Hethie S. Pamesano Rebuttal Exhibits - nyseg
Hethie S. Pamesano Rebuttal Exhibits - nyseg
Hethie S. Pamesano Rebuttal Exhibits - nyseg
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Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 1 of 55February 08, 2010Rochester Gas & Electric CorporationMarginal Cost of Electric Delivery Service
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 2 of 55Project Team<strong>Hethie</strong> ParmesanoAmparo NietoWilliam RankinJordan NarducciNicholas AmabileNERA Economic Consulting777 South Figueroa Street, Suite 1950Los Angeles, California 90017Tel: +1 213 346 3000Fax: +1 213 346 3030www.nera.com
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 3 of 55ContentsI. INTRODUCTION........................................................................................................................1II. COSTING/PRICING PERIODS.................................................................................................2III. MARGINAL TRANSMISSION COST ....................................................................................3IV. MARGINAL DISTRIBUTION COSTS ...................................................................................5A. Upstream Distribution Equipment and Distribution Substation and Trunkline FeederCosts.....................................................................................................................................6B. Local Distribution Facility Costs.......................................................................................11C. Lighting Costs....................................................................................................................13D. Meter and Service Costs ....................................................................................................17V. OTHER MARGINAL COSTS .................................................................................................21A. Customer Accounts Expenses............................................................................................21B. Customer Service and Informational Expenses .................................................................22C. Administrative and General Expenses...............................................................................24D. General Plant......................................................................................................................24E. Marginal Losses.................................................................................................................25VI. COMPUTATION OF ECONOMIC CARRYING CHARGES ..............................................26VII. COMPUTATION OF ANNUAL MARGINAL COSTS.......................................................28VIII. SUMMARY TABLES AND EFFICIENT PRICES.............................................................38NERA Economic Consultingi
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 4 of 55List of TablesTable 1. Costing/Pricing Periods .............................................................................2Figure 1. Simplified Diagram of RG&E’s Delivery System ...................................3Table 2. 2010 Time-Differentiated Marginal Transmission Costs .........................4Table 3. Upstream Lines & Substation and Distribution Substation &Trunkline Feeder Marginal Investment ............................................................7Table 4. Upstream Station and Distribution Substation O&M Expense perkW.....................................................................................................................9Table 5. Upstream Line & Trunkline Feeder O&M Expense per kW...................10Table 6. Probability of Peak for Upstream Facilities and DistributionSubstations & Trunkline Feeders....................................................................11Table 7. Marginal Distribution Facilities Investment per kW of...........................12Design Demand......................................................................................................12Table 8. Distribution Facilities O&M Expense per kW of Design Demand .........13Table 9. SC6 Area Lighting Investment and Annual Maintenance.......................15Table 10. SC1 Street Lighting Investment and Annual Maintenance ...................16Table 11. Annual Relamping Expense...................................................................17Table 12. Investment per Customer in Meters and Services .................................18Table 13. Meter O&M Expense per Weighted Customer......................................19Table 14. Meter O&M Expense by Service Classification....................................20Table 15. Adjustment Factor for Uncollectibles....................................................21Table 16. Customer Accounts and Uncollectibles Expense by ServiceClassification ..................................................................................................22Table 17. Customer Services and Informational Expenses by ServiceClassification ..................................................................................................23Table 18. Administrative and General and General Plant Loaders .......................25Table 19. Incremental Capital Structure and Cost.................................................26Table 20. Economic Carrying Charges..................................................................27Table 21. Derivation of Annual Distribution Substation and TrunklineFeeder, Upstream Line and Upstream Station Costs......................................29Table 22A. Derivation of Annual Distribution Facilities Costs ............................30Table 22B. Derivation of Annual Distribution Facilities Costs.............................30Table 23A. Derivation of Annual Meter, Service and Customer-RelatedCosts – After Customer Contributions ...........................................................31Table 23B. Derivation of Annual Meter, Service and Customer-RelatedCosts – Full Cost Before Customer Contributions .........................................32Table 23C. Derivation of Annual Meter, Service and Customer-RelatedCosts – After Customer Contributions ...........................................................33Table 23D. Derivation of Annual Meter, Service and Customer-RelatedCosts – Full Cost Before Customer Contributions .........................................34Table 23E. Derivation of Annual Meter, Service and Customer-RelatedCosts ...............................................................................................................35Table 24. Derivation of Annual Area Lighting Costs............................................36Table 25. Derivation of Annual SC1 Street Lighting Costs ..................................37NERA Economic Consultingii
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 5 of 55Table 26. Summary of Marginal Upstream, Distribution Substation andTrunkline Feeder Costs per kW......................................................................39Table 27. Summary of Marginal Transmission, Upstream and DistributionSubstation and Trunkline Feeder Costs, Stated on a per-kWh Basis .............40Table 28 A. Summary of Monthly Marginal Customer and LocalDistribution Facilities Costs per kW of Design Demand and PerCustomer – After Customer Contributions.....................................................41Table 28 B. Summary of Monthly Marginal Customer and LocalDistribution Facilities Costs per kW of Design Demand and PerCustomer – Total Cost Before Customer Contributions.................................42Table 29. Summary of Monthly Marginal Area Lighting and SC1 StreetLighting Cost Per Component ........................................................................43Table 30. Summary of Monthly Marginal Relamping Cost Per Unit....................44Table 31. Marginal Costs Compared to Current Rates (Non-Lighting) ................45Table 32. Marginal Costs Compared to Current Rates (Lighting Deliveryand Fixed Charges).........................................................................................46Table 33. Marginal Costs Compared to Current Rates (Lighting SC 1Circuit Charges)..............................................................................................46Table 34. Marginal Costs Compared to Current Rates (Lighting SC 1Fixture Charges) .............................................................................................47Table 35. Marginal Costs Compared to Current Rates (Lighting SC 1 LampCharges)..........................................................................................................48Table 36. Marginal Costs Compared to Current Rates (Area LightingFixture Charges) .............................................................................................49NERA Economic Consultingiii
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 6 of 55I. INTRODUCTIONRochester Gas & Electric Corporation (RG&E) retained NERA Economic Consulting to preparean estimate of the company’s typical marginal costs of delivering electricity, for use in thecompany’s 2009 rate case. All costs are expressed in 2010 dollars. Estimates of marginal costsfor subsequent years can be calculated by applying an appropriate inflation factor. 1 This reportdescribes the methods for estimating marginal transmission, distribution and customer-relatedcosts and presents summary tables of the results.What are marginal costs? Marginal cost is defined as the change in total cost with respect to asmall change in output. To quantify the marginal costs of electricity service one must answer thequestion: What are the additional costs that would be incurred with changes in kilowatt-hours ofenergy, kilowatts of demand and number of customers? Because some of the cost of additionalconsumption differ depending upon the time of the change in output, it is important to estimatetime-differentiated marginal costs of electricity delivery.Our method for estimating marginal costs is based on the system planning process, and takes intoaccount the wholesale market and transmission access arrangements specific to the environmentwhere the utility operates. We determine the marginal cost of electricity by examining theutility’s planning processes to determine what drives new investment and operating decisionsand how changes in consumption affect utility system operations. The method is not a formula,but a series of guidelines outlining what should be measured and how the measurements can bemade.1 RG&E is using an inflation rate of 1.9% for internal purposes, and this inflation rate is used in the economiccarrying charges described in Section VI.Confidential DraftFor Client Review OnlyPrivileged and Confidential1
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 7 of 55II. COSTING/PRICING PERIODSIn this study we developed hourly marginal cost estimates for the transmission and distributioncomponent costs that vary with time of use—loss-adjusted NYISO transmission charges 2 anddistribution substations and trunkline feeders. The summary tables in Section VIII show thesecost components aggregated by RG&E’s current time-of-use pricing periods, shown in Table 1,which vary by customer classification:Table 1. Costing/Pricing PeriodsNon-Residential TOU (SC 8, 9)Seasons: Summer: June – SeptemberDiurnalPeriods:Winter:Base:Peak:Off-Peak:December – FebruaryMarch – May and October - NovemberMonday - Friday, 7 am to 11, pm local timeAll remaining hoursResidential TOU (SC 4)DiurnalPeriods:Peak:Off-Peak:Monday - Friday, 7 am to 9 pm, local timeAll remaining hours2 As explained in Section III, transmission marginal costs do not vary with time of use within a month, except formarginal losses associated with the various voltage levels at which customers are served.2
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 8 of 55III. MARGINAL TRANSMISSION COSTAs the figure below illustrates, RG&E’s transmission facilities consist of transmission lines ofvarious voltage levels, and transmission substations. Lines of a particular voltage level canfunction either as transmission or distribution. The determination of what is considered atransmission facility is governed by Federal Energy Regulatory Commission rules. Certainfacilities upstream of distribution substations and formerly known as transmission facilities, butnot meeting the FERC definition, are referred to as “upstream distribution facilities” in thisstudy.Figure 1. Simplified Diagram of RG&E’s Delivery SystemTransmissionTransmission SubstationsTransmissionCustomer115 kV Transmission LinesUpstream Substations(including some115/69/46/34 kV)Upstream Distribution Lines (69/46/34 kV)Customer withDedicatedSubstationDedicatedSubstationDist. SubstationTrunkline Feeder Primary(34/12/4 kV)DistributionLineTransformerSecondaryServiceLocalPrimaryLinePrimaryserviceHigher voltage distributioncomponentsSecondaryCustomerSecondaryLinePrimaryCustomerLocal DistributionFacilitiesCustomer-relatedcomponent (service)3
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 9 of 55As a Transmission Owner subject to the rules of the New York Independent System Operator(NYISO), RG&E’s transmission revenue requirement is the basis for the Company’sTransmission Service Charge (TSC). Users of RG&E’s transmission system (implicitly includingRG&E, although no explicit payments are made) are required to pay this charge. If RG&E’sdelivery service customers use more electricity, RG&E is responsible for additional TSCcharges, which constitute RG&E’s marginal transmission cost. Other NYISO charges applicableto RG&E are considered commodity costs and so are not included in this study.A specific forecast of TSC charges is not available. We used as the starting point for RG&E’smarginal transmission costs the most recent 12 months’ charges, which are flat prices per MWhsold or transported. The charges vary only slightly from month to month. The average TSCcharge for the most recent 12 months (August 2008 – July 2009) is $ 3.6756 per MWh. Weapplied factors that account for losses between the transmission tie point and customers’ meters,using estimates of hourly marginal energy losses, which vary with load. 3Table 2 shows the results for 2010 by period and voltage level of service.Table 2. 2010 Time-Differentiated Marginal Transmission CostsSummer Season Winter Season Base SeasonOn-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak------------------------------------------- (2010 Dollars per kWh) ------------------------------------------(1) (1) (2) (1) (1)(1) Marginal Transmission Service Charges $0.00368 $0.00368 $0.00368 $0.00368 $0.00368 $0.00368Residential (SC 4) Marginal Transmission Service Charges by Voltage Level(2) Secondary Service TOD $0.00396 $0.00389 $0.00394 $0.00389 $0.00392 $0.00387(3) Secondary Service Seasonal $0.00392 $0.00391 $0.00389(4) Secondary Service Annual $0.00391Non-Residential (SC 8&9) Marginal Transmission Service Charges by Voltage Level(5) Transmission Service TOD $0.00368 $0.00368 $0.00368 $0.00368 $0.00368 $0.00368(6) Transmission Service Seasonal $0.00368 $0.00368 $0.00368(7) Transmission Service Annual $0.00368(8) Dedicated Substation Service TOD $0.00378 $0.00376 $0.00378 $0.00376 $0.00377 $0.00375(9) Dedicated Substation Service Seasonal $0.00377 $0.00377 $0.00376(10) Dedicated Substation Service Annual $0.00376(11) Primary Service TOD $0.00389 $0.00384 $0.00388 $0.00384 $0.00386 $0.00382(12) Primary Service Seasonal $0.00386 $0.00386 $0.00384(13) Primary Service Annual $0.00385(14) Secondary Service TOD $0.00395 $0.00389 $0.00394 $0.00389 $0.00392 $0.00387(15) Secondary Service Seasonal $0.00392 $0.00391 $0.00389(16) Secondary Service Annual $0.003913 Section V.E discusses the development of the marginal energy loss factors.4
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 10 of 55IV. MARGINAL DISTRIBUTION COSTSConceptually, most costing practitioners agree that the design of the distribution system isdetermined by two major factors: (1) the number and location of customers and (2) theirdemands. Marginal cost studies have traditionally attempted to identify a portion of distributioncosts as customer-related and the remaining portion as demand-related. This has led tosemantics arguments about the definition of the customer-related and demand-relatedcomponents. In fact, for most distribution systems, this two-part segmentation of distributionequipment is not consistent with the cost drivers, because it ignores the fact that there are twotypes of demand that determine distribution capacity requirements for a particular customer –design (or contract) demand and near-term demand at the time of likely neighborhood peaks.Figure 1 above includes a simplified illustration of RG&E’s distribution system. The variousdistribution components are categorized as:• substations and lines upstream from distribution substations, but defined asdistribution (shown as bold lines and boxes);• distribution substations and primary trunkline feeders (shown as bold lines andboxes).• local distribution facilities: consisting of secondary lines, primary-to-secondarytransformers and local primary lines, and substations for customers with dedicatedsubstations (shown as solid boxes);• customer-related service drops (shown as dashed lines).RG&E adds distribution substation capacity and distribution equipment upstream of thesesubstations as load grows, either from connection of new customers or growth by existingcustomers. The trunkline feeders from the substation to the point where the line branches tocreate a local primary line also must be upgraded or rerouted as load grows. Because these moreextensively shared, higher voltage distribution components are expanded as customer loads growin critical hours, their costs are time-differentiated.Local distribution facilities are designed using engineering design standards that take intoconsideration the number of customers and the maximum expected loads (or “design demands”)of customers who will eventually use those facilities, over the life of the facilities. For example,residential customers with electric space heat might have different design demands from thosewithout. In RG&E’s case, however, almost all electric-heat residential customers’ airconditioning loads exceed their heating loads, so their design demands do not differ from thoseof customers without electric space heat. Residential design demands do vary for single-familyhomes and apartments. Local distribution facilities for commercial and industrial customers are5
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 11 of 55generally designed on a case-by-case basis, taking into consideration the expected long-termpeak demand by the customer.Because the marginal cost of local distribution facilities is incurred based on design demand, anddoes not vary with a customer’s actual peak load from hour to hour or month to month, thesecosts are computed as a fixed monthly cost per kW of design (or contract) demand. These costsare marginal when the customer is initially connected to the grid, and again whenever thefacilities have to be replaced because of age. At that point the costs could be avoided if theservice connection was eliminated. 4 These facilities are also marginal when there is a majorincrease in the design demand of the customers using them.The service drop in most cases serves a single customer. The service, along with the meter andassociated equipment such as current transformer (not shown in the diagram), is treated as part ofthe marginal customer cost for each customer classification, and is discussed in Section IV.D.A. Upstream Distribution Equipment and Distribution Substation andTrunkline Feeder CostsTo estimate the marginal cost of typical upstream distribution lines and substations anddistribution substation and trunkline feeder expansion per kW of demand, we typically identifythe cost of budgeted load growth-related projects of this type (excluding any replacementprojects that do not add capacity) and divide by the load growth that is driving the need for theadditional capacity.RG&E was able to provide details about planned expansion of facilities upstream of distributionsubstations for 2009 and distribution substation and trunkline feeder expansion planned for 2008and 2009. To compute marginal investment in upstream stream lines, upstream stations, anddistribution substations and trunkline feeders, we followed a three-step process:1. We divided the sum of the investment (in 2010 dollars) by the additions to nameplatecapacity represented by those projects to obtain a typical investment per kVA of capacity.2. To convert these figures to costs per kW of load, we multiplied the cost per kVA of capacityby one plus the typical reserve margin in RG&E’s substations in 2008. RG&E does not planfor a specific reserve margin in these facilities. However the Company’s planning policydoes result in capacity in excess of peak loads because of factors such as the lumpiness ofcapacity additions. The typical reserve margin was computed by identifying substationswhere additions are likely to be needed in the near term, and determining the median of these4 This might occur, for example, if the customers using the specific local facilities decided to go off-grid, or thehomes or businesses were demolished.6
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 12 of 55stations’ 2008 reserve margins (71 percent) 5 . This process excludes substations that have lostload in recent years or otherwise have higher than typical reserves.3. A final adjustment recognizes that some substations have sufficient capacity to accommodateload growth. Thus, load growth in those areas will not trigger marginal investment. Toconvert the results from Step 2 to marginal investment applicable systemwide, we multipliedby a factor representing the share (53 percent) of 2008 substation peak loads in stations thatare below the typical reserve margin identified in Step 2 above. The computations for each ofthe three components are shown on Table 3.Table 3. Upstream Lines & Substation and Distribution Substation & Trunkline FeederMarginal InvestmentDistribution Substations and Trunkline Feeders(1) Budgeted Investment per kW of Summer Rated Capacity inDistribution Substations and Trunkline Feeders, 2008-2009(2010 Dollars/kW) $97.94(2) Typical Percent Reserve Margin 71%(3) Typical Investment per kW of Load Growth (2010 Dollars/kW)[(1) x (1+(2))] $167.48(4) Share of 2008 peak loads of substations needing capacityadditions to meet typical reserve margin 53%(5)System-wide Marginal Investment in Distribution Substationsand Trunkline Feeders (2010 Dollars per kW)(2010 Dollars per kW) (3) x (4) $88.76Upstream Distribution Lines(6) Budgeted Investment per kW of Summer Rated Capacity inUpstream Distribution Lines, 2008-2009(2010 Dollars/kW) $128.67(7) Typical Investment per kW of Load Growth (2010 Dollars/kW)[(6) x (1+(2))] $220.03(8) System-wide Marginal Investment in Upstream DistributionLines (2010 Dollars per kW) (7) x (4) $116.61Upstream Distribution Stations(9) Budgeted Investment per kW of Summer Rated Capacity inUpstream Distribution Stations, 2008-2009(2010 Dollars/kW) $89.40(10) Typical Investment per kW of Load Growth (2010 Dollars/kW)[(9) x (1+(2))] $152.87(11) System-wide Marginal Investment in Upstream DistributionStations (2010 Dollars per kW) (10) x (4) $81.025 Calculated as summer normal rating divided by 2008 peak load, minus 1.7
