Board member David road is estimated to be another Chadwick observed how the million dollars. 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