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 13 of 551. Upstream Distribution and Distribution Substation Marginal O&MExpensesDistribution O&M expenses depend on the amount of plant in service. The addition ofdistribution plant to meet increments in customers or design load or peak substation load givesrise to increased O&M expenses as well. Distribution O&M expenses are, therefore, marginalcosts. RG&E’s FERC Form 1 filings provide 2004-2008 distribution O&M expenses by FERCaccount. Expenses for individual components (e.g., meters, line, substations, etc.) were allocateda proportional share of the general overhead O&M categories. 6 The trends in recent averagelevels of each category of distribution O&M were the starting point for our estimates of marginalO&M expenses.We divided the 2004-2008 distribution substation O&M expenses, plus associated overheads, byan estimate of the sum of non-coincident peak demands at the upstream substations 7 andconverted to 2010 dollars, as shown on Table 4. After reviewing the trend in expense per kW (inconstant dollars), we used the 2008 value as our estimate of marginal substation O&M expensesper kW of load. However, as the investment analysis discussed above revealed, load growth insome parts of RG&E’s service territory is not likely to require additions to upstream ordistribution substation capacity. Consequently, we applied the same factor used in the third stepabove to the estimates of marginal station O&M to account for this situation. Because theseexpenses cover both distribution stations and upstream stations, we divided the results into twocomponents, based on the estimated peak loads of stations in the two categories. Thesecalculations are shown in Table 4.6 These general accounts consist of Operation Supervision and Engineering and Maintenance Supervision andEngineering, and Miscellaneous Maintenance Expense.7 This estimate was developed by taking the sum of the non-coincident peak demands on distribution substationsand adding the annual peak demands of customers served at subtransmission voltage.8
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 14 of 55Table 4. Upstream Station and Distribution Substation O&M Expense per kWSubstation SubstationExpenses Per Expenses PerTotal Estimated kW of Weighted kW ofDistribution Substation Substation Labor and SubstationSubstation Noncoincident Noncoincident Materials NoncoincidentYear Expenses Peak Loads Peak Loads Cost Index Peak Loads(Thousand Dollars) (MW) (Dollars) (2010=1.00) (2010 Dollars)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 $3,748 1,477 $2.54 0.74 $3.41(2) 2005 $4,205 1,521 2.76 0.78 3.54(3) 2006 $4,292 1,494 2.87 0.83 3.44(4) 2007 $4,574 1,502 3.04 0.89 3.42(5) 2008 $3,915 1,455 2.69 0.95 2.83(6) Estimated Annual Distribution Substation O&M Expensesfor the Planning Period (2008 Level) $2.83(7) Share of 2008 peak loads of substations needing capacityadditions to meet typical reserve margin 53%(8) Adjustment for share of system that will require additional capacity by 2013: (6) x (7) $1.50(9) 2008 Upstream Peak Load as a Percentage of Total Upstream and DistributionSubstation Peak Load (1,051 / 3,060) 34%(10) Upstream Station Share (based on station capacity) (8) x (9) $0.51(11) 2008 Distribution Substation Peak Load as a Percentage of Total Upstreamand Distribution Substation Peak Load (2,009 / 3,060) 66%(12) Distribution Substation Share (based on station capacity) (8) x (11) $0.99(13) Customers with Dedicated Substation (based on station capacity) (6) x (11) 1.862. Upstream Line O&M ExpensesFERC accounts do not distinguish O&M on lines by voltage level. To develop estimates ofO&M on upstream lines, we used the 2004-2008 data for overhead and underground lines andassociated overheads. We used estimates of miles of line to apportion these expenses between (1)upstream lines and (2) primary and secondary lines included in local facilities costs. 8Table 5 shows the development of the resulting O&M estimates. We used the average expensesin 2007-2008 as our estimate of marginal O&M expense, and applied the adjustment described8 We treated all primary lines O&M as a local facilities cost, rather than trying to identify the portion of primary linemiles that is trunkline feeders.9
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 15 of 55for station O&M above to account for the fact that additional upstream line O&M will not beincurred at the margin in areas where reserves are sufficient to accommodate marginal load.Table 5. Upstream Line & Trunkline Feeder O&M Expense per kWUpstream LineUpstream LinesExpense Per Expense PerUpstream kW of Weighted kW ofDistribution Substation Substation Labor and SubstationLines Noncoincident Noncoincident Materials NoncoincidentYear Expenses Peak Loads Peak Load Cost Index Peak Load(Thousand Dollars) (MW) (Dollars) (2010=1.00) (2010 Dollars)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 $826 1,477 $0.56 0.74 $0.75(2) 2005 $1,140 1,521 0.75 0.78 0.96(3) 2006 $993 1,494 0.66 0.83 0.80(4) 2007 $993 1,502 0.66 0.89 0.74(5) 2008 $1,126 1,455 0.77 0.95 0.81(6) Estimated Annual Distribution Lines O&M Expenses(Average of 2007-2008) $0.78(7) Adjustment for share of system that will require additional capacity by 2013 - (6) x 0.53 $0.413. Time-differentiation of Marginal Upstream Distribution and DistributionSubstation and Trunkline Feeder CostsOnly load growth when capacity is strained triggers additions to the higher voltage distributionsystem. We analyzed hourly loads on a sample of representative RG&E distribution substationsfor the years 2004-2008 to identify patterns of loads.We estimated the relative probability of a given hour’s being the substation peak for months,day-types (weekdays, weekends) and hours for each substation, taking into account the highercarrying capability of this equipment in cold temperatures. We then calculated weightedaverages of the sample substation’s relative probabilities of peak for each pricing period, usingas weights the total summer rated capacity of substations similar to the sample substations. Theperiod assignment factors are shown on Table 6.10
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 16 of 55Table 6. Probability of Peak for Upstream Facilities and Distribution Substations &Trunkline FeedersRelative Probability of Substation PeakResidential Periods Non-Residential Periods(1) (2)Summer Season(1) On-Peak 90.9% 90.9%(2) Off-Peak 3.0% 3.0%(3) Subtotal 93.9% 93.9%Winter Season(4) On-Peak 0.0% 0.0%(5) Off-Peak 0.0% 0.0%(6) Subtotal 0.0% 0.0%Base Season(7) On-Peak 4.4% 6.0%(8) Off-Peak 1.7% 0.1%(9) Subtotal 6.1% 6.1%Total 100.0% 100.0%B. Local Distribution Facility Costs1. Local Distribution Facility InvestmentRG&E developed estimates of the typical investment per kW of design demand in services, 9secondary lines, transformers, and local primary lines for various types and sizes of customers,by calculating the replacement cost of this equipment on a sample of circuits. We computedestimates of facilities investment for each service classification by averaging the costs identifiedfor customers in the sample that are in a particular service classification. Local distributionfacilities for customers served from a dedicated substation consist of their substations. RG&Eprovided the per-kVA cost of a typical dedicated substation for these customers.9 Service drop costs are discussed in Section IV D below.11
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 17 of 55Because the marginal cost of local distribution facilities is incurred based on design demand, anddoes not vary with a customer’s actual peak load from month to month, we computed these costsas a monthly cost per kW of design (or contract) demand. We used RG&E’s estimates of thesummer peak demands of these customers as the estimated design demand.The distribution facilities investments for residential and non-residential customer categories areshown on Table 7. No local facilities costs are identified for lighting customers because theirusage does not affect the sizing of distribution facilities. Transmission customers provide theirown local facilities or pay upfront.Table 7. Marginal Distribution Facilities Investment per kW ofDesign DemandAverageInvestmentper kW ofCustomer ClassDesign Demand(2010 Dollars)(1) SC 1 Residential $278.80(2) SC 4 Residential TOU $285.25(3) SC 2 General Service - Small Use $342.91(4) SC 3 General Service - 100 kW Min. $176.75(5) SC 6 Area Lighting na(6) SC 7 General Service - 12 kW Minimum $244.20(7) SC 8 LGS TOU - Secondary $186.37(8) New Dedicated Substation Service $204.84(9) SC 8 LGS TOU - Primary $128.97(10) SC 8 LGS TOU Transmission na(11) SC 9 General Service TOU $325.282. Local Distribution Facility Operation and MaintenanceWe reviewed the 2004-2008 local distribution facilities O&M expenses 10 and divided theexpenses by estimates of total design demand of customers using those facilities. Total designdemand was the product of customer counts and per-customer design demand estimates bycustomer category from the sample circuit analysis. We used the average of the 2007 and 2008values as our estimate of marginal distribution facilities O&M expense, and separated line-10 FERC accounts 583, 584, 593, 594 and 595, plus an allocation of accounts 580, 588, 590 and 598.12
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 18 of 55related expenses into primary and secondary categories on the basis of circuit miles of conductor(with the line transformer portion assigned entirely to secondary), as shown on Table 8.Table 8. Distribution Facilities O&M Expense per kW of Design DemandSecondary Primary Secondary PrimaryPortion Portion Weighted Dist Fac Dist FacDistribution Distribution Labor and Expense ExpenseFacilities Facilities Load on Load on Materials Per kW of Per kW ofYear O&M Expenses O&M Expenses Secondary Primary Cost Index Load Load(000's Dollars) (000's Dollars) (kW) (kW) (2010 = 1.00) (2010 $/kW) (2010 $/kW)[[(1)x1000/(3)]/(5) [[(2)x1000/(4)]/(5)(1) (2) (3) (4) (5) (6)(1) 2004 $2,556 $14,131 2,592,999 2,836,564 0.74 $1.32 $6.69(2) 2005 3,328 19,502 2,576,284 2,824,083 0.78 1.65 8.84(3) 2006 2,513 16,974 2,535,785 2,788,016 0.83 1.19 7.30(4) 2007 2,316 16,984 2,536,685 2,790,110 0.89 1.02 6.83(5) 2008 2,550 19,256 2,582,210 2,839,127 0.95 1.04 7.12(6) Estimated Annual Weighted Primary Distribution Facilities O&M Expense(Average of 2007-2008) $6.97(7) Estimated Annual Weighted Secondary Distribution Facilities O&M Expense(Average of 2007-2008) $8.00C. Lighting CostsThe amount of investment RG&E makes to provide lighting service depends upon the type ofservice offered and the specific equipment required for each installation. Lighting serviceequipment is categorized in three components:• Circuit equipment – This is dedicated equipment comparable to a service drop for a nonlightingcustomer and may include overhead wire, wood poles, underground conductorand conduit, and buried cable.• Fixtures – This equipment includes various types of poles (other than circuit poles),bases, brackets and luminaires.• Lamps – This category consists of the lamps and photo-eyes.RG&E provides and maintains circuit equipment, fixtures and lamps for two types of lightingservice: SC 6 (Area Lighting Service) and SC 1 (Street Lighting Service). SC 2 (Street LightingCustomers) and SC 3 (Traffic Signal Service) customers provide and maintain their ownequipment. The only delivery costs incurred by RG&E for these latter two lighting services arecustomer accounts and customer service costs.RG&E contracts out most of the labor involved in installing and maintaining lighting equipment.The company provided the current material and contractor costs of circuit equipment and fixture13
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 19 of 55installation and maintenance. We computed a loader for RG&E’s direct costs associated withmaintenance of lighting equipment. Although contractors perform most of the labor, RG&E doesincur costs itself to facilitate this maintenance. We computed the direct cost loader by taking theRG&E’s total streetlight maintenance expense for 2008, subtracting material costs andcontractors’ charges, and dividing by the contractors’ charges.Table 9 shows the installed cost and annual maintenance expense for of the various componentsof SC6 – Area Lighting. Table 10 shows the same information for SC1 – Street Lighting Service.Table 11 shows the annual material and labor expense of relamping luminaires of various types.14
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 20 of 55Table 9. SC6 Area Lighting Investment and Annual MaintenanceFixture TypeTotal Installed Costexcluding Lamp and Photo Annual O&M (Excl.EyeRelamping)(2010 $ per Unit)(1) (2)Standard FixtureHigh Pressure SodiumHPS 70 $196.17 $5.26HPS 100 201.65 5.26HPS 150 201.72 5.26HPS 250 197.21 5.26HPS 400 203.52 5.26250/400 duel 304.17 5.26Metal HalideMH 250 197.21 5.26MH 400 197.21 5.26Bracket Length30 inch 147.16 na8 foot 223.40 na12 foot 349.79 na16 foot 530.67 na20 foot 617.18 naFlood FixtureHigh Pressure SodiumHPS 150 0.00 5.26HPS 250 310.77 5.26HPS 400 311.59 5.26HPS 1000 320.00 5.26Metal HalideMH 250 170.01 5.26MH 400 170.84 5.26MH 1000 280.85 5.26BracketBracket- single 90.83 naBracket- twin 37.83 naShoebox FixtureHigh Pressure SodiumHPS 250 0.00 5.26HPS 400 0.00 5.26Bracket Length30 inch 147.16 naAdded FacilitiesAdditional wood pole installed for luminaire 609.36 0.04Wire service (per foot of extension) 1.33 0.0815
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 21 of 55Table 10. SC1 Street Lighting Investment and Annual MaintenanceMarginalAnnualInvestment Marginal O&MPer UnitPer Unit----------------- 2010 Dollars ----------------(1) (2)Fixture TypesType 2d F2d 15' post top, w/ HPS $609.02 $5.26Type 2f F2d 15' post top, w/ MH 544.83 5.26Type 2g Wood pole supporting a MH shoebox luminaire 297.82 5.26Type 9c F9c mast arm WP, w/ HPS 449.67 5.26Type 9d F9d mast arm WP, w/ MH 490.14 5.26Type 10a F10a 20-25' tub steel w/ MH 5,603.68 6.15Type 10a-2 F10a-2 20-25' twin steel w/ MH 5,876.46 6.15Type 10c F10c 20-25' steel, w/ HPS 5,557.49 6.15Type 10c-2 F10c-2 20-25' tub steel, w/ HPS 5,784.07 6.15Type 11a F11a 30-35' Steel w/ MH 5,816.68 6.15Type 11a-2 F11a-2 30-35' Steel w/ MH 6,341.11 6.15Type 11b F11b 30-35' steel, w/ HPS 5,851.18 6.15Type 11b-2 F11b-2 30-35' tub steel, w/ HPS 6,410.10 6.15Type13a F13a mast arm on WP, w/ HPS 590.49 5.26Type13b F13b mast arm on WP, w/ MH 641.00 5.26Type 20b Customer pole & arm supporting HPS shoebox type luminaire 273.88 5.26Type 20g Customer pole & arm supporting HPS luminaire 233.41 5.26Type 20i Customer pole supporting HPS luminaire (250W max.) 372.28 5.26Type 20j Customer pole & arm supporting a MH closed type luminaire 308.09 5.26Type 21a Customer pole with Company arm supporting a HPS luminaire 539.05 5.26Type 21b Customer pole with Co. arm supporting a MH closed type luminaire 558.21 5.26Type C-4a C-4a Flour. Underpass 0.00 0.00Circuit ComponentOverhead Wire $1.63 $0.08Wood Pole Company Owned 532.69 0.04Wood Pole Jointly Owned 266.34 0.04Conduit & Cable 13.18 0.08Buried Cable URD Subdivisions 2.48 0.08Cable in Conduit owned by Others 1.29 0.0816
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 22 of 55Table 11. Annual Relamping ExpenseAnnualMarginalRelampingExpenseLumins Wattage Type per Unit(2010 Dollarsper unit perMonth)1,260 116 Incandescent $14.402,500 166 Incandescent 11.212,800 202 Incandescent 13.104,000 261 Incandescent 12.746,000 366 Incandescent 13.1310,000 621 Incandescent 13.324,000 50 High Pressure Sodium 156.125,800 70 High Pressure Sodium 150.119,500 100 High Pressure Sodium 151.2316,000 150 High Pressure Sodium 152.5527,500 250 High Pressure Sodium 153.9350,000 400 High Pressure Sodium 158.06140,000 1,000 High Pressure Sodium 259.096,950 100 Fluorescent 63.196,950 100 Fluorescent 63.194,000 70 Metal Halide 260.675,850 100 Metal Halide 201.6210,500 175 Metal Halide 156.1217,000 250 Metal Halide 165.8028,800 400 Metal Halide 157.50D. Meter and Service Costs1. Meter and Service InvestmentRG&E provided the installed cost of a typical meter (including current and potential transformer,if applicable) and service drop for each customer class. The analysis of sample circuits used todevelop marginal facilities costs included detailed cost estimates of the services on the circuits,which were used to develop estimates of the installed cost of services for each customerclassification.17
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 23 of 55The typical meter (and associated equipment) and service drop investments, stated in 2010dollars are shown on Table 12. A portion of service costs is sometimes recovered upfront incontributions in aid of construction (CIAC) charges. The marginal service cost estimates areshown two ways—excluding the portion of local facilities costs paid up front, to avoid doublecountingwhen the estimates are used to inform rate design, and including the full cost of theequipment. 11Table 12. Investment per Customer in Meters and ServicesMeter & Total Total Meter &Service Service Service ServiceMeter Investment Investment Investment InvestmentRate Description Investment (after CIAC ) (after CIAC ) (before CIAC ) (before CIAC )-------------------------------------- (2010 $ per Customer) --------------------------------------(1) + (2) (1) + (4)(1) (2) (3) (4) (5)(1) SC 1 Residential $59.03 $1,002.63 $1,061.65 $1,114.15 $1,173.18(2) SC 4 Residential TOU 138.03 1,418.69 1,556.72 1,438.08 1,576.11(3) SC 2 General Service - Small Use 108.83 645.06 753.89 2,454.78 2,563.61(4) SC 3 General Service - 100 kW Min. 2,748.28 0.00 2,748.28 6,613.01 9,361.30(5) SC 6 Area Lighting na na na na na(6) SC 7 General Service - 12 kW Minimum 416.02 0.00 416.02 2,607.24 3,023.26(7) SC 8 LGS TOU - Secondary 1,362.94 0.00 1,362.94 8,456.93 9,819.87(8) New Dedicated Substation Service 1,465.53 0.00 1,465.53 na 1,465.53(9) SC 8 LGS TOU - Primary 3,522.41 2,382.11 5,904.52 14,546.81 18,069.23(10) SC 8 LGS TOU Transmission 58,586.18 0.00 58,586.18 na 58,586.18(11) SC 9 General Service TOU 952.57 0.00 952.57 4,879.96 5,832.53Note:Service cost of Dedicated Substation and Transmission level customers is customer-specific.11 Customers with dedicated substations and transmission-level customers pay for their entire service through CIAC,no service costs are shown for them in the “before CIAC” column because these costs are customer-specific.18
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 24 of 552. Meter and Service Operation and Maintenance ExpensesWe analyzed meter O&M expenses 12 over the past five years. The meter O&M per weightedcustomer (using relative meter cost as weights) declined significantly in recent years. We usedthe 2008 value as the estimate of the marginal level of these expenses, as shown on Table 13.Table 14 multiplies the result by the class weights to yield annual meter O&M by class.Table 13. Meter O&M Expense per Weighted CustomerTotal Meter MeterMeter Average Weighted Expense Weighted ExpenseOperation & Number of Average Per Labor and PerMaintenance Metered Number of Weighted Materials WeightedYear Expenses Customers Customers Customer Cost Index Customer(000's Dollars) (Dollars) (2010 = 1.00) (2010 Dollars)(2) x 1.51 [(1) x 1000]/(3) (4)/(5)(1) (2) (3) (4) (5) (6)(1) 2004 $6,202.53 355,924 537,445 $11.54 0.74 $15.50(2) 2005 8,898.63 356,694 538,608 16.52 0.78 21.15(3) 2006 7,237.89 356,176 537,826 13.46 0.83 16.13(4) 2007 4,251.72 357,853 540,358 7.87 0.89 8.83(5) 2008 4,181.15 358,817 541,814 7.72 0.95 8.10(6) Estimated Annual Weighted Meter O&M Expense (2010 Dollars)(2008 value) $8.1012 FERC accounts 586 and 597, plus associated overheads.19
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 25 of 55Table 14. Meter O&M Expense by Service ClassificationAnnualWeighting Meter ExpenseRate Class Factor Per Customer(2010 Dollars)(1) x $8.10(1) (2)(1) SC 1 Residential 1.00 $8.10(2) SC 4 Residential TOU 2.34 18.96(3) SC 2 General Service - Small Use 1.84 14.91(4) SC 3 General Service - 100 kW Min. 46.56 377.18(5) SC 6 Area Lighting na 0.00(6) SC 7 General Service - 12 kW Minimum 7.05 57.11(7) SC 8 LGS TOU - Secondary 23.09 187.05(8) New Dedicated Substation Service 24.83 201.15(9) SC 8 LGS TOU - Primary 59.68 483.46(10) SC 8 LGS TOU Transmission 992.56 8,040.67(11) SC 9 General Service TOU 16.14 130.7520
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 26 of 55V. OTHER MARGINAL COSTSA. Customer Accounts ExpensesCustomer accounts expenses, composed mainly of meter-reading and billing expenses anduncollectibles, 13 are costs that are the function of a number of customers on the system. Weanalyzed the level of customer accounts expenses 14 other than uncollectibles for the last fiveyears and determined, in consultation with RG&E, that the 2008 expenses are a reasonableproxy for the marginal cost in future years. We used the results from the 2008 embedded study toidentify the cost per customer for each class.In the case of uncollectibles, which had a two-fold increase from 2007 to 2008, we adjusted theannual cost per customer from the embedded study by the ratio of the two-year average to the2008 level to reduce the effect of the recession. Table 15 shows the calculation of thisuncollectibles ratio and Table 16 shows the estimated marginal costs by service classification.Table 15. Adjustment Factor for UncollectiblesYearUncollectibles2007 $6,852,7632008 $10,668,839Average $8,760,801Ratio Average to 2008 82.12%13 We dealt with uncollectibles separately because this component of customer accounts expense is not subject to thecash working capital adjustment, discussed later.14 FERC accounts 901-905, excluding portions of uncollectibles and credit and collection costs that are associatedwith the merchant function.21
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 27 of 55Table 16. Customer Accounts and Uncollectibles Expense by Service ClassificationCustomer CustomerAccounts Accounts EstimatedExpense (excl. Expense (excl. 2008 Marginaluncollectibles) Uncollectibles uncollectibles) Uncollectibles UncollectiblesRate Class per Customer per Customer per Customer per Customer per Customer(2008 Dollars) (2008 Dollars) (2010 Dollars) (2010 Dollars) (2010 Dollars)(1) / 0.9426 (2) / 0.9426 (4) x 0.8212(1) (2) (3) (4) (5)(1) SC 1 Residential $21.27 $7.66 $22.56 $8.13 $6.67(2) SC 4 Residential TOU 34.23 17.46 36.32 18.52 15.21(3) SC 2 General Service - Small Use 19.89 0.68 21.10 0.72 0.59(4) SC 3 General Service - 100 kW Min. 123.40 35.18 130.92 37.32 30.64(5) SC 6 Area Lighting 10.90 0.54 11.56 0.57 0.47(6) SC 7 General Service - 12 kW Minimum 42.56 7.45 45.16 7.90 6.49(7) SC 8 LGS TOU - Secondary 300.74 97.03 319.06 102.94 84.53(8) New Dedicated Substation Service 333.96 109.70 354.29 116.38 95.56(9) SC 8 LGS TOU - Primary 462.28 154.26 490.43 163.65 134.39(10) SC 8 LGS TOU Transmission 821.30 281.55 871.31 298.69 245.27(11) SC 9 General Service TOU 54.85 11.39 58.19 12.08 9.92(12) SL 1 Street Lighting Service 56.41 16.22 59.85 17.21 14.13(13) SL 2Street Lighting Customer-OwnedEquipment56.41 16.22 59.85 17.21 14.13(14) SL 3 Traffic Signal 56.41 16.22 59.85 17.21 14.13B. Customer Service and Informational ExpensesCustomer service and informational expenses, 15 which include the costs of disseminatinginformation to consumers, typically vary with the number of customers on the system and are,therefore, marginal.In consultation with RG&E we used the 2008 embedded cost values per customer for eachclassification as our estimate of marginal customer service and informational expenses. Table 17shows the expense by service classification.15 FERC Accounts 908, 909 and 910.22
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 28 of 55Table 17. Customer Services and Informational Expenses by Service ClassificationAnnual Customer Annual CustomerService and Service andInformational InformationalExpense ExpenseRate Class Per Customer Per Customer(2008 Dollars) (2010 Dollars)(1) / 0.9426(1) (2)(1) SC 1 Residential $0.39 $0.41(2) SC 4 Residential TOU 0.89 0.94(3) SC 2 General Service - Small Use 0.29 0.31(4) SC 3 General Service - 100 kW Min. 14.89 15.80(5) SC 6 Area Lighting 0.24 0.25(6) SC 7 General Service - 12 kW Minimum 3.16 3.35(7) SC 8 LGS TOU - Secondary 40.99 43.49(8) New Dedicated Substation Service 47.64 50.54(9) SC 8 LGS TOU - Primary 65.94 69.95(10) SC 8 LGS TOU Transmission 122.21 129.65(11) SC 9 General Service TOU 4.87 5.16(12) SL 1 Street Lighting Service 7.24 7.68(13) SL 2Street Lighting Customer-OwnedEquipment7.24 7.68(14) SL 3 Traffic Signal 7.24 7.6823
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 29 of 55C. Administrative and General ExpensesWhen a utility adds plant and incurs additional O&M expenses, it typically incurs additionaloverhead costs as well. Certain administrative and general (A&G) expenses can grow eitherwith plant or with O&M expenses. General plant typically grows with other types of plant. Ourmarginal cost study includes plant-related A&G, non-plant-related A&G and general plantloaders to capture these elements of marginal cost.Based on our understanding of RG&E’s classification of costs in the various FERC accounts foradministrative and general (A&G) expenses we identified A&G accounts as potentially marginalwith respect to O&M. We then used regression analyses on 24 years of historical data (1985-2008) in an attempt to estimate the marginal level of non-plant-related A&G expense. However,the regression analysis did not yield meaningful results. Consequently, because social securityand unemployment benefits clearly grow with O&M, we used as the non-plant-related A&Gloader the 2008 ratio of social security and unemployment benefits to total O&M (less fuel,purchased power and transmission by others).The regression analysis of A&G accounts likely to be marginal with respect to plant oncumulative additions to plant also did not yield meaningful results. Consequently, we treatedproperty insurance as the only element of plant-related A&G. RG&E provided the expected 2009insurance premium per dollar of investment. RG&E’s property insurance covers distributionsubstations, but not lines or other distribution facilities. So the plant-related A&G loader is usedonly in the calculations of substation marginal costs. Both A&G loaders are shown on Table 18below.D. General PlantGeneral plant consists of items such as office buildings, warehouses, cars, trucks and otherequipment. The need for general plant typically increases with each marginal increase inproduction, transmission and distribution plant.We used regression analysis on 17 years of historical company data (1992-2008) to estimate amarginal general plant loader applicable to distribution plant. We regressed cumulativeadditions to general plant net of retirements (plus the electric portion of common plant) oncumulative additions to total plant net of retirements (less general plant and the electric share ofcommon plant), all stated in 2008 dollars. The coefficient of explanatory variable, shown onTable 18, is the loader.24
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 30 of 55Table 18. Administrative and General and General Plant LoadersEstimate ofLoadingFactor(1) Non-Plant Related A&G Loader 1.96%(2) Plant Related A&G Loader 0.04%(3) General Plant & Electric Share of Common Plant Loader 33.40%E. Marginal LossesThe marginal cost study develops costs stated on a per-kW or per-kWh basis at a particularcomponent of the system. For use in ratemaking, these costs must be adjusted to costs at themeter of customers served at the various voltage levels of service.The marginal loss calculations in this study are based on estimates of variable and total losses attime of system peak at each voltage level for which costs are calculated. Marginal capacitylosses, applied to upstream distribution components and to distribution substation and trunklinefeeder costs, reflect the fact that to accommodate a kW of additional peak load at the customer’smeter, facilities must be expanded by successively more than a kW as you move up thedistribution system to accommodate the fixed and variable losses on the system in the peak hour.Peak capacity loss factors were developed from RG&E’s most recent detailed loss study.Marginal energy losses reflect the additional losses incurred to move an added kWh through thesystem at a particular level of system load. Fixed losses are, by definition, not affected by theincrements of load to a fixed system. Only variable losses come into these calculations. Marginalenergy losses increase in proportion to the square of the load. We calculated hourly losses bymeans of an approximation of quadratic losses based on variable losses at system peak load(from RG&E’s most recent detailed loss study) and 2008 hourly system loads. These marginalenergy losses were applied to the marginal transmission costs, which are incurred on a per-kWhbasis.25
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 31 of 55VI. COMPUTATION OF ECONOMIC CARRYING CHARGESSection V. above describes the development of estimates of marginal investment in severalcategories of distribution plant. To be useful in ratemaking and other marginal cost applications,the investment must be converted into annual costs using an economic carrying charge. Theannual charge reflects the elements of RG&E’s revenue requirement associated with incrementalplant: return to stockholders and bondholders, depreciation, and taxes. For use in a marginal coststudy, the appropriate stream of annual charges is a stream that rises at the rate of inflation net oftechnical progress and yields the total present value of all costs over the life of the investment.In such a stream, the first year's charge represents the cost in today's dollars of owning the plantor equipment for a year. It also represents the rental rate for such an investment in a competitivemarket.Key inputs for the economic carrying charge calculation include: (1) the utility’s incrementalcost of capital (mix of debt and equity and their respective long-term market costs), (2) theexpected inflation rate for that type of plant, net of technical progress, and (3) the average servicelife and patterns of failure (“Iowa curve”) for that type of plant.RG&E foresees financing of near-term incremental investment through additional equity(retained earnings and/or infusion of equity capital from the parent company) and long-term debtwith the capital structure and costs shown in Table 19.Table 19. Incremental Capital Structure and CostShare % Cost %(%) (%)Debt 51.88 7.00Common Stock 48.12 11.43Another integral part of the economic carrying charge calculation is the estimation of the rate ofinflation net of technical progress applicable over the life of the investment. We used 1.9 percentas an approximation of the rate of future inflation net of technical progress, based on RG&E’srecommendation.Finally, an adjustment is required for the fact that not all plant and equipment will last itsestimated service life. Some components will require early replacement, causing added costs,while some will last longer than expected and produce savings. The pattern of expected requiredreplacement for each type of plant is defined by an Iowa Curve. An adjustment for this dispersedpattern of replacements using Iowa Curves was included in the derivation of the economic26
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 32 of 55carrying charges. The results of these economic carrying charge calculations are presentedbelow. The adjustments for dispersed retirements are shown on line (2) of this table.Table 20. Economic Carrying ChargesUpstreamDistribution Distribution Distribution Meters & StreetLines Facilities Subtations Services Lights(1) (2) (3) (4) (5)(1) Present Value of Revenue RequirementsRelated to Incremental $1,000 Investment $1,804.63 $1,811.23 $1,839.87 $1,792.14 $1,696.14(2) Present Value Cost of ReplacingDispersed Retirements Related toIncremental $1,000 Investment $126.87 $122.79 $80.41 $97.44 $152.13(3) Total Present Value Cost Related toIncremental $1,000 Investment (1)+(2) $1,931.49 $1,934.02 $1,920.28 $1,889.58 $1,848.27(4) First-Year Annual Economic ChargeRelated to Incremental $1,000 Investment ^1 $118.56 $117.98 $114.88 $121.29 $137.57(5) First-Year Annual Economic Charge Related toIncremental Investment [(4)/$1,000] 11.86% 11.80% 11.49% 12.13% 13.76%27
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 33 of 55VII. COMPUTATION OF ANNUAL MARGINAL COSTSTo compute marginal investment for each distribution component of service to annual marginalcosts, we adjusted upwards the investment per unit by the general plant loading factor. Wemultiplied the resulting figures by the annual economic carrying charge percentage plus theplant-related A&G loading factor to yield the annualized plant costs. To these costs we addedthe associated O&M and A&G expenses and the revenue requirements for working capital.The computation of working capital includes components for cash, materials, supplies andprepayments. The working capital needs were estimated based on recent historical amounts. Therevenue requirement for this working capital was developed from RG&E’s weighted averagecost of capital plus an income tax component that recognizes that the equity portion of return oncapital is taxable.Table 21 shows the derivation of the annual upstream distribution costs and distributionsubstation and trunkline feeder costs.28
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 34 of 55Table 21. Derivation of Annual Distribution Substation and Trunkline Feeder, UpstreamLine and Upstream Station CostsDistributionSubstations andTrunklineFeedersUpstreamDistributionSubstationsUpstreamDistributionLines------------------ (2010 Dollars per kW) -------------------(1) Marginal Investment per kW $88.76 $81.02 $116.61(2) With General Plant Loading (1) x 1.3340 118.41 108.08 155.56(3) Annual Economic Carrying Charge Related toCapital Investment 11.49% 11.49% 11.86%(4) A&G Loading (plant related) 0.04% 0.04% 0.00(5) Total Annual Carrying Charge (3) + (4) 11.53% 11.53% 11.86%(6) Annualized Costs (2) x (5) $13.65 $12.46 $18.44(7) O&M Expenses 0.99 0.51 0.41(8) With A&G Loading (7) x 1.0196 (Non-plant Related) 1.01 0.52 0.42(9) Subtotal (6) + (8) $14.66 $12.98 $18.87Working Capital(10) Material and Supplies (2) x 0.13% 0.15 0.14 0.20(11) Prepayments (2) x 0.80% 0.95 0.86 1.24(12) Cash Working Capital Allowance (8) x 12.50% 0.13 0.06 0.05(13) Total Working Capital (10) + (11) + (12) $1.23 $1.07 $1.50(14) Revenue Requirement for WorkingCapital (13) x 13.22% $0.16 $0.14 $0.20(15) Total Annual Cost (9) + (14) $14.82 $13.12 $19.06Tables 22 below show the development of the annual marginal cost for local distributionfacilities.29
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 35 of 55Table 22A. Derivation of Annual Distribution Facilities CostsSC 1 SC 4 SC2 SC 3 SC 6 SC 7GeneralServiceSmall UseGeneralService 100kW Min.GeneralService 12kW Min.ResidentialResidentialTOUAreaLighting----------------------------- (2010 Dollars per kW of Design Demand) -----------------------------(1) (2) (3) (4) (5) (6)(1) Marginal Investment per kW of Design Demand $278.80 $285.25 $342.91 $176.75 na $244.20(2) With General Plant Loading (1) x 1.3341 371.92 380.53 457.44 235.79 325.76(3) Annual Economic Carrying Charge Related toCapital Investment 11.80% 11.80% 11.80% 11.80% 11.80%(4) A&G Loading (plant-related) 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total Annual Carrying Charge (3) + (4) 11.80% 11.80% 11.80% 11.80% 11.80%(6) Annualized Costs (2) x (5) $43.88 $44.90 $53.97 $27.82 $38.43(7) Annual O&M Expense per kW of Design Demand 8.00 8.00 8.00 8.00 8.00(8) With A&G Loading (7) x 1.0196(non-plant related) 8.16 8.16 8.16 8.16 8.16(9) Distribution Facilities Related Costs (6) + (8) $52.04 $53.05 $62.13 $35.98 $46.59Working Capital(10) Material and Supplies (2) x 0.13% 0.48 0.49 0.59 0.31 0.42(11) Prepayments (2) x 0.80% 2.98 3.04 3.66 1.89 2.61(12) Cash Working Capital Allowance (8) x 12.50% 1.02 1.02 1.02 1.02 1.02(13) Total Working Capital (10) + (11) + (12) $4.48 $4.56 $5.27 $3.21 $4.05(14) Revenue Requirement for WorkingCapital (13) x 13.22% $0.59 $0.60 $0.70 $0.42 $0.54(15) Total Annual Marginal DistributionFacilities Related Costs (9) + (14) $52.63 $53.65 $62.82 $36.40 $47.13Table 22B. Derivation of Annual Distribution Facilities CostsSC 8 New SC 8 SC 8 SC 9LGS TOUSecondaryDedicatedSubstationServiceLGS TOUPrimaryLGS TOUTransmissionGeneral ServiceTOU------------------------------ (2010 Dollars per kW of Design Demand) ------------------------------(1) (2) (3) (6) (7)(1) Marginal Investment per kW of Design Demand $186.37 $204.84 $128.97 na $325.28(2) With General Plant Loading (1) x 1.3341 248.62 273.26 172.04 433.92(3) Annual Economic Carrying Charge Related toCapital Investment 11.80% 11.49% 11.80% 11.80%(4) A&G Loading (plant-related) 0.00% 0.04% 0.00% 0.00%(5) Total Annual Carrying Charge (3) + (4) 11.80% 11.53% 11.80% 11.80%(6) Annualized Costs (2) x (5) $29.33 $31.50 $20.30 $51.20(7) Annual O&M Expense per kW of Design Demand 8.00 1.86 6.97 8.00(8) With A&G Loading (7) x 1.0196(non-plant related) 8.16 1.90 7.11 8.16(9) Distribution Facilities Related Costs (6) + (8) $37.49 $33.40 $27.40 $59.35Working Capital(10) Material and Supplies (2) x 0.13% 0.32 0.36 0.22 0.56(11) Prepayments (2) x 0.80% 1.99 2.19 1.38 3.47(12) Cash Working Capital Allowance (8) x 12.50% 1.02 0.24 0.89 1.02(13) Total Working Capital (10) + (11) + (12) $3.33 $2.78 $2.49 $5.06(14) Revenue Requirement for WorkingCapital (13) x 13.22% $0.44 $0.37 $0.33 $0.67(15) Total Annual Marginal DistributionFacilities Related Costs (9) + (14) $37.93 $33.77 $27.73 $60.0230
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 36 of 55Tables 23 show the annualization meters and service drops and also include customer-relatedexpenses. Two sets of costs are shown for each service classification (except the lightingclasses). The first shows annual costs after customer contributions and the second includes thefull cost (before customer contributions)..Table 23A. Derivation of Annual Meter, Service and Customer-Related Costs – AfterCustomer ContributionsSC 1 SC 4 SC2 SC 3 SC 6 SC 7GeneralServiceSmall UseGeneralService 100kW Min.GeneralService 12kW Min.ResidentialResidentialTOUAreaLighting------------------------------------- (2010 Dollars per Customer) -------------------------------------(1) (2) (3) (4) (5) (6)(1) Meter and Service Investment $1,061.65 $1,556.72 $753.89 $2,748.28 na $416.02(2) With General Plant Loading (1) x 1.3341 * 1,453.50 2,083.14 1,610.13 5,874.95 0.00 1,425.79(3) Annual Economic Charge Related toCapital Investment 12.13% 12.13% 12.13% 12.13% 12.13% 12.13%(4) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total (3) + (4) 12.13% 12.13% 12.13% 12.13% 12.13% 12.13%(6) Annualized Costs (2) x (5) $176.29 $252.65 $195.29 $712.54 $0.00 $172.93(7) Meter O&M Expenses 8.10 18.96 14.91 377.18 0.00 57.11(8) Customer Accounts Expenses excl. Uncollectibles 22.56 36.32 21.10 130.92 11.56 45.16(9) Uncollectibles 6.67 15.21 0.59 30.64 0.47 6.49(10) Customer Service and Informational Expenses 0.41 0.94 0.31 15.80 0.25 3.35(11) A&G Loading [(7)+(8)+(10)] x 0.0196(Non-plant Related) 0.61 1.10 0.71 10.26 0.23 2.07(12) Customer-Related Costs (6)+(7)+(8)+(9)+(10)+(11) $214.64 $325.18 $232.90 $1,277.34 $12.51 $287.10Working Capital(13) Materials and Supplies (2) x 0.13% * 2.03 2.73 4.45 16.23 0.00 5.24(14) Prepayments (2) x 0.8% * 12.52 16.82 27.36 99.90 0.00 32.26(15) Cash Working Capital (7)+(8)+(10)+(11) x 12.50% 3.96 7.16 4.63 66.77 1.51 13.46(16) Revenue Requirement for Working Capital[(13)+(14)+(15)] x 13.22% $2.45 $3.53 $4.82 $24.18 $0.20 $6.74(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $217.09 $328.71 $237.72 $1,301.52 $12.71 $293.84Note:Rows with asterisks are calculated using total investment from next table.31
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 37 of 55Table 23B. Derivation of Annual Meter, Service and Customer-Related Costs – Full CostBefore Customer ContributionsSC 1 SC 4 SC2 SC 3 SC 6 SC 7GeneralServiceSmall UseGeneralService 100kW Min.GeneralService 12kW Min.ResidentialResidentialTOUAreaLighting------------------------------------- (2010 Dollars per Customer) -------------------------------------(1) (2) (3) (4) (5) (6)(1) Meter and Service Investment $1,173.18 $1,576.11 $2,563.61 $9,361.30 na $3,023.26(2) With General Plant Loading (1) x 1.3341 1,565.02 2,102.53 3,419.86 12,487.97 0.00 4,033.03(3) Annual Economic Charge Related toCapital Investment 12.13% 12.13% 12.13% 12.13% 12.13% 12.13%(4) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total (3) + (4) 12.13% 12.13% 12.13% 12.13% 12.13% 12.13%(6) Annualized Costs (2) x (5) $189.81 $255.01 $414.78 $1,514.60 $0.00 $489.15(7) Meter O&M Expenses 8.10 18.96 14.91 377.18 0.00 57.11(8) Customer Accounts Expenses excl. Uncollectibles 22.56 36.32 21.10 130.92 11.56 7.45(9) Uncollectibles 6.67 15.21 0.59 30.64 0.47 6.49(10) Customer Service and Informational Expenses 0.41 0.94 0.31 15.80 0.25 3.35(11) A&G Loading [(7)+(8)+(10)] x 0.0196(Non-plant Related) 0.61 1.10 0.71 10.26 0.23 1.33(12) Customer-Related Costs (6)+(7)+(8)+(9)+(10)+(11) $228.17 $327.53 $452.39 $2,079.40 $12.51 $564.88Working Capital(13) Materials and Supplies (2) x 0.13% 2.03 2.73 4.45 16.23 0.00 5.24(14) Prepayments (2) x 0.80% 12.52 16.82 27.36 99.90 0.00 32.26(15) Cash Working Capital (7)+(8)+(10)+(11) x 12.50% 3.96 7.16 4.63 66.77 1.51 8.65(16) Revenue Requirement for Working Capital[(13)+(14)+(15)] x 13.22% $2.45 $3.53 $4.82 $24.18 $0.20 $6.10(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $230.62 $331.07 $457.21 $2,103.58 $12.71 $570.9832
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 38 of 55Table 23C. Derivation of Annual Meter, Service and Customer-Related Costs – AfterCustomer ContributionsSC 8 New SC 8 SC 8 SC 9LGS TOUSecondaryDedicatedSubstationServiceLGS TOUPrimaryLGS TOUTransmissionGeneral ServiceTOU--------------------------------- (2010 Dollars per Customer) ---------------------------------(1) (2) (3) (4) (5)(1) Meter and Service Investment $1,362.94 $1,465.53 $5,904.52 $58,586.18 $952.57(2) With General Plant Loading (1) x 1.3340 * 4,642.77 1,955.01 11,939.64 78,153.97 2,900.64(3) Annual Economic Charge Related toCapital Investment 12.13% 12.13% 12.13% 12.13% 12.13%(4) A&G Loading (Plant Related) 0.00% 0.04% 0.00% 0.00% 0.00%(5) Total (3) + (4) 12.13% 12.17% 12.13% 12.13% 12.13%(6) Annualized Costs (2) x (5) $563.10 $237.91 $1,448.10 $9,478.91 $351.80(7) Meter O&M Expenses 187.05 201.15 483.46 8,040.67 130.75(8) Customer Accounts Expenses excl. Uncollectibles 319.06 354.29 490.43 871.31 58.19(9) Uncollectibles 84.53 95.56 134.39 245.27 9.92(10) Customer Service and Informational Expenses 43.49 50.54 69.95 129.65 5.16(11) A&G Loading [(7)+(8)+(10)] x 0.0196(Non-plant Related) 10.76 11.86 20.43 176.99 3.80(12) Customer-Related Costs (6)+(7)+(8)+(9)+(10)+(11) $1,207.98 $951.32 $2,646.76 $18,942.82 $559.63Working Capital(13) Materials and Supplies (2) x 0.13% * 17.03 2.54 31.34 101.60 10.11(14) Prepayments (2) x 0.80% * 104.80 15.64 192.83 625.23 62.24(15) Cash Working Capital (7)+(8)+(10)+(11) x 12.50% 70.04 77.23 133.03 1,152.33 24.74(16) Revenue Requirement for Working Capital[(13)+(14)+(15)] x 13.22% $25.37 $12.61 $47.22 $248.43 $12.84(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $1,233.35 $963.93 $2,693.98 $19,191.24 $572.46Notes: Rows with asterisks are calculated using total investment from next table.Service cost of Dedicated Substation and Transmission level customers is customer-specific.33
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 39 of 55Table 23D. Derivation of Annual Meter, Service and Customer-Related Costs – Full CostBefore Customer Contributions` SC 8 New SC 8 SC 8 SC 9LGS TOUSecondaryDedicatedSubstationServiceLGS TOUPrimaryLGS TOUTransmissionGeneralService TOU----------------------------------- (2010 Dollars per Customer) -----------------------------------(1) (2) (3) (4) (5)(1) Meter and Service Investment $9,819.87 $1,465.53 $18,069.23 $58,586.18 $5,832.53(2) With General Plant Loading (1) x 1.3340 13,099.71 1,955.01 24,104.35 78,153.97 7,780.60(3) Annual Economic Charge Related toCapital Investment 12.13% 12.13% 12.13% 12.13% 12.13%(4) A&G Loading (Plant Related) 0.00% 0.04% 0.00% 0.00% 0.00%(5) Total (3) + (4) 12.13% 12.17% 12.13% 12.13% 12.13%(6) Annualized Costs (2) x (5) $1,588.80 $237.91 $2,923.50 $9,478.91 $943.67(7) Meter O&M Expenses 187.05 201.15 483.46 8,040.67 130.75(8) Customer Accounts Expenses excl. Uncollectibles 319.06 354.29 490.43 871.31 58.19(9) Uncollectibles 84.53 95.56 134.39 245.27 9.92(10) Customer Service and Informational Expenses 43.49 50.54 69.95 129.65 5.16(11) A&G Loading [(7)+(8)+(10)] x 0.0196(Non-plant Related) 10.76 11.86 20.43 176.99 3.80(12) Customer-Related Costs (6)+(7)+(8)+(9)+(10)+(11) $2,233.68 $951.32 $4,122.16 $18,942.82 $1,151.49Working Capital(13) Materials and Supplies (2) x 0.13% 17.03 2.54 31.34 101.60 10.11(14) Prepayments (2) x 0.80% 104.80 15.64 192.83 625.23 62.24(15) Cash Working Capital (7)+(8)+(10)+(11) x 12.50% 70.04 77.23 133.03 1,152.33 24.74(16) Revenue Requirement for Working Capital[(13)+(14)+(15)] x 13.22% $25.37 $12.61 $47.22 $248.43 $12.84(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $2,259.05 $963.93 $4,169.38 $19,191.24 $1,164.33Note: Service cost of Dedicated Substation and Transmission level customers is customer-specific.34
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 40 of 55Table 23E. Derivation of Annual Meter, Service and Customer-Related CostsSL 1 SL 2 SL 3Street LightingServiceStreet LightingService Customer-Owned Equipment Traffic Signals--------------------- (2010 Dollars per Customer) ---------------------(1) (2) (2)(1) Meter and Service Investment $0.00 $0.00 $0.00(2) With General Plant Loading (1) x 1.3340 0.00 0.00 0.00(3) Annual Economic Charge Related toCapital Investment 13.76% 13.76% 13.76%(4) A&G Loading (Plant Related) 0.00% 0.00% 0.00%(5) Total (3) + (4) 13.76% 13.76% 13.76%(6) Annualized Costs (2) x (5) 0.00 0.00 0.00(7) Meter O&M Expenses 0.00 0.00 0.00(8) Customer Accounts Expenses excl. Uncollectibles 59.85 59.85 59.85(9) Uncollectibles 14.13 14.13 14.13(10) Customer Service and Informational Expenses 7.68 7.68 7.68(11) A&G Loading [(7)+(8)+(10)] x 0.0196(Non-plant Related) 1.32 1.32 1.32(12) Customer-Related Costs (6)+(7)+(8)+(9)+(10)+(11) $82.98 $82.98 $82.98Working Capital(13) Materials and Supplies (2) x 0.13% 0.00 0.00 0.00(14) Prepayments (2) x 0.800% 0.00 0.00 0.00(15) Cash Working Capital (7)+(8)+(10)+(11) x 12.50% 8.61 8.61 8.61(16) Revenue Requirement for Working Capital[(13)+(14)+(15)] x 13.22% $1.14 $1.14 $1.14(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $84.12 $84.12 $84.12Tables 24 and 25 show the annualization of lighting costs for Area Lighting Service andStandard Street Lighting Service components.35
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 41 of 55Table 24. Derivation of Annual Area Lighting CostsInvestment perUnitWithGeneralPlantLoadingAnnualEconomicCarryingChargeAnnualizedCost(1) x1.3340 0.14 (2) x (3)O&MWith A&GLoading (Nonplant)SubtotalMaterials &Supplies &Prepayments(5) x[1+(0.31 x0.0196)] (4)+(6) (2) x 0.0093CashWorkingCapitalRevenueRequirement forWorking CapitalTotalAnnual Costper Unit(6) x0.1250 [(8)+(9)] x 0.1322 (7)+(10)---------------------------------------------------------------------------------------------- (2010 Dollars per Unit) ----------------------------------------------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)Standard FixtureHigh Pressure SodiumHPS 70 $196.17 261.68 13.76% $36.00 $5.26 $5.29 $41.29 $2.43 $0.66 $0.41 $41.70HPS 100 $201.65 269.00 13.76% $37.01 $5.26 $5.29 $42.30 $2.50 $0.66 $0.42 $42.72HPS 150 $201.72 269.09 13.76% $37.02 $5.26 $5.29 $42.31 $2.50 $0.66 $0.42 $42.73HPS 250 $197.21 263.07 13.76% $36.19 $5.26 $5.29 $41.48 $2.45 $0.66 $0.41 $41.89HPS 400 $203.52 271.50 13.76% $37.35 $5.26 $5.29 $42.64 $2.52 $0.66 $0.42 $43.06250/400 duel $304.17 405.76 13.76% $55.82 $5.26 $5.29 $61.11 $3.77 $0.66 $0.59 $61.70Metal HalideMH 250 $197.21 263.07 13.76% $36.19 $5.26 $5.29 $41.48 $2.45 $0.66 $0.41 $41.89MH 400 $197.21 263.07 13.76% $36.19 $5.26 $5.29 $41.48 $2.45 $0.66 $0.41 $41.89Bracket Length30 inch $147.16 196.31 13.76% 27.01 na $0.00 $27.01 $1.83 $0.00 $0.24 $27.258 foot $223.40 298.01 13.76% 41.00 na $0.00 $41.00 $2.77 $0.00 $0.37 $41.3612 foot $349.79 466.62 13.76% 64.19 na $0.00 $64.19 $4.34 $0.00 $0.57 $64.7716 foot $530.67 707.91 13.76% 97.39 na $0.00 $97.39 $6.58 $0.00 $0.87 $98.2620 foot $617.18 823.32 13.76% 113.27 na $0.00 $113.27 $7.66 $0.00 $1.01 $114.28Flood FixutreHigh PressureSodiumHPS 150 $0.00 0.00 13.76% $0.00 $5.26 $5.29 $5.29 $0.00 $0.66 $0.09 $5.38HPS 250 $310.77 414.57 13.76% $57.03 $5.26 $5.29 $62.32 $3.86 $0.66 $0.60 $62.92HPS 400 $311.59 415.67 13.76% $57.18 $5.26 $5.29 $62.48 $3.87 $0.66 $0.60 $63.07HPS 1000 $320.00 426.88 13.76% $58.73 $5.26 $5.29 $64.02 $3.97 $0.66 $0.61 $64.63Metal HalideMH 250 $170.01 226.80 13.76% $31.20 $5.26 $5.29 $36.49 $2.11 $0.66 $0.37 $36.86MH 400 $170.84 227.90 13.76% $31.35 $5.26 $5.29 $36.64 $2.12 $0.66 $0.37 $37.01MH 1000 $280.85 374.65 13.76% $51.54 $5.26 $5.29 $56.83 $3.48 $0.66 $0.55 $57.38BracketBracket- single $90.83 121.17 13.76% 16.67 na $0.00 $16.67 $1.13 $0.00 $0.15 $16.82Bracket- twin $37.83 50.46 13.76% 6.94 na $0.00 $6.94 $0.47 $0.00 $0.06 $7.00Shoebox FixtureHigh PressureSodiumHPS 250 $0.00 0.00 13.76% $0.00 $5.26 $5.29 $5.29 $0.00 $0.66 $0.09 $5.38HPS 400 $0.00 0.00 13.76% $0.00 $5.26 $5.29 $5.29 $0.00 $0.66 $0.09 $5.38Bracket Length30 inch $147.16 196.31 13.76% $27.01 na $0.00 $27.01 $1.83 $0.00 $0.24 $27.25Added FacilitiesAdditional wood poleinstalled for luminaire $609.36 812.89 11.80% $95.91 $0.04 $0.04 $95.95 $7.56 $0.01 $1.00 $96.95Wire service (per footof extension) $1.33 1.77 11.80% $0.21 $0.08 $0.08 $0.29 $0.02 $0.01 $0.00 $0.2936
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 42 of 55Table 25. Derivation of Annual SC1 Street Lighting CostsFixture TypesInvestment perUnitWith GeneralPlant LoadingAnnualEconomicCarryingChargeAnnualizedCost(1) x 1.3340 (2)x(3)O&MWith A&GLoading (Nonplant)Materials &Supplies &PrepaymentsSubtotal(5) x [1+ (.31x 0.0196)] (4)+(6) (2) x 0.0093CashWorkingCapital(6) x0.1250RevenueRequirement forWorking CapitalTotal AnnualCost per Unit[(8)+(9)] x0.1322 (7)+(10)---------------------------------------------------------------------------------------------- (2010 Dollars per Unit) ---------------------------------------------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)# Type 2d F2d 15' post top, w/ HPS $609.02 $812.43 13.76% $111.77 $5.26 $5.29 $117.06 $7.56 $0.66 $1.09 $118.15# Type 2f F2d 15' post top, w/ MH 544.83 726.81 13.76% 99.99 5.26 5.29 105.28 6.76 0.66 0.98 106.26# Type 2g Wood pole supporting a MHshoebox luminaire 297.82 397.30 13.76% 54.66 5.26 5.29 59.95 3.69 0.66 0.58 60.52# Type 9c F9c mast arm WP, w/ HPS 449.67 599.86 13.76% 82.52 5.26 5.29 87.82 5.58 0.66 0.82 88.64# Type 9d F9d mast arm WP, w/ MH 490.14 653.84 13.76% 89.95 5.26 5.29 95.24 6.08 0.66 0.89 96.13# Type 10a F10a 20-25' tub steel w/ MH 5,603.68 7,475.31 13.76% 1,028.39 6.15 6.19 1,034.59 69.52 0.77 9.29 1,043.88# Type 10a-2 F10a-2 20-25' twin steel w/ MH 5,876.46 7,839.19 13.76% 1,078.45 6.15 6.19 1,084.65 72.90 0.77 9.74 1,094.39# Type 10c F10c 20-25' steel, w/ HPS 5,557.49 7,413.69 13.76% 1,019.92 6.15 6.19 1,026.11 68.95 0.77 9.22 1,035.33# Type 10c-2 F10c-2 20-25' tub steel, w/ HPS 5,784.07 7,715.96 13.76% 1,061.50 6.15 6.19 1,067.69 71.76 0.77 9.59 1,077.28# Type 11a F11a 30-35' Steel w/ MH 5,816.68 7,759.46 13.76% 1,067.48 6.15 6.19 1,073.68 72.16 0.77 9.64 1,083.32# Type 11a-2 F11a-2 30-35' Steel w/ MH 6,341.11 8,459.04 13.76% 1,163.73 6.15 6.19 1,169.92 78.67 0.77 10.50 1,180.42# Type 11b F11b 30-35' steel, w/ HPS 5,851.18 7,805.47 13.76% 1,073.81 6.15 6.19 1,080.01 72.59 0.77 9.70 1,089.70# Type 11b-2 F11b-2 30-35' tub steel, w/ HPS 6,410.10 8,551.07 13.76% 1,176.39 6.15 6.19 1,182.58 79.52 0.77 10.62 1,193.19# Type13a F13a mast arm on WP, w/ HPS 590.49 787.71 13.76% 108.37 5.26 5.29 113.66 7.33 0.66 1.06 114.71# Type13b F13b mast arm on WP, w/ MH 641.00 855.09 13.76% 117.64 5.26 5.29 122.93 7.95 0.66 1.14 124.07Type 20b#Customer pole & arm supportingHPS shoebox type luminaire273.88 365.35 13.76% 50.26 5.26 5.29 55.55 3.40 0.66 0.54 56.09# Type 20g Customer pole & arm supportingHPS luminaire 233.41 311.37 13.76% 42.84 5.26 5.29 48.13 2.90 0.66 0.47 48.60# Type 20i Customer pole supporting HPSluminaire (250W max.) 372.28 496.62 13.76% 68.32 5.26 5.29 73.61 4.62 0.66 0.70 74.31Type 20j#Type 21a#Type 21b#Customer pole & arm supporting aMH closed type luminaire308.09 410.99 13.76% 56.54 5.26 5.29 61.83 3.82 0.66 0.59 62.43Customer pole with Company armsupporting a HPS luminaire539.05 719.09 13.76% 98.93 5.26 5.29 104.22 6.69 0.66 0.97 105.19Customer pole with Co. armsupporting a MH closed typeluminaire 558.21 744.65 13.76% 102.44 5.26 5.29 107.73 6.93 0.66 1.00 108.74Type C-4a#C-4a Flour. Underpass 0.00 0.00 13.76% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00Circuit Component# Overhead Wire 1.63 2.18 11.80% 0.26 0.08 0.08 0.33 0.02 0.01 0.00 0.34# Wood Pole Company Owned 532.69 710.60 11.80% 83.84 0.04 0.04 83.88 6.61 0.01 0.87 84.75# Wood Pole Jointly Owned 266.34 355.30 11.80% 41.92 0.04 0.04 41.96 3.30 0.01 0.44 42.40# Conduit & Cable 13.18 17.58 11.80% 2.07 0.08 0.08 2.15 0.16 0.01 0.02 2.17# Buried Cable URD Subdivisions 2.48 3.31 11.80% 0.39 0.08 0.08 0.47 0.03 0.01 0.01 0.47# Cable in Conduit owned by Others 1.29 1.71 11.80% 0.20 0.08 0.08 0.28 0.02 0.01 0.00 0.2837
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 43 of 55VIII. SUMMARY TABLES AND EFFICIENT PRICESAnnual marginal upstream and distribution substation and trunkline feeder costs were timedifferentiatedusing the probability of peak analysis described in Section IV.A.3 above. In Table26 we show these costs, adjusted by losses, for each TOD period, season, and averaged over theentire year. These costs can also be expressed on a per-kWh basis by dividing by the number ofhours in the period, as shown on Table 27. Table 27 also includes the per-kWh marginaltransmission costs from Table 2.38
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 44 of 55Table 26. Summary of Marginal Upstream, Distribution Substation and Trunkline FeederCosts per kWSummer Season Winter SeasonBase SeasonOn-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak--------------------------- (2010 Dollars per kW per month) ----------------------------(1) (2) (3) (4) (5) (6)Residential (SC 4 Periods)Secondary Service(1) TOD Upstream Distribution $7.87 $0.26 $0.00 $0.00 $0.31 $0.12(2) Distribution Substation $3.55 $0.12 $0.00 $0.00 $0.14 $0.05$11.43 $0.38 $0.00 $0.00 $0.44 $0.17(3) Seasonal Upstream Distribution $8.14 $0.00 $0.42(4) Distribution Substation $3.67 $0.00 $0.19$11.81 $0.00 $0.61(5) Annual Upstream Distribution $2.89(6) Distribution Substation $1.30$4.19Non-Residential (SC 8&9 Periods)Transmission Service(7) TOD $0.00 $0.00 $0.00 $0.00 $0.00 $0.00(8) Seasonal $0.00 $0.00 $0.00(9) Annual $0.00Dedicated Substation Service(10) TOD Upstream Distribution $7.52 $0.25 $0.00 $0.00 $0.40 $0.00(11) Seasonal Upstream Distribution $7.76 $0.00 $0.40(12) Annual Upstream Distribution $2.75Primary Service(13) TOD Upstream Distribution $7.68 $0.25 $0.00 $0.00 $0.41 $0.00(14) Distribution Substation $3.47 $0.11 $0.00 $0.00 $0.18 $0.00$11.15 $0.37 $0.00 $0.00 $0.59 $0.01(15) Seasonal Upstream Distribution $7.93 $0.00 $0.41(16) Distribution Substation $3.58 $0.00 $0.19$11.51 $0.00 $0.60(17) Annual Upstream Distribution $2.82(18) Distribution Substation $1.27$4.09Secondary Service(19) TOD Upstream Distribution $7.88 $0.26 $0.00 $0.00 $0.42 $0.00(20) Distribution Substation $3.56 $0.12 $0.00 $0.00 $0.19 $0.00$11.43 $0.37 $0.00 $0.00 $0.60 $0.01(21) Seasonal Upstream Distribution $8.14 $0.00 $0.42(22) Distribution Substation $3.67 $0.00 $0.19$11.81 $0.00 $0.61(23) Annual Upstream Distribution $2.89(24) Distribution Substation $1.30$4.1939
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 45 of 55Table 27. Summary of Marginal Transmission, Upstream and Distribution Substation andTrunkline Feeder Costs, Stated on a per-kWh BasisSummer Season Winter Season Base Season Annual AverageOn-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak----------------------------------------------------------- (2010 Dollars per kWh) -----------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8)Residential (SC 4 Periods)Secondary Service(1) TOD Transmission $0.00396 $0.00389 $0.00394 $0.00389 $0.00392 $0.00387 $0.00394 $0.00388(2) Upstream Dist. $0.02586 $0.00061 $0.00000 $0.00000 $0.00101 $0.00027 $0.00904 $0.00032(3) Dist. Substation $0.01167 $0.00028 $0.00000 $0.00000 $0.00046 $0.00012 $0.00408 $0.00014$0.04149 $0.00478 $0.00394 $0.00389 $0.00538 $0.00426 $0.01706 $0.00434(4) Seasonal Transmission $0.00392 $0.00391 $0.00389(5) Upstream Dist. $0.01112 $0.00000 $0.00057(6) Dist. Substation $0.00502 $0.00000 $0.00026$0.02005 $0.00391 $0.00472(7) Annual Transmission $0.00391(8) Upstream Dist. $0.00396(9) Dist. Substation $0.00179$0.00965Non-Residential (SC 8&9 Periods)Transmission Service(10) TOD Transmission $0.00368 $0.00368 $0.00368 $0.00368 $0.00368 $0.00368 $0.00368 $0.00368(11) Seasonal Transmission $0.00368 $0.00368 $0.00368(12) Annual Transmission $0.00368Dedicated Sub. Service(13) TOD Transmission $0.00378 $0.00376 $0.00378 $0.00376 $0.00377 $0.00375 $0.00377 $0.00375(14) Upstream Dist. $0.02160 $0.00064 $0.00000 $0.00000 $0.00115 $0.00001$0.02538 $0.00440 $0.00378 $0.00376 $0.00492 $0.00376(15) Seasonal Transmission $0.00377 $0.00377 $0.00376(16) Upstream Dist. $0.01060 $0.00000 $0.00055$0.01437 $0.00377 $0.00430(17) Annual Transmission $0.00376(18) Upstream Dist. $0.00377$0.00754Primary Service(19) TOD Transmission $0.00389 $0.00384 $0.00388 $0.00384 $0.00386 $0.00382 $0.00387 $0.00383(20) Upstream Dist. $0.02207 $0.00066 $0.00000 $0.00000 $0.00118 $0.00001 $0.00785 $0.00022(21) Dist. Substation $0.00996 $0.00030 $0.00000 $0.00000 $0.00053 $0.00001 $0.00354 $0.00010$0.03592 $0.00479 $0.00388 $0.00384 $0.00556 $0.00384 $0.01526 $0.00415(22) Seasonal Transmission $0.00386 $0.00386 $0.00384(23) Upstream Dist. $0.01084 $0.00000 $0.00056(24) Dist. Substation $0.00489 $0.00000 $0.00025$0.01959 $0.00386 $0.00465(25) Annual Transmission $0.00385(26) Upstream Dist. $0.00386(27) Dist. Substation $0.00174$0.00945Secondary Service(28) TOD Transmission $0.00395 $0.00389 $0.00394 $0.00389 $0.00392 $0.00387 $0.00393 $0.00388(29) Upstream Dist. $0.02264 $0.00067 $0.00000 $0.00000 $0.00121 $0.00001 $0.00805 $0.00023(30) Dist. Substation $0.01022 $0.00030 $0.00000 $0.00000 $0.00054 $0.00001 $0.00363 $0.00010$0.03681 $0.00486 $0.00394 $0.00389 $0.00567 $0.00388 $0.01562 $0.00421(31) Seasonal Transmission $0.00392 $0.00391 $0.00389(32) Upstream Dist. $0.01112 $0.00000 $0.00057(33) Dist. Substation $0.00502 $0.00000 $0.00026$0.02005 $0.00391 $0.00472(34) Annual Transmission $0.00391(35) Upstream Dist. $0.00396(36) Dist. Substation $0.00179$0.00965Tables 28 summarize monthly marginal customer and local distribution facilities costs per kW ofdesign demand and on a per customer basis, by class.40
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 46 of 55Table 28 A. Summary of Monthly Marginal Customer and Local Distribution FacilitiesCosts per kW of Design Demand and Per Customer – After Customer ContributionsMonthly Monthly MonthlyDistribution Typical Distribution MarginalFacilities Marginal Design Facilities Customer TotalCost per kW of Demand Cost per Cost per MonthlyCustomer Class Design Demand (kW) Customer Customer Costs(2010 $/kW/Month) (kW) (2010 $/Month) (2010 $/Month) (2010 $/Month)(1) x (2) (3) + (4)(1) (2) (3) (4) (5)(1) SC 1 Residential $4.39 2.87 $12.59 $18.09 $30.68(2) SC 4 Residential TOU 4.47 7.17 32.06 27.39 59.45(3) SC 2 General Service - Small Use 5.24 24.83 130.12 19.81 149.93(4) SC 3 General Service - 100 kW Min. 3.03 154.09 466.90 108.46 575.36(5) SC 6 Area Lighting na na na 1.06 1.06(6) SC 7 General Service - 12 kW Minimum 3.93 82.64 324.77 24.49 349.26(7) SC 8 LGS TOU - Secondary 3.16 452.43 1,429.69 102.78 1,532.47(8) New Dedicated Substation Service 2.81 2,000.00 5,620.00 80.33 5,700.33(9) SC 8 LGS TOU - Primary 2.31 1,067.34 2,465.56 224.50 2,690.06(10) SC 8 LGS TOU Transmission na na na 1,599.27 1,599.27(11) SC 9 General Service TOU 5.00 35.40 177.00 47.71 224.71(12) SL 1 Street Lighting Service na na na 7.01 7.01(13) SL 2Street Lighting Customer-OwnedEquipment na na na7.01 7.01(14) SL 3 Traffic Signal na na na 7.01 7.0141
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 47 of 55Table 28 B. Summary of Monthly Marginal Customer and Local Distribution FacilitiesCosts per kW of Design Demand and Per Customer – Total Cost Before CustomerContributionsMonthly Monthly MonthlyDistribution Typical Distribution MarginalFacilities Marginal Design Facilities Customer Totalper kW of Demand Cost per Cost per MonthlyCustomer Class Design Demand (kW) Customer Customer Costs(2010 $/kW/Month) (kW) (2010 $/Month) (2010 $/Month) (2010 $/Month)(1) x (2) (3) + (4)(1) (2) (3) (4) (5)(1) SC 1 Residential $4.39 2.87 $12.59 $19.22 $31.81(2) SC 4 Residential TOU 4.47 7.17 32.06 27.59 59.65(3) SC 2 General Service - Small Use 5.24 24.83 130.12 38.10 168.22(4) SC 3 General Service - 100 kW Min. 3.03 154.09 466.90 175.30 642.20(5) SC 6 Area Lighting na na na 1.06 1.06(6) SC 7 General Service - 12 kW Minimum 3.93 82.64 324.77 47.58 372.35(7) SC 8 LGS TOU - Secondary 3.16 452.43 1,429.69 188.25 1,617.94(8) New Dedicated Substation Service 2.81 2,000.00 5,620.00 80.33 5,700.33(9) SC 8 LGS TOU - Primary 2.31 1,067.34 2,465.56 347.45 2,813.01(10) SC 8 LGS TOU Transmission na na na 1,599.27 1,599.27(11) SC 9 General Service TOU 5.00 35.40 177.00 97.03 274.03(12) SL 1 Street Lighting Service na na na 7.01 7.01(13) SL 2Street Lighting Customer-OwnedEquipment na na na7.01 7.01(14) SL 3 Traffic Signal na na na 7.01 7.01Note:Service cost of Dedicated Substation and Transmission level customers is customer-specific.42
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 48 of 55Tables 29 and 30 summarize monthly lighting costs per fixture.Table 29. Summary of Monthly Marginal Area Lighting and SC1 Street Lighting Cost PerComponentMonthly MarginalCost per UnitMonthly MarginalCost per Unit(2010 $ per Mo.) (2010 $ per Mo.)(1) (2)Fixture TypesStandard FixtureType 2d F2d 15' post top, w/ HPS $9.85 High Pressure SodiumType 2f F2d 15' post top, w/ MH 8.86 HPS 70 $3.48Type 2g Wood pole supporting a MH shoebox luminaire 5.04 HPS 100 3.56Type 9c F9c mast arm WP, w/ HPS 7.39 HPS 150 3.56Type 9d F9d mast arm WP, w/ MH 8.01 HPS 250 3.49Type 10a F10a 20-25' tub steel w/ MH 86.99 HPS 400 3.59Type 10a-2 F10a-2 20-25' twin steel w/ MH 91.20 250/400 duel 5.14Type 10c F10c 20-25' steel, w/ HPS 86.28 Metal HalideType 10c-2 F10c-2 20-25' tub steel, w/ HPS 89.77 MH 250 3.49Type 11a F11a 30-35' Steel w/ MH 90.28 MH 400 3.49Type 11a-2 F11a-2 30-35' Steel w/ MH 98.37 Bracket LengthType 11b F11b 30-35' steel, w/ HPS 90.81 30 inch 2.27Type 11b-2 F11b-2 30-35' tub steel, w/ HPS 99.43 8 foot 3.45Type13a F13a mast arm on WP, w/ HPS 9.56 12 foot 5.40Type13b F13b mast arm on WP, w/ MH 10.34 16 foot 8.19Type 20b F20b (owned by others) 4.67 20 foot 9.52Type 20g F20g (owned by others) 4.05Type 20i F20i (owned by others) 6.19 Flood FixutreType 20j F20j (owned by others) 5.20 High Pressure SodiumType 21a F21a (owned by others) 8.77 HPS 150 0.45Type 21b F21b (owned by others) 9.06 HPS 250 5.24Type C-4a C-4a Flour. Underpass 0.00 HPS 400 5.26HPS 1000 5.39Marginal cost per foot Metal Halide(2010 $ per Mo.) MH 250 3.07Circuit Component MH 400 3.08Overhead Wire $0.03 MH 1000 4.78Wood Pole Company Owned 7.06 BracketWood Pole Jointly Owned 3.53 Bracket- single 1.40Conduit & Cable 0.18 Bracket- twin 0.58Buried Cable URD Subdivisions 0.04Cable in Conduit owned by Others 0.02 Shoebox FixtureHigh Pressure SodiumHPS 250 0.45HPS 400 0.45Bracket Length30 inch 2.27Added FacilitiesAdditional wood poleinstalled for luminaireWire service (per foot ofextension)8.080.0243
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 49 of 55Table 30. Summary of Monthly Marginal Relamping Cost Per UnitMonthly MarginalLamp TypeRelamping CostLumins Wattage Type per Unit(2010 Dollars perunit per Month)1,260 116 Incandescent $1.202,500 166 Incandescent 0.932,800 202 Incandescent 1.094,000 261 Incandescent 1.066,000 366 Incandescent 1.0910,000 621 Incandescent 1.114,000 50 High Pressure Sodium 13.015,800 70 High Pressure Sodium 12.519,500 100 High Pressure Sodium 12.6016,000 150 High Pressure Sodium 12.7127,500 250 High Pressure Sodium 12.8350,000 400 High Pressure Sodium 13.17140,000 1,000 High Pressure Sodium 21.596,950 100 Fluorescent 5.276,950 100 Fluorescent 5.274,000 70 Metal Halide 21.725,850 100 Metal Halide 16.8010,500 175 Metal Halide 13.0117,000 250 Metal Halide 13.8228,800 400 Metal Halide 13.12Efficient rates would mirror the structure of RG&E’s marginal costs and have charges for eachrate component set equal to marginal cost. Efficient rate designs for RG&E’s electric deliveryservice customers consist of a fixed monthly customer charge, a monthly facilities charge basedon kW of design demand (perhaps based on annual peak demand), and time-differentiatedcharges based on monthly use. For classes with a narrow range of design demands, thedistribution facility costs could be combined with the marginal customer costs and recovered in asingle monthly fixed charge. The upstream and distribution substation marginal costs could berecovered either in a demand charge (using the per kW costs in Table 26) or combined withmarginal transmission costs in time-differentiated energy charges (using the per kWh costs inTable 27). There is clear seasonality to the non-local-facilities distribution and transmissionmarginal costs, so even customers without time-of-day meters would see more efficient prices ifthese cost components were seasonally differentiated. Of course rates set equal to these marginalcosts would not produce match NYSEG’s revenue requirement. Some adjustment would benecessary.Tables 31 – 37 compare current charges to efficient prices set equal to marginal cost for eachservice classification, using current rate designs. Again, adjustment would be necessary toproduce the target revenue requirement.44
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 50 of 55Table 31. Marginal Costs Compared to Current Rates (Non-Lighting)CustomerChargeAll kWh1st 200 hrsof demandCurrent Rates Marginal Costs (2010$)AllOtherkWhDeliveryPeakChargeDeliveryOff-PeakCharge($/month) --------------------------------------- ($/kWh) --------------------------------------DemandChargeCustomerCost (afterCIAC)All kWhSC No. 1 Residential Service $20.00 $0.0227 $30.68 $0.00965Year-roundDeliveryPeak CostYear-roundYear-round MonthlyDelivery Marginal DemandOff-Peak Cost Cost($/kw permo.) ($/month) ----------------------- ($/kWh) ---------------------- ($/kw/mo.)SC4 Residential Service - TOUSchedule I $23.98 $0.02783 $0.02252 $59.45 $0.01706 $0.00434SC4 Residential Service - TOUSchedule II $23.98 $0.04249 $0.02723 $59.45 $0.01706 $0.00434SC2 General Service - SmallUse Secondary $20.00 $0.0145 $149.93 $0.00965SC3 100kW MinimumSecondary $160.00 $10.59 $575.36 $0.00391 $4.19SC7 General Service 12 kWMinimum secondary $50.00 $0.00102 $0.00074 $13.38 $349.26 $0.00391 $4.19SC8 Large Time of Use -Secondary $500.00 $7.93 $1,532.47 $0.00391 $4.19SC8 Large Time of Use - SubTransmission-Secondary $800.00 $4.68 $5,700.33 $0.00376 $2.75SC8 Large Time of Use -Primary $450.00 $7.30 $2,690.06 $0.00385 $4.09SC8 Large Time of Use - SubTransmission - Industrial $700.00 $3.31SC8 Large Time of Use - SubTransmission - Commercial $700.00 $3.39SC8 Large Time of Use -Transmission $950.00 $3.38 $1,599.27 $0.00368 $0.00SC9 Time of Use - Secondary $50.00 $0.00663 $0.00389 $9.01 $224.71 $0.00393 $0.00388 $4.1945
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 51 of 55Table 32. Marginal Costs Compared to Current Rates (Lighting Delivery and FixedCharges)Current Rates Marginal Costs (2010$)CustomerDelivery Bill IsuanceDelivery (per Chargewithout SBC Charge (perkWh) (per month)(per kWh) kWh)Lighting Service ClassificationSC 1 Standard lighting $0.620 $0.0096 $7.01SC 2 Customer-Owned24-hour Burning service $0.0126 $0.620 $0.0096 $7.01Dusk-to-Dawn service $0.0352 $0.620 $0.0096 $7.01Dusk-to-l:00 a.m. service $0.1014 $0.620 $0.0096 $7.01SC 3 Traffic SignalEnergy Delivery per Billing Face: $0.9692 $0.620 $0.0096 $7.01SC 6 Area Lighting $0.620 $0.0096 $1.06Table 33. Marginal Costs Compared to Current Rates (Lighting SC 1 Circuit Charges)Street Lighting SC No. 1 - Standard Street LightingCurrent RatesMonthly CircuitCharges($ per unit)Marginal CostMonthly MarginalCircuit Costs(2010 $ per unit)Circuit ChargesOverhead wire $0.0124 $0.0282Street lighting wood poles, Company owned, per pole $4.0533 $7.0629Street lighting wood poles, jointly owned by Co. and 3rd party, per pole $2.0267 $3.5332Conduit and cable $0.0876 $0.1812Direct buried cable in URD subdivisions $0.0406 $0.0394Cable in conduit owned by others $0.0312 $0.023646
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 52 of 55Table 34. Marginal Costs Compared to Current Rates (Lighting SC 1 Fixture Charges)Street Lighting SC No. 1 - Standard Street LightingMonthly Fixture ChargesCurrent Rates($ per unit)Marginal Cost(2010$ per unit)Fixture Charges1 Concrete pole supporting INC harp or globe type luminaire $7.59 $9.851a Concrete pole supporting HPS harp or globe type luminaire $7.59 $9.852d Pole (15 ft. max.) supporting HPS luminaire $12.99 $9.852e Pole (15 ft. max.) supporting octagonal HPS luminaire $16.98 $9.852f Pole (15 ft. max) supporting a MH post top luminaire $12.27 $8.862g Wood pole (17 ft. max.) supporting a MH shoebox type luminaire $11.96 $5.043a Fluted pole with arm supporting INC open type luminaire $6.35 $7.393a-2 Fluted pole with two arms each supporting INC open type luminaire $8.70 $7.395a Wood pole with arm supporting an INC open type luminaire $1.62 $7.396 Steel pole supporting an INC harp or globe type luminaire $4.76 $7.396a Steel pole supporting a HPS harp or globe type luminaire $4.76 $7.399b Wood pole with arm supporting an INC closed type luminaire $2.61 $7.399c Wood pole with arm supporting a HPS luminaire (150W max.) $5.02 $7.399d Wood pole with arm supporting a MH closed type luminaire (250W max) $4.42 $8.0110a Davit pole (20-25 ft) supporting a MH luminaire (250W max) $11.91 $86.9910a-2 Davit pole (20-25 ft.) supporting two MH luminaires (250W max) $17.47 $91.2010c Davit pole (20 - 25 ft.) supporting a HPS luminaire (150W max.) $11.64 $86.2810c-2 Davit pole (20 - 25 ft.) supporting two HPS luminaires (150W max.) $17.21 $89.7711a Davit pole (30-35 ft.) supporting a MH luminaire (1000W max) $14.02 $90.2811a-2 Davit pole (20-25 ft.) supporting two MH luminaires (1000W max) $21.14 $98.3711b Davit pole (30 - 35 ft.) supporting a HPS luminaire (400W max.) $15.64 $90.8111b-2 Davit pole (30 - 35 ft.) supporting two HPS luminaires (400W max.) $24.68 $99.4313a Wood pole with arm supporting a HPS luminaire (400W max.) $6.85 $9.5613b Wood pole with arm supporting a MH closed type luminaire (1000W max) $4.40 $10.3420b Customer pole & arm supporting a HPS shoebox type luminaire $6.99 $4.6720d Customer pole supporting Company high mast HPS luminaire installed by Customer $8.53 $8.7720g Customer pole & arm supporting a HPS luminaire $4.16 $4.0520i Customer pole supporting a HPS luminaire (250W max.) $7.82 $6.1920j Customer pole & arm supporting a MH closed type luminaire $2.77 $5.2020k Customer pole supporting a MH post top luminaire (250W max) $3.40 $6.1921a Customer pole with Company arm supporting a HPS luminaire $5.76 $8.7721b Customer pole with Company arm supporting a MH closed type luminaire $4.08 $9.06C-5 Conduit fed fixture with INC lamp burning 24 hours a day (2500 Lumen) $2.47 $0.00C-4a Conduit fed fluorescent tunnel light $9.21 $0.00C-5a Conduit fed fluorescent tunnel light burning 24 hours a day $9.89 $0.00C-6 Conduit fed fixture with two INC lamps (1260 Lumen ea.) $4.99 $0.0047
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 53 of 55Table 35. Marginal Costs Compared to Current Rates (Lighting SC 1 Lamp Charges)Current RatesStreet Lighting SC No. 1 -Standard Street Lighting Lumens WattsMarginal CostLampCharge Relamping($ per light) (2010$ per light)Incandescent 1,260 116 $4.23 $1.20Incandescent 2,500 166 $3.92 $0.93Incandescent 2,800 202 $4.13 $1.09Incandescent 2,800 202 $12.32 $1.09Incandescent 4,000 261 $5.34 $1.06Incandescent 6,000 366 $6.87 $1.09Incandescent 10,000 621 $12.68 $1.11High Pressure Sodium 4,000 50 $1.14 $13.01High Pressure Sodium 5,800 70 $1.47 $12.51High Pressure Sodium 9,500 100 $1.98 $12.60High Pressure Sodium 16,000 150 $2.78 $12.71High Pressure Sodium 27,500 250 $4.66 $12.83High Pressure Sodium 50,000 400 $6.97 $13.17High Pressure Sodium 140,000 1,000 $20.26 $21.59Fluorescent (dusk-to-dawn) 6,950 100 $2.77 $5.27Fluorescent (24-hour burning) 6,950 100 $4.48 $5.27Metal Halide 4,000 70 $2.57 $21.72Metal Halide 5,850 100 $2.54 $16.80Metal Halide 10,500 175 $2.44 $13.01Metal Halide 17,000 250 $2.45 $13.82Metal Halide 28,800 400 $2.45 $13.1248
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 54 of 55Table 36. Marginal Costs Compared to Current Rates (Area Lighting Fixture Charges)Area Lighting SC No. 6Type of LuminaireLumenCurrent RateMarginal CostResidential Non-Residential 2010$Monthly Charge Monthly Charge Monthly(per unit) (per unit) Costs (per unit)StandardHigh Pressure SodiumHPS 70 5,800 $5.92 $5.88 $3.48HPS 100 9,500 $5.99 $5.98 $3.56HPS 150 16,000 $10.69 $10.61 $3.56HPS 250 27.5 $14.08 $14.04 $3.49HPS 400 50,000 $15.16 $15.24 $3.59Metal HalideMH 250 22,000 $14.32 $14.29 $3.49MH 400 36,000 $15.10 $15.18 $3.49Bracket Length30 inch $0.58 $0.58 $2.278 foot $0.78 $0.78 $3.4512 foot $1.12 $1.12 $5.4016 foot $1.55 $1.55 $8.1920 foot $1.90 $1.90 $9.52Flood Fixture:High Pressure SodiumHPS 150 16,000 $10.42 $10.35 $0.45HPS 250 27,500 $11.51 $11.48 $5.24HPS 400 50,000 $12.51 $12.57 $5.26HPS 1000 140,000 $25.02 $25.25 $5.39Metal HalideMH 250 19,500 $13.36 $13.30 $3.07MH 400 32,000 $14.03 $14.05 $3.08MH 1000 100,000 $23.49 $23.68 $4.78BracketBracket- single $0.49 $0.49 $1.40Bracket- twin $0.98 $0.98 $0.58Shoe Box FixtureHigh Pressure SodiumHPS 250 27,500 $16.23 $16.23 $0.45HPS 400 50,000 $17.14 $17.14 $0.45Bracket Length30 inch $0.58 $0.58 $2.27Added FacilitiesAdditional wood pole installed forluminaire $3.62 $3.62 $8.08Wire service (per foot of extension) $0.02 $0.02 $0.0249
Exhibit __ (RGEHP-2) <strong>Rebuttal</strong>Page 55 of 55NERA Economic ConsultingSuite 1950Los Angeles, California 90017Tel: +1 213 346 3000Fax: +1 213 346 3030www.nera.com50
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 1 of 56February 8, 2010New York State Electric & Gas CorporationMarginal Cost of Electric Delivery Service
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 2 of 56Project Team<strong>Hethie</strong> ParmesanoAmparo NietoWilliam RankinJordan NarducciNicholas AmabileNERA Economic Consulting777 South Figueroa Street, Suite 1950Los Angeles, California 90017Tel: +1 213 346 3000Fax: +1 213 346 3030www.nera.com
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 3 of 56ContentsI. INTRODUCTION........................................................................................................................1II. COSTING/PRICING PERIODS.................................................................................................2III. MARGINAL TRANSMISSION COST ....................................................................................4IV. MARGINAL DISTRIBUTION COSTS ...................................................................................6A. Upstream Distribution Equipment and Distribution Substation and Trunkline FeederCosts.....................................................................................................................................7B. Local Distribution Facility Costs.......................................................................................11C. Lighting Costs....................................................................................................................14D. Meter and Service Costs ....................................................................................................17V. OTHER MARGINAL COSTS .................................................................................................21A. Customer Accounts Expenses............................................................................................21B. Customer Service and Informational Expenses .................................................................22C. Administrative and General Expenses...............................................................................24D. General Plant......................................................................................................................24E. Marginal Losses.................................................................................................................25VI. COMPUTATION OF ECONOMIC CARRYING CHARGES ..............................................26VII. COMPUTATION OF ANNUAL MARGINAL COSTS.......................................................28VIII. 2010 SUMMARY TABLES AND EFFICIENT PRICES....................................................39NERA Economic Consultingi
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 4 of 56List of TablesTable 1. Costing/Pricing Periods .............................................................................3Figure 1. Generalized Diagram of NYSEG’s Delivery System ..............................4Table 2. Summary of 2010 Marginal Transmission Costs .....................................5Table 3. Upstream Substations, Distribution Substations and TrunklineFeeder Investment.............................................................................................8Table 4. Upstream Station and Distribution Substation O&M Expense perkW...................................................................................................................10Table 5. Probability of Peak for Upstream Substations, DistributionSubstations & Trunkline Feeders....................................................................11Table 6. Marginal Distribution Facilities Investment per kW of...........................13Design Demand......................................................................................................13Table 7. Distribution Facilities O&M Expense per kW of Design Demand .........14Table 8. Outdoor Lighting Investment and O&M .................................................15Table 9. Standard Street Lighting Service Investment and O&M.........................16Table 10. Relamping Expense per Unit .................................................................17Table 11. Investment per Customer in Meters and Services .................................18Table 12. Meter O&M Expense per Weighted Customer......................................19Table 13. Meter O&M Expense by Service Classification....................................20Table 14. Adjustment Factor for Uncollectibles....................................................21Table 15. Customer Accounts and Uncollectibles Expense by ServiceClassification ..................................................................................................22Table 16. Customer Services and Informational Expenses by ServiceClassification ..................................................................................................23Table 17. Administrative and General Expense and General Plant Loaders.........25Table 18. Incremental Capital Structure and Cost.................................................26Table 19. Economic Carrying Charges..................................................................27Table 20. Derivation of Annual Distribution Substation and TrunklineFeeder and Upstream Substation Costs ..........................................................29Table 21 A. Derivation of Annual Distribution Facilities Costs – AfterCIAC...............................................................................................................30Table 21 B. Derivation of Total Annual Distribution Facilities Costs(Before CIAC) ................................................................................................30Table 21 C. Derivation of Annual Distribution Facilities Costs – AfterCIAC...............................................................................................................31Table 21 D. Derivation of Total Annual Distribution Facilities Costs(Before CIAC) ................................................................................................32Table 22 A. Derivation of Annual Meter, Service and Customer-RelatedCosts – After CIAC ........................................................................................33Table 22 B. Derivation of Total Annual Meter, Service and Customer-Related Costs – Before CIAC.........................................................................34Table 22 C. Derivation of Annual Meter, Service and Customer-RelatedCosts – After CIAC ........................................................................................35Table 22 D. Derivation of Total Annual Meter, Service and Customer-Related Costs – Before CIAC.........................................................................36NERA Economic Consultingii
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 5 of 56Table 23. Derivation of Annual Outdoor Lighting Costs ......................................37Table 24. Derivation of Annual Standard Lighting Service Costs ........................38Table 25. Summary of Monthly Marginal Upstream Substation, DistributionSubstation and Trunkline Feeder Costs per kW .............................................39Table 26 A. Summary of Marginal Transmission, Upstream Substation,Distribution Substation and Trunkline Feeder Costs, on a per-kWhBasis................................................................................................................40Table 26 B. Summary of Marginal Transmission Costs per-kWh.........................41Table 27 A. Summary of Monthly Marginal Customer and LocalDistribution Facilities Costs (after CIAC payments)......................................42Table 27 B. Summary of Total Monthly Marginal Customer and LocalDistribution Facilities Costs (total before CIAC payments)...........................42Table 28. Summary of Monthly Marginal Outdoor Lighting Cost perComponent......................................................................................................43Table 29. Summary of Monthly Marginal Standard Lighting Service Costper Component................................................................................................44Table 30. Summary of Monthly Relamping Expense per Component..................45Table 31 A. Marginal Costs Compared to Current Rates (Non-Lighting) ............46Table 31 B. Marginal Costs Compared to Current Rates (Lighting Deliveryand Fixed Charges ..........................................................................................46Table 31 C. Marginal Costs Compared to Current Rates (SC1 and SC2O&M Charges) ...............................................................................................47Table 31 D. Marginal Costs Compared to Current Rates (SC 3 FixtureCharges)..........................................................................................................48Table 31 E. Marginal Costs Compared to Current Rates (SC 3 CircuitCharges)..........................................................................................................49Table 31 F. Marginal Costs Compared to Current Rates (SC 5 Charges) .............50NERA Economic Consultingiii
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 6 of 56I. INTRODUCTIONNew York State Electric & Gas Corporation (NYSEG) retained NERA Economic Consulting toprepare an estimate of the company’s typical marginal costs of delivering electricity, for use inthe company’s 2009 rate case. All costs are expressed in 2010 dollars. Estimates of marginalcosts for subsequent years can be calculated by applying an appropriate inflation factor. 1 Thisreport describes the methods for estimating marginal transmission, distribution and customerrelatedcosts and presents summary tables of the results.What are marginal costs? Marginal cost is defined as the change in total cost with respect to asmall change in output. To quantify the marginal costs of electricity service one must answer thequestion: What are the additional costs that would be incurred with changes in kilowatt-hours ofenergy, kilowatts of demand and number of customers? Because some of the cost of additionalconsumption differ depending upon the time of the change in output, it is important to estimatetime-differentiated marginal costs of electricity delivery.Our method for estimating marginal costs is based on the system planning process, and takes intoaccount the wholesale market and transmission access arrangements specific to the environmentwhere the utility operates. We determine the marginal cost of electricity by examining theutility’s planning processes to determine what drives new investment and operating decisionsand how changes in consumption affect utility system operations. The method is not a formula,but a series of guidelines outlining what should be measured and how the measurements can bemade.1NYSEG is using an inflation rate of 1.9% for internal purposes, and this inflation rate is used in the economiccarrying charges described in Section VI.1
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 7 of 56II. COSTING/PRICING PERIODSIn this study we developed hourly marginal cost estimates for the transmission and distributioncomponent costs that vary with time of use—loss-adjusted NYISO transmission charges, 2upstream distribution equipment and distribution substations and trunkline feeders. Thesummary tables in Section VIII show these cost components aggregated by NYSEG’s variouscurrent time-of-day pricing periods and the seasonal periods in SC12, shown in Table 1.2 As explained in Section III, transmission marginal costs do not vary with time of use within a month, except formarginal losses associated with the various voltage levels at which customers are served.2
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 8 of 56Table 1. Costing/Pricing PeriodsResidential TOU (SC 12)Winter: December - FebruaryOn-Peak: 7 – 10 am; 5-10 pm, Mon. – Fri., ESTMid-Peak: 10 am – 5 pm and 10 pm to 11:30 pm, Mon. –Fri.; and 7 am – 11:30 pm Sat., Sun. andHolidays, 3 ESTSummer: June - AugustOff-Peak: 11:30 pm – 7 am, ESTOn-Peak: 10 am – 6 pm, Mon. – Fri., ESTMid-Peak: 7 – 10 am and 6 – 11:30 pm, Mon. – Fri.; 7 am– 11:30 pm, Sat., Sun., and Holidays 3, ESTOff-Peak: 11:30 pm – 7 am, ESTOff-Season:March – May and September - NovemberPeak: NAMid-Peak: 7 am – 11:30 pm, ESTOff-Peak: 11:30 pm – 7 am, ESTLarge General Service TOU (SC 7)On-Peak: Mon. – Fri., 7 am to 10 pm, local time, exceptHolidays 3Off-Peak: All remaining hoursGeneral Service and Residential Day-Night (SC 8,9)Day: 7 am – 11:30 pm ESTNight: All remaining hours3 Holidays are New Year’s Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day and ChristmasDay.3
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 9 of 56III. MARGINAL TRANSMISSION COSTAs the figure below illustrates, NYSEG’s transmission facilities consist of transmission lines ofvarious voltage levels, and transmission substations. Lines of a particular voltage level canfunction either as transmission or distribution. The determination of what is considered atransmission facility is governed by FERC rules. Certain facilities upstream of distributionsubstations and formerly known as transmission facilities, but not meeting the FERC definition,are referred to as “upstream distribution facilities” in this study.Figure 1. Generalized Diagram of NYSEG’s Delivery SystemTransmissionTransmission SubstationsTransmissionCustomer115 kV Transmission LinesUpstream Substations(including some115/69/46/34 kV)Upstream Distribution Lines (69/46/34 kV)Dist. SubstationTrunkline Feeder Primary(34/12/4 kV)DistributionLineTransformerSecondaryServiceLocalPrimaryLinePrimaryserviceHigher voltage distributioncomponentsSecondaryCustomerSecondaryLinePrimaryCustomerLocal DistributionFacilitiesCustomer-relatedcomponent (service)4
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 10 of 56As a Transmission Owner subject to the rules of the New York Independent System Operator(NYISO), NYSEG’s transmission revenue requirement is the basis for the Company’sTransmission Service Charge (TSC). Users of NYSEG’s transmission system (implicitlyincluding NYSEG, although no explicit payment is made) are required to pay this charge. IfNYSEG’s delivery service customers use more electricity, NYSEG is responsible for additionalTSC charges, which constitute NYSEG’s marginal transmission cost. Other NYISO chargesapplicable to NYSEG are considered commodity costs and so are not included in this study.A specific forecast of TSC charges is not available. We used as the starting point for NYSEG’smarginal transmission costs recent historical charges, which are flat prices per MWh sold ortransported. The charges were atypical in 2008, dropping to zero in 6 of the 12 months. As aresult, we used the average of the monthly NTAC charges in August - December of 2007 andJanuary – July of 2009 ($3.5221 per MWh). We applied factors that account for losses from thetransmission tie point to customer meters, using estimates of average marginal energy losses byperiod. 4 Table 2 shows the results for 2010 by period and voltage level of service.Table 2. Summary of 2010 Marginal Transmission CostsSummer SeasonWinter SeasonOff SeasonOn-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak--------------------------------------------------- (2010 Dollars per kWh) ---------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9)Marginal Transmission Cost $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352LOSS ADJUSTED MARGINAL TRANSMISSION COSTSResidential TOU (SC 12) PeriodsSecondary Service(1) TOD $0.00382 $0.00378 $0.00372 $0.00382 $0.00379 $0.00375 $0.00377 $0.00371(2) Seasonal $0.00377 $0.00379 $0.00375(3) Annual $0.00376LGS TOU (SC 7) PeriodsTransmission Service(4) TOD $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352(5) Seasonal $0.00352 $0.00352 $0.00352(6) Annual $0.00352Primary Service(7) TOD $0.00376 $0.00370 $0.00376 $0.00372 $0.00373 $0.00369(8) Seasonal $0.00373 $0.00375 $0.00371(9) Annual $0.00372Secondary Service(10) TOD $0.00381 $0.00374 $0.00381 $0.00376 $0.00378 $0.00373(11) Seasonal $0.00377 $0.00380 $0.00375(12) Annual $0.00377Day-Night (SC 8 & 9) Periods(13) Secondary Serv TOD $0.00380 $0.00372 $0.00380 $0.00375 $0.00377 $0.00371(14) Seasonal $0.00377 $0.00379 $0.00375(15) Annual $0.003774 Section V.E discusses the development of the marginal energy loss factors.5
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 11 of 56IV. MARGINAL DISTRIBUTION COSTSConceptually, most costing practitioners agree that the design of the distribution system isdetermined by two major factors: (1) the number and location of customers and (2) theirdemands. Marginal cost studies have traditionally attempted to identify a portion of distributioncosts as customer-related and the remaining portion as demand-related. This has led tosemantics arguments about the definition of the customer-related and demand-relatedcomponents. In fact, for most distribution systems, this two-part segmentation of distributionequipment is not consistent with the cost drivers, because it ignores the fact that there are twotypes of demand that determine distribution capacity requirements for a particular customer –design (or contract) demand and near-term demand at the time of likely neighborhood peaks.Figure 1 above includes a simplified illustration of NYSEG’s distribution system. The variousdistribution components are categorized as:• substations and lines upstream from distribution substations, but defined asdistribution (shown as bold lines and boxes);• distribution substations and primary trunkline feeders (shown as bold lines andboxes);• local distribution facilities: consisting of secondary lines, primary-to-secondarytransformers and local primary lines (shown as solid boxes);• customer-related service drops (shown as dashed lines).NYSEG adds distribution substation capacity and distribution equipment upstream of thesesubstations as load grows, either from connection of new customers or growth by existingcustomers. The trunkline feeders from the substation to the point where the line branches tocreate a local primary line also must be upgraded or rerouted as load grows. Because these moreextensively shared, higher voltage distribution components are expanded as customer loads growin critical hours, their costs are time-differentiated.Local distribution facilities are designed using engineering design standards that take intoconsideration the number of customers and the maximum expected loads (or “design demands”)of customers who will eventually use those facilities, over the life of the facilities. For example,residential customers with electric space heat typically have design demands higher than thosewithout, and single family homes typically have higher design demands than apartments orcondos. Local distribution facilities for commercial and industrial customers are generallydesigned on a case-by-case basis, taking into consideration the expected long-term peak demandby the customer.6
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 12 of 56Because the marginal cost of local distribution facilities is incurred based on design demand, anddoes not vary with a customer’s actual peak load from hour to hour or month to month, thesecosts are computed as a fixed monthly cost per kW of design (or contract) demand. These costsare marginal when the customer is initially connected to the grid, and again whenever thefacilities have to be replaced because of age. At that point the costs could be avoided if theservice connection was eliminated. 5 These facilities are also marginal when there is a majorincrease in the design demand of the customers using them.The service drop in most cases serves a single customer. The service, along with the meter andassociated equipment such as current transformer (not shown in the diagram), is treated as part ofthe marginal customer cost for each class, and is discussed in Section IV.D.A. Upstream Distribution Equipment and Distribution Substation andTrunkline Feeder CostsTo estimate the marginal cost of typical upstream distribution and distribution substation andtrunkline feeder expansion per kW of demand, we typically identify the cost of budgeted loadgrowth-related projects of this type (excluding any replacement projects that do not add capacity)and divide by the load growth that is driving the need for the additional capacity. We used aslightly different approach for NYSEG because not all parts of the Company’s service territoryare experiencing growth.NYSEG was able to provide details about distribution substation and trunkline feeder expansionin 2007 – 2009 and upstream station expansion for 2009 projects. There are no growth-relatedupstream lines projects planned for 2009. To compute marginal investment in upstream stationsand distribution substations and trunkline feeders, we followed a three-step process:1. We divided the sum of the investment (in 2010 dollars) by the additions to nameplatecapacity represented by those projects to obtain a typical investment per kVA of capacity.2. To convert these figures to costs per kW of load, we multiplied the cost per kVA of capacityby one plus the typical reserve margin in NYSEG’s substations in 2008. NYSEG does notplan for a specific reserve margin in these facilities. However their planning policy doesresult in capacity in excess of peak loads because of factors such as the lumpiness of capacityadditions. The typical reserve margin was computed by identifying substations facing loadgrowth, and determining the median of those stations’ 2008 reserve margins (54 percent). 6This process excludes substations that have lost load in recent years or otherwise have higherthan typical reserves.5 This might occur, for example, if the customers using the specific local facilities decided to go off-grid, or thehomes or businesses were demolished.6 Calculated as nameplate capacity divided by 2008 peak load, minus 1.7
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 13 of 563. A final adjustment recognizes that some substations have sufficient capacity to accommodateload growth. Thus, load growth in those areas will not trigger marginal investment. Toconvert the results from Step 2 to marginal investment applicable systemwide, we multipliedby a factor representing the share (71 percent) of 2008 substation peak loads in stations thathad 2008 reserve margins below the typical level identified in Step 2. The computations foreach of the three components are shown on Table 3.Table 3. Upstream Substations, Distribution Substations and Trunkline Feeder InvestmentDistribution Substations and Trunkline Feeders(1) Budgeted Investment per kW of Nameplate Capacity inDistribution Substations and Trunkline Feeders, 2007-2009(2010 Dollars/kW) $103.17(2) Typical 2008 Percent Reserve Margin 54%(3) Typical Investment per kW of Load Growth (2010 Dollars/kW)[(1) x (1+(2))] $158.88(4) 2008 Peak Load of Substations with Growth as aPercent of Total Station Peak Loads 71%(5)System-wide Marginal Investment in Distribution Substations andTrunkline Feeders (2010 Dollars per kW)(2010 Dollars per kW) (3) x (4) $112.11Upstream Distribution Substations(6) 2009 Budgeted Investment per kW of Nameplate Capacity Added inUpstream Distribution Stations(2010 Dollars/kW) $81.00(7) Typical Investment per kW of Load Growth (2010 Dollars/kW)[(6) x (1+(2))] $124.73(8)System-wide Marginal Investment in Upstream Distribution Stations(2010 Dollars per kW) (7) x (4) $88.021. Upstream Substation and Distribution Substation Marginal O&MExpensesDistribution O&M expenses are a function of the amount of distribution plant in service. Theaddition of distribution plant required to meet increments in customers or design load or peaksubstation load gives rise to increased O&M expenses as well. Distribution O&M expenses are,therefore, marginal costs. We used NYSEG’s NYPSC Annual Reports for 2004 – 2008 as thestarting point for our analysis of distribution O&M expenses. Expenses for individual8
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 14 of 56components (e.g., meters, substations, etc.) were allocated a proportional share of the generaloverhead distribution O&M categories. 7We divided the 2004-2008 distribution substation O&M expenses, plus associated overheads, byan estimate of the sum of non-coincident peak demands at the upstream substations 8 andconverted to 2010 dollars, as shown on Table 4. After reviewing the trend in expense per kW (inconstant dollars), we used the average of the 2007-2008 values as our estimate of marginalsubstation O&M expenses per kW of load. However, as the investment analysis discussed aboverevealed, load growth in some parts of NYSEG’s service territory is not likely to requireadditions to upstream or distribution substation capacity. Consequently, we applied the samefactor used in the third step above to the estimates of marginal station O&M to account for thissituation. Because these expenses cover both distribution stations and upstream stations, wedivided the results into two components, based on the estimated non-coincident peak loads ofstations in the two categories. These calculations are shown in Table 4.7 These general accounts consist of Operation Supervision and Engineering, Miscellaneous Operations,Maintenance Supervision and Engineering, and Miscellaneous Maintenance Expense.8 This estimate was developed by taking the sum of the non-coincident peak demands on distribution substationsand adding the annual peak demands of customers served at subtransmission voltage.9
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 15 of 56Table 4. Upstream Station and Distribution Substation O&M Expense per kWSubstation SubstationExpenses Per Expenses PerTotal Estimated kW of Weighted kW ofDistribution Substation Substation Labor and SubstationSubstation Noncoincident Noncoincident Materials NoncoincidentYear Expenses Peak Loads Peak Load Cost Index Peak Load(Thousand Dollars) (MW) (Dollars) (2010=1.00) (2010 Dollars)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 $13,045 3,375 $3.86 0.78 $4.98(2) 2005 9,957 3,757 2.65 0.81 3.29(3) 2006 9,084 3,507 2.59 0.85 3.05(4) 2007 10,830 3,502 3.09 0.90 3.44(5) 2008 8,225 3,577 2.30 0.95 2.43(6) Estimated Annual Distribution Substation O&M Expenses(Average of 2007-2008) $2.93(7) 2008 Peak Load of Substations with Growth as aPercent of Total Station Peak Loads 71%(8) Adjustment for share of system that will require additional capacity by 2013: (6) x (7) $2.07(9) 2008 Upstream Peak Load as a Percentage of Total Upstream and DistributionSubstation Peak Load (3,577 / 6,845) 52%(10) Upstream Station Share: (8) x (9) $1.08(11) 2008 Distribution Substation Peak Load as a Percentage of Total Upstreamand Distribution Substation Peak Load (3,268 / 6,845) 48%(12) Distribution Substation Share: (8) x (11) $0.992. Time-differentiation of Marginal Upstream and Distribution Substation &Trunkline CostsOnly load growth when capacity is strained triggers additions to the higher voltage distributionsystem. We analyzed hourly loads on a sample of representative rural and suburban NYSEGdistribution substations for the years 2006-2008 to identify patterns of loads.We estimated the relative probability of peak for months, day-types (e.g., weekdays, weekends)and hours for each substation, taking into account the higher carrying capability of thisequipment in cold temperatures. We then calculated weighted averages of these individualsubstation relative probabilities of peak for each set of pricing periods, using as weights thenameplate capacity of all urban/suburban and rural substations in the NYSEG system. The periodassignment factors are shown on Table 5.10
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 16 of 56Table 5. Probability of Peak for Upstream Substations, Distribution Substations &Trunkline FeedersRelative Probability of Substation PeakResidential Periods(SC 12)LGS TOU Periods(SC 7)Day-Night Periods(SC 8 & 9)(1) (2) (3)Summer Season(1) On-Peak 90.0% 99.1% 100.0%(2) Mid-Peak 10.0%(3) Off-Peak 0.0% 0.9% 0.0%(4) Subtotal 100.0% 100.0% 100.0%Winter Season(5) On-Peak 0.0% 0.0% 0.0%(6) Mid-Peak 0.0%(7) Off-Peak 0.0% 0.0% 0.0%(8) Subtotal 0.0% 0.0% 0.0%Off SeasonOn-Peak 0.0% 0.0%(9) Mid-Peak 0.0%(10) Off-Peak 0.0% 0.0% 0.0%(11) Subtotal 0%(12) Total 100% 100% 100%B. Local Distribution Facility Costs1. Local Distribution Facility InvestmentNYSEG developed estimates of the typical investment per kW of design demand in services, 9secondary lines, transformers, and local primary lines for various types and sizes of customers bycalculating the replacement cost of this equipment on a sample of three circuits – one urban-ruraland two village-rural. Because of low representation of large customers on the sample circuits,9 Service drop costs are discussed in Section IV D below.11
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 17 of 56NYSEG also provided information on ten additional customers in the SC 2, SC 7-1 and SC 7-2classes. NYSEG indicated that, although served at secondary voltage, few SC 7-1 customerswould use secondary lines and so we assigned no secondary line costs to those customers. Wecomputed weighted averages of facilities investment per kW for each customer group within acircuit using the number of sample customers of each type on that circuit as weights. To combinethe results from the three circuits, we weighted by the number of customers by class on rural andurban/suburban circuits over the entire NYSEG system.Because the marginal cost of local distribution facilities is incurred based on design demand, anddoes not vary with a customer’s actual peak load from month to month, we computed these costsas a monthly cost per kW of design (or contract) demand. NYSEG estimated the design demandfor each customer in the sample by using customer bills to determine if the circuit is summer orwinter peaking, and then using the customer’s billing demand (or a conversion factor applied tokWh) of the customer’s peak season bill.The distribution facilities investments for residential and non-residential customer categories areshown on Table 6. No local facilities costs are identified for lighting customers because theirusage does not affect the sizing of distribution facilities. Transmission-level customers providetheir own local facilities, so no facilities cost is shown for them either. A portion of localfacilities costs is sometimes recovered upfront in contributions in aid of construction (CIAC)charges. The marginal local facilities cost estimates are shown two ways—excluding the portionof local facilities costs paid up front, to avoid double-counting when the estimates are used toinform rate design, and including the full cost of the equipment.12
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 18 of 56Table 6. Marginal Distribution Facilities Investment per kW ofDesign DemandAverage Total AverageInvestment (after Investment (beforeCIAC) per kW of CIAC) per kW ofCustomer Class Design Demand Design Demand(2010 Dollars) (2010 Dollars)(1) SC 1 Residential Service $602.22 $810.82(2) SC 8 Residential Service Day Night Service $602.22 $810.82(3) SC 12 Residential Service with Time-of-Use Metering $602.22 $810.82(4) SC 2 General Service with Demand Metering $358.81 $544.50(5) SC 3 Primary Service - 25 kW or more - Primary $166.71 $166.71(6) SC5 Outdoor Lighting Service NA NA(7) SC 6 General Service $573.28 $754.83(8) SC 7-1 LGS with TOU Metering - Secondary $87.02 $87.02(9) SC 7-2 LGS with TOU - Primary $166.71 $166.71(10) SC 7-4 LGS with TOU Metering - Transmission $0.00 $0.00(11) SC 9 General Service - Day Night Service $573.28 $754.83(12) SL 1 Street Lighting - Contributory Provisions NA NA(13) SL 2 Street Lighting - Energy and Limited Maintenance NA NA(14) SL 3 Standard Street Lighting Service NA NA2. Local Distribution Facility Operation and MaintenanceWe reviewed the 2004-2008 local distribution facilities portion of distribution line O&Mexpenses, 10 plus maintenance of line transformers 11 and separated line-related expenses intoprimary and secondary categories on the basis of circuit miles of conductor. 12 We divided theexpenses for each voltage level by estimates of total design demand of customers using thosefacilities. Total design demand is the product of customer counts and per-customer designdemand estimates based on a variety of data sources. 13 We used the average of the 2007 and2008 values as our estimate of marginal distribution facilities O&M expense, as shown on Table7.10 FERC accounts 583, 584, 593, 594, plus an allocation of accounts 580, 588, 590 and 598. The portion of theseaccounts attributable to upstream lines was excluded, based on circuit miles of conductor.11 FERC account 595, plus an allocation of accounts 580, 588, 590 and 598.12 We treated all primary lines O&M as a local facilities cost, rather than trying to identify the portion of primaryline miles that is trunkline feeders.13 These include the design demands of customer on the sample circuits, load data used to develop allocators for theembedded cost-of-service study, actual individual customer actual peak demands, and maximum demandspermitted by a tariff.13
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 19 of 56Table 7. Distribution Facilities O&M Expense per kW of Design DemandSecondaryPrimarySecondary Primary Distribution DistributionPortion of Portion of Weighted Facilities FacilitiesDistribution Distribution Labor and Expense ExpenseFacilities Facilities Load on Load on Materials Per kW of Per kW ofYear O&M Expenses O&M Expenses Secondary Primary Cost Index Load Load(000's Dollars) (000's Dollars) (kW) (kW) (2010 = 1.00) (2010 Dollars/kW) (2010 Dollars/kW)[[(1)x1000/(3)]/(5) [[(1)x1000/(3)]/(5)(1) (2) (3) (4) (5) (6)(1) 2004 4,413 39,702 4,470,480 4,770,976 0.78 $1.27 $10.72(2) 2005 6,364 61,601 4,494,616 4,817,482 0.81 $1.76 $15.87(3) 2006 7,319 79,927 4,533,743 4,860,122 0.85 $1.90 $19.38(4) 2007 4,922 57,079 4,584,047 4,902,505 0.90 $1.19 $12.94(5) 2008 4,872 57,772 4,612,010 4,937,307 0.95 $1.12 $12.36(6) Estimated Annual Weighted Primary Distribution Facilities O&M Expense(Average of 2007-2008) $12.65(7) Estimated Annual Weighted Secondary Distribution Facilities O&M Expense(Average of 2007-2008) $13.80C. Lighting Costs1. Lighting InvestmentThe amount of investment NYSEG makes to provide lighting service depends upon the type ofservice offered and the specific equipment required for each installation. Lighting serviceequipment is categorized in three components:• Circuit equipment – This is dedicated equipment comparable to a service drop for a nonlightingcustomer and may include overhead wire, wood poles, underground conductorand conduit, and buried cable.• Fixtures – This equipment includes various types of poles (other than circuit poles),bases, brackets and luminaires.• Lamps – This category consists of the lamps and photo eyes.NYSEG offers two lighting services in which the company provides and maintains the lightingequipment:• SC 5 - Outdoor Lighting Service and• SC 3 - Standard Street Lighting Service.For two other lighting services NYSEG provides only lamp and photo control replacement:14
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 20 of 56• SC1 - Street Lighting Services with Contributory Provisions and• SC 2 - Street Lighting Service with Energy and Limited MaintenanceNYSEG provided estimates of the installed cost of marginal outdoor light and standard streetlight equipment (fixtures, poles, lines and associated facilities) and associated annual O&Mexpense, per foot, as shown on Tables 8 and 9.Table 8. Outdoor Lighting Investment and O&MSC 5 Outdoor Lighting EquipmentTotal Installed Cost ExcludingLamp and Photo EyeAnnual O&M (Excl.Relamping)(2010 $ per Unit)(1) (2)Safeguard Luminaires14,500 Nominal Lumen 150 Watt H.P.S. (replacing 7,000 L. 175 Watt M.V.) $523.4343,000 Nominal Lumen 400 Watt H.P.S. (replacing 17,200 L. 400 Watt M.V.) 583.07123,000 Nominal Lumen 940 Watt H.P.S. (replacing 48,000 L. 1,000 Watt M.V.) 823.33Area Lights8,500 Nominal Lumen (100 Watt) H.P.S.* 30.138,500 Nominal Lumen (100 Watt) H.P.S. Power Bracket 568.4314,400 Nominal Lumen (150 Watt) H.P.S. 523.4324,700 Nominal Lumen (250 Watt) H.P.S. 551.3545,000 Nominal Lumen (400 Watt) H.P.S. 583.07126,000 Nominal Lumen (1,000 Watt) H.P.S. 823.3310,500 Nominal Lumen (175 Watt) Metal Halide Power Bracket 653.5216,000 Nominal Lumen (250 Watt) Metal Halide 558.0528,000 Nominal Lumen (400 Watt) Metal Halide 582.98Flood Lights14,400 Nominal Lumen (150 Watt) H.P.S. 604.7124,700 Nominal Lumen (250 Watt) H.P.S 616.6345,000 Nominal Lumen (400 Watt) H.P.S. 616.99126,000 Nominal Lumen (1,000 Watt) H.P.S. 716.5616,000 Nominal Lumen (250 Watt) Metal Halide 614.1528,000 Nominal Lumen (400 Watt) Metal Halide 614.1688,000 Nominal Lumen (1,000 Watt) Metal Halide 702.13"Shoebox" Luminaire14,400 Nominal Lumen (150 Watt) H.P.S. 703.3724,700 Nominal Lumen (250 Watt) H.P.S. 706.0245,000 Nominal Lumen (400 Watt) H.P.S. 760.2116,000 Nominal Lumen (250 Watt) Metal Halide 748.0028,000 Nominal Lumen (400 Watt) Metal Halide 736.8088,000 Nominal Lumen (1,000 Watt) Metal Halide 843.25Post Tops5,200 Nominal Lumen (70 Watt) H.P.S. 577.308,500 Nominal Lumen (100 Watt) H.P.S. 583.60Brackets 16' and over 227.03 $0.00Additional Wood Pole Installed for Lamp 587.64 51.66Wire Service (Overhead) (Per circuit foot of extension) 1.34 0.0018' Fiberglass Pole - Direct Embedded 553.59 4.6120' Fiberglass Pole - Pedestal Mount 553.59 4.6120' Metal Pole - Pedestal Mount 830.81 26.6230' Metal Pole - Pedestal Mount 967.62 26.6230' Fiberglass Pole - Pedestal Mount 1,429.33 4.6130' Fiberglass Pole - Direct Embedded 1,429.33 4.61Screw Base for Pedestal Mounted Pole - Light Duty 688.14 0.00Screw Base for Pedestal Mounted Pole - Heavy Duty 696.56 0.0015
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 21 of 56Table 9. Standard Street Lighting Service Investment and O&MSC3 Streetlighting EquipmentLuminaire & Mast Arm TotalInstalled Cost Excluding Lamp Facilitiesand Photo EyeInstalled Cost(2010 $ per Unit)Facilities AnnualO&M(1) (2) (3)High Pressure Sodium Cobra(1) 70 Watts - 5,200 Lumen $530.01(2) 150 Watts - 14,400 Lumen 538.31(3) 250 Watts - 24,700 Lumen 565.90(4) 400 Watts - 45,000 Lumen 598.61(5) 1000 Watts - 126,000 Lumen 863.09High Pressure Sodium Post Top(6) 50 Watts - 3,300 Lumen 598.94(7) 70 Watts - 5,200 Lumen 590.93(8) 150 Watts - 14,400 Lumen 604.08High Pressure Sodium Cut Off ("Shoebox")(9) 250 Watts - 24,700 Lumen 720.56(10) 400 Watts - 45,000 Lumen 805.04Metal Halide Cobra(11) 100 Watts – 5,800 Lumen 591.77(12) 175 Watts – 12,000 Lumen 568.77(13) 250 Watts - 16,000 Lumen 566.35(14) 400 Watts - 28,000 Lumen 642.11Metal Halide Cut Off (“Shoebox”)(15) 175 Watts – 12,000 Lumen 655.54(16) 250 Watts - 16,000 Lumen 695.88(17) 400 Watts - 28, 000 Lumen 752.20Metal Halide Post Top(18) 70 Watts – 4,000 Lumen 630.82(19) 100 Watts- 5,800 Lumen 649.85(20) 175 Watts - 12,000 Lumen 623.63High Pressure Sodium Special Luminaires(21) 250 Watts - 24,700 - Hiway Liter 1,554.55(22) 400 Watts - 45,000 - Hiway Liter 1,331.91(23) 150 Watts - 14,400 - Turnpike 921.12(24) 250 Watts - 24,700 - Turnpike 933.55(25) 400 Watts - 45,000 - Turnpike 994.48(26) 150 Watts - 14,400 - Floodlight 618.92(27) 250 Watts - 24,700 - Floodlight 631.18(28) 400 Watts - 45,000 - Floodlight 631.92Metal Halide - Floodlights(29) 250 Watts - 16,000 Lumen 654.16(30) 400 Watts - 28,000 Lumen 629.49Pole Installed by the Corporation(31) Standard Wood Pole $378.83 $51.66(32) Wood Pole - high mount use (45' or greater) 540.94 51.66(33) Aluminum Pole 16' and under 365.16 0.00(34) Alum. Pole over 16' installed prior to August 1, 1987 581.70 0.00(35) Alum. Pole over 16' direct embedded installed after July 31, 1987 581.70 0.00(36) Alum. Pole over 16' pedestal mounted 691.82 0.00(37) Fiberglass Pole 18' and under 350.42 4.61(38) Fiberglass Pole 18' to 22' 350.42 4.61Screw-in steel base for pedestal mounted poles:(39) Light Duty 242.73 0.00(40) Heavy Duty 249.75 0.00Special Brackets(41) Standard Bracket - 16' and over 348.00 0.00Circuit Control(42) Group Controllers 587.00 0.00Circuits (Per Trench Foot**)(43) Cable and Conduit 2.31 0.00(44) Direct Burial Cable 1.73 0.00(45) Cable Only (Conduit Supplied by Customer) 1.31 0.00(46) Underground Circuits 2.31 0.0016
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 22 of 562. Lamp Replacement ExpenseNYSEG provided estimates of annual expense for replamping (including replacement of lampsand photo cells) applicable to all of the lighting services. We adjusted these estimates to 2010dollars and added loaders for A&G expense and cash working capital.Lamp TypeTable 10. Relamping Expense per UnitRelamping Expenseper Unit per Year(2010 Dollars)High Pressure Sodium50 Watts - 3,300 Lumen $17.3370 Watts - 5,200 Lumen 17.33100 Watts - 8,500 Lumen 17.79150 Watts - 14,400 Lumen 17.85250 Watts - 24,700 Lumen 17.92400 Watts - 45,000 Lumen 18.12940 Watts - 123,000 Lumen 23.041000 Watts - 126,000 Lumen 23.04Metal Halide70 Watts – 4,000 Lumen 20.24100 Watts - 5,800 Lumen 24.11175 Watts - 10,500 or 12,000 Lumen 18.02250 Watts - 16,000 Lumen 18.02400 Watts - 28,000 Lumen 18.091000 Watts - 88,000 Lumen 20.16Mercury Vapor100 Watts - 3,200 Lumen 18.52175 Watt - 7,000 Lumen 18.52250 Watts - 9,400 Lumen 18.52400 Watts - 17,200 Lumen 18.521000 Watts - 48,000 Lumen 18.52D. Meter and Service Costs1. Meter and Service InvestmentNYSEG provided the installed cost of a typical meter (including current and potentialtransformer, if applicable). The analysis of sample circuits and the supplemental large customersample used to develop marginal facilities costs included detailed cost estimates of the serviceson the circuits, which were used to develop estimates of the installed cost of services for eachcustomer classification. The typical meter (and associated equipment) and service drop17
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 23 of 56investments, stated in 2010 dollars are shown on Table 11. A portion of service costs issometimes recovered upfront in contributions in aid of construction (CIAC) charges. Themarginal service cost estimates are shown two ways—excluding the portion of local facilitiescosts paid up front, to avoid double-counting when the estimates are used to inform rate design,and including the full cost of the equipment.Table 11. Investment per Customer in Meters and ServicesTotalMeter & Total Meter &Service Service Service ServiceMeter Investment Investment Investment InvestmentRate Description Investment after CIAC after CIAC (before CIAC) (before CIAC)------------------------------------- (2010 $ per Customer) -------------------------------------(1) + (2) (1) + (4)(1) (2) (3) (4) (5)(1) SC 1 Residential Service $114.91 $411.32 $526.24 $746.92 $861.84(2) SC 8 Residential Service Day Night Service 213.60 411.32 624.92 746.92 960.52(3) SC 12 Residential Service with Time-of-Use Metering 213.60 411.32 624.92 746.92 960.52(4) SC 2 General Service with Demand Metering 528.41 978.82 1,507.23 5,515.41 6,043.82(5) SC 3 Primary Service - 25 kW or more - Primary 7,265.00 0.00 7,265.00 2,401.78 9,666.78(6) SC5 Outdoor Lighting Service na na 0.00 na 0.00(7) SC 6 General Service 168.46 20.06 188.52 416.62 585.08(8) SC 7-1 LGS with TOU Metering - Secondary 861.78 3,786.40 4,648.18 8,791.83 9,653.61(9) SC 7-2 LGS with TOU - Primary 7,249.61 0.00 7,249.61 2,401.78 9,651.39(10) SC 7-4 LGS with TOU Metering - Transmission 90,956.54 0.00 90,956.54 0.00 90,956.54(11) SC 9 General Service - Day Night Service 199.39 20.06 219.44 416.62 616.0118
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 24 of 562. Meter and Service Operation and Maintenance ExpensesWe analyzed meter O&M expenses 14 over the past five years. The meter O&M per weightedcustomer (using relative meter cost as weights) declined significantly over the past few years. Inconsultation with NYSEG, we used the 2008 value as the estimate of the marginal level of theseexpenses, as shown on Table 12. Table 13 multiplies the result by the class weights to yieldannual meter O&M by service classification.Table 12. Meter O&M Expense per Weighted CustomerTotal Meter MeterMeter Average Weighted Expense Weighted ExpenseOperation & Number of Average Per Labor and PerMaintenance Metered Number of Weighted Materials WeightedYear Expenses Customers Customers Customer Cost Index Customer(000's Dollars) (Dollars) (2010 = 1.00) (2010 Dollars)(2) x 1.47 [(1) x 1000]/(3) (4)/(5)(1) (2) (3) (4) (5) (6)(1) 2004 $22,983 845,401 1,243,581 $18.48 0.78 $23.80(2) 2005 23,536.56 850,188 1,250,622 18.82 0.81 23.36(3) 2006 17,466.82 858,317 1,262,581 13.83 0.85 16.30(4) 2007 13,413.87 862,951 1,269,397 10.57 0.90 11.74(5) 2008 11,629.38 864,151 1,271,162 9.15 0.95 9.66(6) Estimated Annual Weighted Meter O&M Expense(2008 value) $9.6614 FERC accounts 586 and 597, plus associated overheads.19
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 25 of 56Table 13. Meter O&M Expense by Service ClassificationAnnualWeighting Meter ExpenseRate Class Factor Per Customer(2010 Dollars)(1) x $9.66(1) (2)(1) SC 1 Residential Service 1.00 $9.66(2) SC 8 Residential Service Day Night Service 1.86 17.97(3) SC 12 Residential Service with Time-of-Use Metering 1.86 17.97(4) SC 2 General Service with Demand Metering 4.60 44.44(5) SC 3 Primary Service - 25 kW or more - Primary 63.22 611.03(6) SC5 Outdoor Lighting Service na na(7) SC 6 General Service 1.47 14.17(8) SC 7-1 LGS with TOU Metering - Secondary 7.50 72.48(9) SC 7-2 LGS with TOU - Primary 63.09 609.73(10) SC 7-4 LGS with TOU Metering - Transmission 791.53 7,649.95(11) SC 9 General Service - Day Night Service 1.74 16.7720
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 26 of 56V. OTHER MARGINAL COSTSA. Customer Accounts ExpensesCustomer accounts expenses, composed mainly of meter-reading and billing expenses anduncollectibles, 15 are costs that are the function of a number of customers on the system. Weanalyzed the level of customer accounts expenses 16 other than uncollectibles for the last fiveyears and determined, in consultation with RG&E, that the 2008 expenses are a reasonableproxy for the marginal cost in future years. We used the results from the 2008 embedded study toidentify the cost per customer for each class.In the case of uncollectibles, which had a two-fold increase from 2007 to 2008, we adjusted theannual cost per customer from the embedded study by the ratio of the two-year average to the2008 level to reduce the effect of the recession. Table 14 shows the calculation of thisuncollectibles ratio and Table 15 shows the estimated marginal costs by service classification.Table 14. Adjustment Factor for UncollectiblesYearUncollectibles2007 $10,140,5392008 $15,611,320Average $12,875,930Ratio Average to 2008 82.48%15 We dealt with uncollectibles separately because this component of customer accounts expense is not subject to thecash working capital adjustment, discussed later.16 FERC accounts 901-905, excluding portions of uncollectibles and credit and collection costs that are associatedwith the merchant function.21
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 27 of 56Table 15. Customer Accounts and Uncollectibles Expense by Service ClassificationCustomer CustomerAccounts Accounts EstimatedExpense (excl. Expense (excl. 2008 Marginaluncollectibles) Uncollectibles uncollectibles) Uncollectibles UncollectiblesRate Class per Customer per Customer per Customer per Customer per Customer(2008 $) (2008 $) (2010 $) (2010 $) (2010 $)(1) / 0.9426 (2) / 0.9426 (4) x 0.8248(1) (2) (3) (4) (5)(1) SC 1 Residential Service $27.76 $8.25 $29.45 $8.76 $7.22(2) SC 8 Residential Service Day Night Service 30.24 11.28 32.08 11.97 9.87(3) SC 12 Residential Service with Time-of-Use Metering 47.21 40.14 50.09 42.59 35.13(4) SC 2 General Service with Demand Metering 42.45 6.69 45.04 7.10 5.86(5) SC 3 Primary Service - 25 kW or more - Primary 115.71 28.18 122.76 29.89 24.66(6) SC5 Outdoor Lighting Service 14.59 0.68 15.48 0.72 0.59(7) SC 6 General Service 24.54 0.97 26.03 1.03 0.85(8) SC 7-1 LGS with TOU Metering - Secondary 116.79 29.74 123.91 31.55 26.02(9) SC 7-2 LGS with TOU - Primary 607.67 192.62 644.68 204.35 168.54(10) SC 7-4 LGS with TOU Metering - Transmission 1,633.61 536.49 1,733.09 569.16 469.43(11) SC 9 General Service - Day Night Service 26.17 1.43 27.77 1.51 1.25(12) SL 1 Street Lighting - Contributory Provisions 77.12 21.48 81.82 22.79 18.79(13) SL 2 Street Lighting - Energy and Limited Maintenance 77.12 21.48 81.82 22.79 18.79(14) SL 3 Standard Street Lighting Service 77.12 21.48 81.82 22.79 18.79B. Customer Service and Informational ExpensesCustomer service and informational expenses, 17 which include the costs of disseminatinginformation to consumers, typically vary with the number of customers on the system and are,therefore, marginal.In consultation with RG&E we used the 2008 embedded cost values per customer for eachclassification as our estimate of marginal customer service and informational expenses. Table 16shows the expense by service classification.17 FERC Accounts 908, 909 and 910.22
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 28 of 56Table 16. Customer Services and Informational Expenses by Service ClassificationAnnual Customer Annual CustomerService and Service andInformational InformationalExpense ExpenseRate Class Per Customer Per Customer(2008 $) (2010 $)(1) / 0.9426(1) (2)(1) SC 1 Residential Service $0.46 $0.48(2) SC 8 Residential Service Day Night Service 0.63 0.66(3) SC 12 Residential Service with Time-of-Use Metering 2.24 2.38(4) SC 2 General Service with Demand Metering 2.46 2.61(5) SC 3 Primary Service - 25 kW or more - Primary 10.50 11.14(6) SC5 Outdoor Lighting Service 0.27 0.29(7) SC 6 General Service 0.36 0.38(8) SC 7-1 LGS with TOU Metering - Secondary 10.64 11.28(9) SC 7-2 LGS with TOU - Primary 70.72 75.03(10) SC 7-4 LGS with TOU Metering - Transmission 166.14 176.25(11) SC 9 General Service - Day Night Service 0.53 0.56(12) SL 1 Street Lighting - Contributory Provisions 8.72 9.25(13) SL 2 Street Lighting - Energy and Limited Maintenance 8.72 9.25(14) SL 3 Standard Street Lighting Service 8.72 9.2523
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 29 of 56C. Administrative and General ExpensesWhen a utility adds plant and incurs additional O&M expenses, it typically incurs additionalcorporate overhead costs as well. Certain administrative and general (A&G) expenses can groweither with plant or with O&M expenses. General plant typically grows with other types ofplant. Our marginal cost study includes plant-related A&G, non-plant-related A&G and generalplant loaders to capture these elements of marginal cost.Based on our understanding of NYSEG’s classification of costs in the various FERC accountsfor administrative and general (A&G) expenses we identified A&G accounts as potentiallymarginal with respect to O&M. We then used regression analyses on 29 years of historical data(1980-2008) in an attempt to estimate the marginal level of non-plant-related A&G expense.However, the regression analysis did not yield meaningful results. Consequently, because socialsecurity and unemployment benefits clearly grow with O&M, we used as the non-plant-relatedA&G loader the 2008 ratio of social security and unemployment benefits to total O&M (lessfuel, purchased power and transmission by others).The regression analysis of A&G accounts likely to be marginal with respect to plant oncumulative additions to total plant also did not yield meaningful results. Consequently, wetreated property insurance as the only element of plant-related A&G. NYSEG provided theexpected 2009 insurance premium per dollar of investment. NYSEG’s property insurance coversdistribution substations, but not lines or other distribution facilities. So the plant-related A&Gloader is used only in the calculations of substation marginal costs. Both A&G loaders are shownon Table 17 below.D. General PlantGeneral plant consists of items such as office buildings, warehouses, cars, trucks and otherequipment. The need for general plant typically increases with marginal increases in other typesof plant. Regression analysis did yield significant results for this loader. Using data for 1992 -2008, we regressed cumulative additions to general plant net of retirements and the electric shareof common plant on cumulative additions to plant net of retirements, less general and commonplant, all stated in 2008 dollars. Dummy shift variables for post 1999 and post 2006 were used toaccount for large increases in general plant. The coefficient of the explanatory variable is theloader used in this study.24
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 30 of 56Table 17. Administrative and General Expense and General Plant LoadersEstimate ofLoadingFactor(1) Non-Plant Related A&G Loader 2.95%(2) Plant-Related A&G Loader 0.04%(3) General Plant & the Electric Share of Common Plant Loader 21.95%E. Marginal LossesThe marginal cost study develops transmission, upstream distribution, and distribution substationand trunkline feeder costs stated on a per-kW or per-kWh basis, stated at each particularcomponent of the system. For use in ratemaking, these costs must be adjusted to costs at themeter of customers served at the various voltage levels of service.The marginal loss calculations in this study are based on estimates of variable and total losses attime of system peak at each voltage level for which costs are calculated. Marginal capacitylosses, applied to upstream substations and to distribution substation and trunkline feeder costs,reflect the fact that to accommodate a kW of additional peak load at the customer’s meter,facilities must be expanded by successively more than a kW as you move up the distributionsystem to accommodate the fixed and variable losses on the system in the peak hour. Peakcapacity loss factors were developed from NYSEG’s most recent detailed loss study.Marginal energy losses reflect the additional losses incurred to move an added kWh through thesystem at a particular level of system load. Fixed losses are, by definition, not affected by theincrements of load to a fixed system. Only variable losses come into these calculations. Marginalenergy losses increase in proportion to the square of the load. We calculated average hourlylosses in each pricing period by means of an approximation of quadratic losses based on variablelosses at system peak load (from NYSEG’s most recent detailed loss study) and 2008 hourlysystem loads. These marginal energy losses were applied to the marginal transmission costs,which are incurred on a per-kWh basis.25
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 31 of 56VI. COMPUTATION OF ECONOMIC CARRYING CHARGESSection IV above describes the development of estimates of marginal investment in severalcategories of distribution plant. To be useful in ratemaking and other marginal cost applications,the investment must be converted into annual costs using an economic carrying charge. Theannual charge reflects the elements of NYSEG’s revenue requirement associated withincremental plant: return to stockholders and bondholders, depreciation, and income andproperty taxes. For use in a marginal cost study, the appropriate stream of annual charges is astream that rises at the rate of inflation net of technical progress and yields the total present valueof all costs over the life of the investment. In such a stream, the first year's charge represents thecost in today's dollars of owning the plant or equipment for a year. It also represents the rentalrate for such an investment in a competitive market.Key inputs for the economic carrying charge calculation include: (1) the utility’s incrementalcost of capital (mix of debt and equity and their respective long-term market costs), (2) theexpected inflation rate for that type of plant, net of technical progress, and (3) the average servicelife and patterns of failure (“Iowa curve”) for that type of plant.NYSEG foresees financing of near-term incremental investment through additional equity(retained earnings and/or infusion of equity capital from the parent company) and long-term debtwith the capital structure and costs shown in Table 18.Table 18. Incremental Capital Structure and CostShare Cost(%) (%)Debt 51.50 7.00Common Stock 48.50 11.43Another integral part of the economic carrying charge calculation is the estimation of the rate ofinflation net of technical progress applicable over the life of the investment. We used 1.9 percentas an approximation of the rate of future inflation net of technical progress, based on NYSEG’srecommendation.Finally, an adjustment is required for the fact that not all plant and equipment will last itsestimated service life. Some components will require early replacement, causing added costs,while some will last longer than expected and produce savings. The pattern of expected requiredreplacement for each type of plant is defined by an Iowa Curve. An adjustment for this dispersedpattern of replacements using Iowa Curves was included in the derivation of the economic26
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 32 of 56carrying charges. The aggregated 18 results of these economic carrying charge calculations arepresented below. The adjustments for dispersed retirements are shown on line (2) of this table.Table 19. Economic Carrying ChargesDistribution Distribution Meters & StreetSubstations Facilities Services Lights(2) (3) (4) (5)(1) Present Value of Revenue RequirementsRelated to Incremental $1,000 Investment $1,766.35 $1,787.14 $1,744.57 $1,692.03(2) Present Value Cost of ReplacingDispersed Retirements Related toIncremental $1,000 Investment $102.02 $114.94 $122.12 $162.89(3) Total Present Value Cost Related toIncremental $1,000 Investment (1)+(2) $1,868.37 $1,902.08 $1,866.69 $1,854.92(4) First-Year Annual Economic ChargeRelated to Incremental $1,000 Investment $124.51 $121.38 $127.41 $136.85(5) First-Year Annual Economic Charge Related toIncremental Investment (4)/$1,000 12.45% 12.14% 12.74% 13.69%18 Iowa curves were provided for a range of FERC plant accounts. The economic carrying charge calculations wereperformed separately for each of these accounts and aggregated to the five categories reported by weightingaccording to dollars of gross plant.27
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 33 of 56VII. COMPUTATION OF ANNUAL MARGINAL COSTSTo compute marginal investment for each distribution component of service to annual marginalcosts, we adjusted upwards the investment per unit by the general plant loading factor. Wemultiplied the resulting figures by the annual economic carrying charge percentage (plus theplant-related A&G loading factor for substations) to yield the annualized plant costs. To thesecosts we added the associated O&M and A&G expenses and the revenue requirements forworking capital.The computation of working capital includes components for cash, materials, supplies andprepayments. The materials, supplies and prepayments needs were estimated based on recenthistorical amounts. The cash working capital factor is the FERC approach (1/8 of O&M). Therevenue requirement for working is computed as NYSEG’s weighted average incremental cost ofcapital plus an income tax component that recognizes that the equity portion of return on capitalis taxable.Table 20 shows the derivation of the annual distribution substation and trunkline feeder costs andupstream station costs.28
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 34 of 56Table 20. Derivation of Annual Distribution Substation and Trunkline Feeder andUpstream Substation CostsDistributionSubstations andTrunklineFeedersUpstreamDistributionSubstations---------- (2010 Dollars/kW) ---------(1) (2)(1) Marginal Investment per kW $112.11 $88.02(2) With General Plant Loading (1) x 1.2195 136.72 107.34(3) Annual Economic Carrying Charge Related toCapital Investment 12.45% 12.45%(4) A&G Loading (plant related) 0.04% 0.04%(5) Total Annual Carrying Charge (3) + (4) 12.49% 12.49%(6) Annualized Costs (2) x (5) $17.08 $13.41(7) O&M Expenses 0.99 1.08(8) With A&G Loading (7) x 1.0295 (Non-plant Related) 1.02 1.11(9) Subtotal (6) + (8) $18.10 $14.51Working Capital(10) Material and Supplies (2) x 0.12% $0.16 $0.13(11) Prepayments (2) x 0.86% 1.18 0.92(12) Cash Working Capital Allowance (8) x 12.50% 0.13 0.14(13) Total Working Capital (10) + (11) + (12) $1.47 $1.19(14) Revenue Requirement for WorkingCapital (13) x 13.29% 0.20 0.16(15) Total Annual Cost (9) + (14) $18.29 $14.67Tables 21 below show the development of the annual marginal cost for local distributionfacilities.29
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 35 of 56Table 21 A. Derivation of Annual Distribution Facilities Costs – After CIACSC 1 SC 8 SC 12 SC 2 SC 3P SC 6ResidentialResidentialDay NightResidentialTOUGeneralService withDemandPrimaryService(Primary)GeneralService--------------------------------- (2010 Dollars per kW of Design Demand) ---------------------------------(1) (2) (3) (4) (5) (6)(1) Marginal Investment per kW of Design Demand $602.22 $602.22 $602.22 $358.81 $166.71 $573.28(2) With General Plant Loading (1) x 1.2195 * 780.19 780.19 780.19 478.33 203.31 738.97(3) Annual Economic Carrying Charge Related toCapital Investment 12.14% 12.14% 12.14% 12.14% 12.14% 12.14%(4) A&G Loading (plant-related) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total Annual Carrying Charge (3) + (4) 12.14% 12.14% 12.14% 12.14% 12.14% 12.14%(6) Annualized Costs (2) x (5) $94.70 $94.70 $94.70 $58.06 $24.68 $89.70(7) Annual Expense per kW of Design Demand 13.80 13.80 13.80 13.80 12.65 13.80(8) With A&G Loading (7) x 1.0295(non-plant related) 14.21 14.21 14.21 14.21 13.02 14.21(9) Distribution Facilities Related Costs (6) + (8) $108.91 $108.91 $108.91 $72.27 $37.70 $103.91Working Capital(10) Material and Supplies (2) x 0.12% * $1.19 $1.19 $1.19 $0.80 $0.24 $1.10(11) Prepayments (2) x 0.86% * 8.50 8.50 8.50 5.71 1.75 7.92(12) Cash Working Capital Allowance (8) x 12.50% 1.78 1.78 1.78 1.78 1.63 1.78(13) Total Working Capital (10) + (11) + (12) $11.47 $11.47 $11.47 $8.28 $3.62 $10.80(14) Revenue Requirement for WorkingCapital (13) x 13.29% 1.52 1.52 1.52 1.10 0.48 1.43(15) Total Annual Marginal DistributionFacilities Related Costs (9) + (14) $110.43 $110.43 $110.43 $73.37 $38.18 $105.34Note:In rows with asterisks, adjustments are made to full investment (before CIAC) from next table.Table 21 B. Derivation of Total Annual Distribution Facilities Costs (Before CIAC)SC 1 SC 8 SC 12 SC 2 SC 3P SC 6ResidentialResidentialDay NightResidentialTOUGeneralService withDemandPrimaryService(Primary)GeneralService-------------------------------- (2010 Dollars per kW of Design Demand) --------------------------------(1) (2) (3) (4) (5) (6)(1) Marginal Investment per kW of Design Demand $810.82 $810.82 $810.82 $544.50 $166.71 $754.83(2) With General Plant Loading (1) x 1.2195 988.80 988.80 988.80 664.02 203.31 920.52(3) Annual Economic Carrying Charge Related toCapital Investment 12.14% 12.14% 12.14% 12.14% 12.14% 12.14%(4) A&G Loading (plant-related) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total Annual Carrying Charge (3) + (4) 12.14% 12.14% 12.14% 12.14% 12.14% 12.14%(6) Annualized Costs (2) x (5) $120.02 $120.02 $120.02 $80.60 $24.68 $111.74(7) Annual Expense per kW of Design Demand 13.80 13.80 13.80 13.80 12.65 13.80(8) With A&G Loading (7) x 1.0295(non-plant related) 14.21 14.21 14.21 14.21 13.02 14.21(9) Distribution Facilities Related Costs (6) + (8) $134.23 $134.23 $134.23 $94.81 $37.70 $125.94Working Capital(10) Material and Supplies (2) x 0.12% 1.19 1.19 1.19 0.80 0.24 1.10(11) Prepayments (2) x 0.86% 8.50 8.50 8.50 5.71 1.75 7.92(12) Cash Working Capital Allowance (8) x 12.50% 1.78 1.78 1.78 1.78 1.63 1.78(13) Total Working Capital (10) + (11) + (12) $11.47 $11.47 $11.47 $8.28 $3.62 $10.80(14) Revenue Requirement for WorkingCapital (13) x 13.29% 1.52 1.52 1.52 1.10 0.48 1.43(15) Total Annual Marginal DistributionFacilities Related Costs (9) + (14) $135.75 $135.75 $135.75 $95.91 $38.18 $127.3830
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 36 of 56Table 21 C. Derivation of Annual Distribution Facilities Costs – After CIACSC 7-1 SC 7-2 SC 7-4 SC 9LGS TOUSecondaryLGS TOUPrimaryLGS TOUTransmissionGeneralService DayNight------------------- (2010 Dollars per kW of Design Demand) ------------------(1) (2) (4) (5)(1) Marginal Investment per kW of Design Demand $87.02 $166.71 $0.00 $573.28(2) With General Plant Loading (1) x 1.2195 * 106.12 203.31 0.00 738.97(3) Annual Economic Carrying Charge Related toCapital Investment 12.14% 12.14% 12.14% 12.14%(4) A&G Loading (plant-related) 0.00% 0.00% 0.00% 0.00%(5) Total Annual Carrying Charge (3) + (4) 12.14% 12.14% 12.14% 12.14%(6) Annualized Costs (2) x (5) $12.88 $24.68 $0.00 $89.70(7) Annual Expense per kW of Design Demand 13.80 12.65 0.00 13.80(8) With A&G Loading (7) x 1.0295(non-plant related) 14.21 13.02 0.00 14.21(9) Distribution Facilities Related Costs (6) + (8) $27.09 $37.70 $0.00 $103.91Working Capital(10) Material and Supplies (2) x 0.12% * 0.13 0.24 0.00 1.10(11) Prepayments (2) x 0.86% * 0.91 1.75 0.00 7.92(12) Cash Working Capital Allowance (8) x 12.50% 1.78 1.63 0.00 1.78(13) Total Working Capital (10) + (11) + (12) $2.82 $3.62 $0.00 $10.80(14) Revenue Requirement for WorkingCapital (13) x 13.29% 0.37 0.48 0.00 1.43(15) Total Annual Marginal DistributionFacilities Related Costs (9) + (14) $27.46 $38.18 $0.00 $105.34Note:In rows with asterisks, adjustments are made to full investment (before CIAC) from next table.31
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 37 of 56Table 21 D. Derivation of Total Annual Distribution Facilities Costs (Before CIAC)SC 7-1 SC 7-2 SC 7-4 SC 9LGS TOUSecondaryLGS TOUPrimaryLGS TOUTransmissionGeneralService DayNight------------------- (2010 Dollars per kW of Design Demand) ------------------(1) (2) (4) (5)(1) Marginal Investment per kW of Design Demand $87.02 $166.71 $0.00 $754.83(2) With General Plant Loading (1) x 1.2195 106.12 203.31 0.00 920.52(3) Annual Economic Carrying Charge Related toCapital Investment 12.14% 12.14% 12.14% 12.14%(4) A&G Loading (plant-related) 0.00% 0.00% 0.00% 0.00%(5) Total Annual Carrying Charge (3) + (4) 12.14% 12.14% 12.14% 12.14%(6) Annualized Costs (2) x (5) $12.88 $24.68 $0.00 $111.74(7) Annual Expense per kW of Design Demand 13.80 12.65 0.00 13.80(8) With A&G Loading (7) x 1.0295(non-plant related) 14.21 13.02 0.00 14.21(9) Distribution Facilities Related Costs (6) + (8) $27.09 $37.70 $0.00 $125.94Working Capital(10) Material and Supplies (2) x 0.12% 0.13 0.24 0.00 1.10(11) Prepayments (2) x 0.86% 0.91 1.75 0.00 7.92(12) Cash Working Capital Allowance (8) x 12.50% 1.78 1.63 0.00 1.78(13) Total Working Capital (10) + (11) + (12) $2.82 $3.62 $0.00 $10.80(14) Revenue Requirement for WorkingCapital (13) x 13.29% 0.37 0.48 0.00 1.43(15) Total Annual Marginal DistributionFacilities Related Costs (9) + (14) $27.46 $38.18 $0.00 $127.38Tables 22 show the annualization of meters and service drops and also include customer-relatedexpenses.32
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 38 of 56Table 22 A. Derivation of Annual Meter, Service and Customer-Related Costs – AfterCIACSC 1 SC 8 SC 12 SC 2 SC 3 SC 5 SC 6ResidentialResidentialDay NightResidentialTOUGeneralService withDemandPrimaryService(Primary)OutdoorLightingGeneralService--------------------------------------------- (2010 Dollars per Customer) --------------------------------------------(1) (2) (3) (4) (5) (6) (8)(1) Meter and Service Investment $526.24 $624.92 $624.92 $1,507.23 $7,265.00 $0.00 $188.52(2) With General Plant Loading (1) x 1.2195 * 715.41 835.76 835.76 2,833.85 9,386.86 0.00 316.94(3) Annual Economic Charge Related toCapital Investment 12.74% 12.74% 12.74% 12.74% 12.74% 12.74% 12.74%(4) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total (3) + (4) 12.74% 12.74% 12.74% 12.74% 12.74% 12.74% 12.74%(6) Annualized Costs (2) x (5) $91.15 $106.49 $106.49 $361.06 $1,195.99 $0.00 $40.38(7) Meter O&M Expenses 9.66 17.97 17.97 44.44 611.03 na 14.17(8) Customer Accounts Expenses excl. Uncoll. 29.45 32.08 50.09 45.04 122.76 15.48 26.03(9) Uncollectibles 7.22 9.87 35.13 5.86 24.66 0.59 0.85(10) Customer Service & Informational Expenses 0.48 0.66 2.38 2.61 11.14 0.29 0.38(11) A&G Loading [(7)+(8)+(10)] x 0.0295(Non-plant Related) 1.17 1.50 2.08 2.72 22.00 0.47 1.20(12)Customer-Related Costs(6)+(7)+(8)+(9)+(10)+(11)$139.14 $168.57 $214.13 $461.73 $1,987.58 $16.83 $83.01Working Capital(13) Materials and Supplies (2) x 0.12% * 1.26 1.41 1.41 8.84 14.15 0.00 0.86(14) Prepayments (2) x 0.860% * 9.04 10.07 10.07 63.39 101.38 0.00 6.14(15)Cash Working Capital [(7)+(8)+(10)+(11)] x12.50% 5.10 6.53 9.06 11.85 95.87 2.03 5.22(16) Revenue Requirement for WorkingCapital [(13)+(14)+(15)] x 13.29% $2.05 $2.39 $2.73 $11.17 $28.09 $0.27 $1.62(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $141.18 $170.96 $216.86 $472.90 $2,015.68 $17.10 $84.63Note: In rows with asterisks, adjustments are made to full investment (before CIAC) from next table.33
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 39 of 56Table 22 B. Derivation of Total Annual Meter, Service and Customer-Related Costs –Before CIACSC 1 SC 8 SC 12 SC 2 SC 3 SC 5 SC 6ResidentialResidentialDay NightResidentialTOUGeneralService withDemandPrimaryService(Primary)OutdoorLightingGeneralService--------------------------------------------- (2010 Dollars per Customer) --------------------------------------------(1) (2) (3) (4) (5) (6) (7)(1) Meter and Service Investment $861.84 $960.52 $960.52 $6,043.82 $9,666.78 $0.00 $585.08(2) With General Plant Loading (1) x 1.2195 1,051.01 1,171.36 1,171.36 7,370.44 11,788.64 0.00 713.50(3) Annual Economic Charge Related toCapital Investment 12.74% 12.74% 12.74% 12.74% 12.74% 12.74% 12.74%(4) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total (3) + (4) 12.74% 12.74% 12.74% 12.74% 12.74% 12.74% 12.74%(6) Annualized Costs (2) x (5) $133.91 $149.24 $149.24 $939.08 $1,502.01 $0.00 $90.91(7) Meter O&M Expenses 9.66 17.97 17.97 44.44 611.03 na 14.17(8) Customer Accounts Expenses excl. Uncoll. 29.45 32.08 50.09 45.04 122.76 15.48 26.03(9) Uncollectibles 7.22 9.87 35.13 5.86 24.66 0.59 0.85(10) Customer Service & Informational Expenses 0.48 0.66 2.38 2.61 11.14 0.29 0.38(11) A&G Loading [(7)+(8)+(10)] x 0.0295(Non-plant Related) 1.17 1.50 2.08 2.72 22.00 0.47 1.20(12)Customer-Related Costs(6)+(7)+(8)+(9)+(10)+(11)$181.90 $211.33 $256.89 $1,039.74 $2,293.60 $16.83 $133.54Working Capital(13) Materials and Supplies (2) x 0.12% 1.26 1.41 1.41 8.84 14.15 0.00 0.86(14) Prepayments (2) x 0.860% 9.04 10.07 10.07 63.39 101.38 0.00 6.14(15)Cash Working Capital [(7)+(8)+(10)+(11)] x12.50% 5.10 6.53 9.06 11.85 95.87 2.03 5.22(16) Revenue Requirement for WorkingCapital [(13)+(14)+(15)] x 13.29% 2.05 2.39 2.73 11.17 28.09 0.27 1.62(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $183.94 $213.72 $259.62 $1,050.91 $2,321.69 $17.10 $135.1634
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 40 of 56Table 22 C. Derivation of Annual Meter, Service and Customer-Related Costs – AfterCIACSC 7-1 SC 7-2 SC 7-4 SC 9 SL 1 SL 2 SL 3LGS TOUTransmissionGeneralServiceDay NightSt. LightwithContribProvisionsSt. LightEnergy &LimitedMaint.StandardStreetLightServiceLGS TOUSecondaryLGS TOUPrimary------------------------------------------ (2010 Dollars per Customer) ------------------------------------------(1) (2) (4) (5) (6) (7) (8)(1) Meter & Service Investment $4,648.18 $7,249.61 $90,956.54 $219.44 $0.00 $0.00 $0.00(2) With General Plant Loading (1) x 1.2195 * 6,767.14 9,368.09 110,921.50 354.66 0.00 0.00 0.00(3) Annual Economic Charge Related toCapital Investment 12.74% 12.74% 12.74% 12.74% 12.74% 12.74% 12.74%(4) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total (3) + (4) 12.74% 12.74% 12.74% 12.74% 12.74% 12.74% 12.74%(6) Annualized Costs (2) x (5) $862.21 $1,193.60 $14,132.65 $45.19 $0.00 $0.00 $0.00(7) Meter O&M Expenses 72.48 609.73 7,649.95 16.77 0.00 0.00 0.00(8) Customer Accounts Expenses excl. Uncoll. 123.91 644.68 1,733.09 27.77 22.79 22.79 22.79(9) Uncollectibles 26.02 168.54 469.43 1.25 18.79 18.79 18.79(10) Customer Service & Informational Expenses 11.28 75.03 176.25 0.56 9.25 9.25 9.25(11) A&G Loading [(7)+(8)+(10)] x 0.0295(Non-plant Related) 6.13 39.26 282.32 1.33 0.95 0.95 0.95(12)Customer-Related Costs(6)+(7)+(8)+(9)+(10)+(11)$1,102.03 $2,730.84 $24,443.70 $92.87 $51.78 $51.78 $51.78Working Capital(13) Materials and Supplies (2) x 0.12% * 14.13 14.12 133.11 0.90 0.00 0.00 0.00(14) Prepayments (2) x 0.860% * 101.24 101.22 953.92 6.46 0.00 0.00 0.00(15)Cash Working Capital [(7)+(8)+(10)+(11)] x12.50% 26.73 171.09 1,230.20 5.80 4.12 4.12 4.12(16) Revenue Requirement for WorkingCapital [(13)+(14)+(15)] x 13.29% 18.88 38.07 307.96 1.75 0.55 0.55 0.55(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $1,120.92 $2,768.91 $24,751.66 $94.62 $52.33 $52.33 $52.33Note: In rows with asterisks, adjustments are made to full investment (before CIAC) from next table.35
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 41 of 56Table 22 D. Derivation of Total Annual Meter, Service and Customer-Related Costs –Before CIACSC 7-1 SC 7-2 SC 7-4 SC 9 SL 1 SL 2 SL 3LGS TOUTransmissionGeneralServiceDay NightSt. LightwithContribProvisionsSt. LightEnergy &LimitedMaint.StandardStreetLightServiceLGS TOUSecondaryLGS TOUPrimary------------------------------------------ (2010 Dollars per Customer) ------------------------------------------(1) (2) (4) (5) (6) (7) (8)(1) Meter & Service Investment $9,653.61 $9,651.39 $90,956.54 $616.01 $0.00 $0.00 $0.00(2) With General Plant Loading (1) x 1.2195 11,772.57 11,769.87 110,921.50 751.22 0.00 0.00 0.00(3) Annual Economic Charge Related toCapital Investment 12.74% 12.74% 12.74% 12.74% 12.74% 12.74% 12.74%(4) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%(5) Total (3) + (4) 12.74% 12.74% 12.74% 12.74% 12.74% 12.74% 12.74%(6) Annualized Costs (2) x (5) $1,499.96 $1,499.61 $14,132.65 $95.71 $0.00 $0.00 $0.00(7) Meter O&M Expenses 72.48 609.73 7,649.95 16.77 0.00 0.00 0.00(8) Customer Accounts Expenses excl. Uncoll. 123.91 644.68 1,733.09 27.77 81.82 81.82 81.82(9) Uncollectibles 26.02 168.54 469.43 1.25 18.79 18.79 18.79(10) Customer Service & Informational Expenses 11.28 75.03 176.25 0.56 9.25 9.25 9.25(11) A&G Loading [(7)+(8)+(10)] x 0.0295(Non-plant Related) 6.13 39.26 282.32 1.33 2.69 2.69 2.69(12)Customer-Related Costs(6)+(7)+(8)+(9)+(10)+(11)$1,739.78 $3,036.85 $24,443.70 $143.39 $112.56 $112.56 $112.56Working Capital(13) Materials and Supplies (2) x 0.12% 14.13 14.12 133.11 0.90 0.00 0.00 0.00(14) Prepayments (2) x 0.860% 101.24 101.22 953.92 6.46 0.00 0.00 0.00(15)Cash Working Capital [(7)+(8)+(10)+(11)] x12.50% 26.73 171.09 1,230.20 5.80 11.72 11.72 11.72(16) Revenue Requirement for WorkingCapital [(13)+(14)+(15)] x 13.29% 18.88 38.07 307.96 1.75 1.56 1.56 1.56(17) Total Annual Marginal Customer-RelatedCosts (12) + (16) $1,758.67 $3,074.92 $24,751.66 $145.14 $114.12 $114.12 $114.12Tables 23 and 24 show the annualization of lighting costs for Outdoor Lighting Service andStandard Lighting Service components.36
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 42 of 56Table 23. Derivation of Annual Outdoor Lighting CostsInvestmentper UnitWithGeneralPlantLoadingAnnualEconomicCarryingChargeAnnualizedCost(1) x 1.2195 13.69% (2) x (3)O&MWith A&GLoading (Nonplant)SubtotalMaterials &Supplies &Prepayments(5) x (1+0.0295) (4)+(6) (2) x 0.0098CashWorkingCapital(6) x0.1250RevenueRequirementfor WorkingCapitalTotal AnnualCost per Unit[(8)+(9)] x0.1329 (7)+(10)-------------------------------------------------------------------------------------------- (2010 Dollars per Unit) -------------------------------------------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)(1)(2)(3)Safeguard Luminaires14,500 Nominal Lumen 150 Watt H.P.S. (replacing 7,000 L.175 Watt M.V.)43,000 Nominal Lumen 400 Watt H.P.S. (replacing 17,200L. 400 Watt M.V.)123,000 Nominal Lumen 940 Watt H.P.S. (replacing 48,000L. 1,000 Watt M.V.)$523.43 $638.32 13.69% $87.35 $0.00 $0.00 $87.35 $6.26 $0.00 $0.83 $88.19$583.07 $711.06 13.69% $97.31 $0.00 $0.00 $97.31 $6.97 $0.00 $0.93 $98.23$823.33 $1,004.05 13.69% $137.40 $0.00 $0.00 $137.40 $9.84 $0.00 $1.31 $138.71Area Lights(4) 8,500 Nominal Lumen (100 Watt) H.P.S.*$30.13 $36.75 13.69% $5.03 $0.00 $0.00 $5.03 $0.36 $0.00 $0.05 $5.08(5) 8,500 Nominal Lumen (100 Watt) H.P.S. Power Bracket$568.43 $693.20 13.69% $94.86 $0.00 $0.00 $94.86 $6.79 $0.00 $0.90 $95.77# (6) 14,400 Nominal Lumen (150 Watt) H.P.S.$523.43 $638.32 13.69% $87.35 $0.00 $0.00 $87.35 $6.26 $0.00 $0.83 $88.19# (7) 24,700 Nominal Lumen (250 Watt) H.P.S.$551.35 $672.37 13.69% $92.01 $0.00 $0.00 $92.01 $6.59 $0.00 $0.88 $92.89# (8) 45,000 Nominal Lumen (400 Watt) H.P.S.$583.07 $711.06 13.69% $97.31 $0.00 $0.00 $97.31 $6.97 $0.00 $0.93 $98.23# (9) 126,000 , Nominal Lumen ((1,000 Watt) ) H.P.S.$823.33 $1,004.05 13.69% $137.40 $0.00 $0.00 $137.40 $9.84 $0.00 $1.31 $138.71# (10) Bracket$653.52 $796.96 13.69% $109.06 $0.00 $0.00 $109.06 $7.81 $0.00 $1.04 $110.10# (11) 16,000 Nominal Lumen (250 Watt) Metal Halide$558.05 $680.54 13.69% $93.13 $0.00 $0.00 $93.13 $6.67 $0.00 $0.89 $94.02# (12) 28,000 Nominal Lumen (400 Watt) Metal Halide$582.98 $710.94 13.69% $97.29 $0.00 $0.00 $97.29 $6.97 $0.00 $0.93 $98.22### (13)Flood Lights14,400 Nominal Lumen (150 Watt) H.P.S.$604.71 $737.44 13.69% $100.92 $0.00 $0.00 $100.92 $7.23 $0.00 $0.96 $101.88(14) 24,700 Nominal Lumen (250 Watt) H.P.S$616.63 $751.98 13.69% $102.91 $0.00 $0.00 $102.91 $7.37 $0.00 $0.98 $103.89(15) 45,000 Nominal Lumen (400 Watt) H.P.S.$616.99 $752.43 13.69% $102.97 $0.00 $0.00 $102.97 $7.37 $0.00 $0.98 $103.95(16) 126,000 Nominal Lumen (1,000 Watt) H.P.S.$716.56 $873.84 13.69% $119.59 $0.00 $0.00 $119.59 $8.56 $0.00 $1.14 $120.72(17) 16,000 Nominal Lumen (250 Watt) Metal Halide$614.15 $748.95 13.69% $102.49 $0.00 $0.00 $102.49 $7.34 $0.00 $0.98 $103.47(18) 28,000 Nominal Lumen (400 Watt) Metal Halide$614.16 $748.97 13.69% $102.50 $0.00 $0.00 $102.50 $7.34 $0.00 $0.98 $103.47(19) 88,000 Nominal Lumen (1,000 Watt) Metal Halide$702.13 $856.25 13.69% $117.18 $0.00 $0.00 $117.18 $8.39 $0.00 $1.12 $118.29"Shoebox" Luminaire(20) 14,400 Nominal Lumen (150 Watt) H.P.S.$703.37 $857.75 13.69% $117.38 $0.00 $0.00 $117.38 $8.41 $0.00 $1.12 $118.50(21) 24,700 Nominal Lumen (250 Watt) H.P.S.$706.02 $860.99 13.69% $117.83 $0.00 $0.00 $117.83 $8.44 $0.00 $1.12 $118.95(22) 45,000 Nominal Lumen (400 Watt) H.P.S.$760.21 $927.08 13.69% $126.87 $0.00 $0.00 $126.87 $9.09 $0.00 $1.21 $128.08(23) 16,000 Nominal Lumen (250 Watt) Metal Halide$748.00 $912.18 13.69% $124.83 $0.00 $0.00 $124.83 $8.94 $0.00 $1.19 $126.02(24) 28,000 Nominal Lumen (400 Watt) Metal Halide$736.80 $898.52 13.69% $122.96 $0.00 $0.00 $122.96 $8.81 $0.00 $1.17 $124.13(25) 88,000 Nominal Lumen (1,000 Watt) Metal Halide$843.25 $1,028.34 13.69% $140.73 $0.00 $0.00 $140.73 $10.08 $0.00 $1.34 $142.07Post Tops(26) 5,200 Nominal Lumen (70 Watt) H.P.S.$577.30 $704.01 12.14% $85.46 $0.00 $0.00 $85.46 $6.90 $0.00 $0.92 $86.37(27) 8,500 Nominal Lumen (100 Watt) H.P.S.$583.60 $711.70 12.14% $86.39 $0.00 $0.00 $86.39 $6.97 $0.00 $0.93 $87.31(28) Brackets 16' and over$227.03 $276.87 12.14% $33.61 $0.00 $0.00 $33.61 $2.71 $0.00 $0.36 $33.97# (29) Additional Wood Pole Installed for Lamp$587.64 $716.63 12.14% $86.99 $51.66 $53.19 $140.17 $7.02 $6.65 $1.82 $141.99# (30) Wire Service (Overhead) (Per circuit foot of extension)$1.34 $1.63 $0.2012.14%$0.00$0.00 $0.20 $0.02 $0.00 $0.00 $0.20# (31) 18' Fiberglass Pole - Direct Embedded$553.59 $675.10 12.14% $81.95 $4.61 $4.74 $86.69 $6.62 $0.59 $0.96 $87.65# (32) 20' Fiberglass Pole - Pedestal Mount$553.59 $675.10 12.14% $81.95 $4.61 $4.74 $86.69 $6.62 $0.59 $0.96 $87.65# (33) 20' Metal Pole - Pedestal Mount$830.81 $1,013.17 12.14% $122.98 $26.62 $27.41 $150.39 $9.93 $3.43 $1.77 $152.17# (34) 30' Metal Pole - Pedestal Mount$967.62 $1,180.01 12.14% $143.23 $26.62 $27.41 $170.64 $11.56 $3.43 $1.99 $172.64# (35) 30' Fiberglass Pole - Pedestal Mount$1,429.33 $1,743.07 12.14% $211.58 $4.61 $4.74 $216.32 $17.08 $0.59 $2.35 $218.67# (36) 30' Fiberglass Pole - Direct Embedded$1,429.33 $1,743.07 12.14% $211.58 $4.61 $4.74 $216.32 $17.08 $0.59 $2.35 $218.67# (37) Screw Base for Pedestal Mounted Pole - Light Duty$688.14 $839.19 12.14% $101.86 $0.00 $0.00 $101.86 $8.22 $0.00 $1.09 $102.96# (38) Screw Base for Pedestal Mounted Pole - Heavy Duty$696.56 $849.45 12.14% $103.11 $0.00 $0.00 $103.11 $8.32 $0.00 $1.11 $104.2237
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 43 of 56Table 24. Derivation of Annual Standard Lighting Service CostsInvestmentper UnitWithGeneralPlantLoadingAnnualEconomicCarryingChargeAnnualizedCost(1) x 1.2195 13.69% (2) x (3)O&MWith A&GLoading (Nonplant)Materials &Supplies &PrepaymentsSubtotal(5) x (1+0.0295) (4)+(6) (2) x 0.0098CashWorkingCapital(6) x0.1250RevenueRequirementfor WorkingCapitalTotal AnnualCost per Unit[(8)+(9)] x0.1329 (7)+(10)-------------------------------------------------------------------------------------------- (2010 Dollars per Unit) --------------------------------------------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)High Pressure Sodium Cobra(1) 70 Watts - 5,200 Lumen $530.01 $646.35 13.69% $88.45 $0.00 $0.00 $88.45 $6.33 $0.00 $0.84 $89.30(2) 150 Watts - 14,400 Lumen $538.31 $656.47 13.69% $89.84 $0.00 $0.00 $89.84 $6.43 $0.00 $0.85 $90.69(3) 250 Watts - 24,700 Lumen $565.90 $690.12 13.69% $94.44 $0.00 $0.00 $94.44 $6.76 $0.00 $0.90 $95.34(4) 400 Watts - 45,000 Lumen $598.61 $730.01 13.69% $99.90 $0.00 $0.00 $99.90 $7.15 $0.00 $0.95 $100.85(5) 1000 Watts - 126,000 Lumen $863.09 $1,052.53 13.69% $144.04 $0.00 $0.00 $144.04 $10.31 $0.00 $1.37 $145.41High Pressure Sodium Post Top(6) 50 Watts - 3,300 Lumen $598.94 $730.41 13.69% $99.96 $0.00 $0.00 $99.96 $7.16 $0.00 $0.95 $100.91(7) 70 Watts - 5,200 Lumen $590.93 $720.64 13.69% $98.62 $0.00 $0.00 $98.62 $7.06 $0.00 $0.94 $99.56(8) 150 Watts - 14,400 Lumen $604.08 $736.68 13.69% $100.81 $0.00 $0.00 $100.81 $7.22 $0.00 $0.96 $101.77High Pressure Sodium Cut Off ("Shoebox")(9) 250 Watts - 24,700 Lumen $720.56 $878.73 13.69% $120.25 $0.00 $0.00 $120.25 $8.61 $0.00 $1.14 $121.40(10) 400 Watts - 45,000 Lumen $805.04 $981.74 13.69% $134.35 $0.00 $0.00 $134.35 $9.62 $0.00 $1.28 $135.63Metal Halide Cobra(11) 100 Watts – 5,800 Lumen $591.77 $721.67 13.69% $98.76 $0.00 $0.00 $98.76 $7.07 $0.00 $0.94 $99.70(12) 175 Watts – 12,000 Lumen $568.77 $693.62 13.69% $94.92 $0.00 $0.00 $94.92 $6.80 $0.00 $0.90 $95.83(13) 250 Watts - 16,000 Lumen $566.35 $690.67 13.69% $94.52 $0.00 $0.00 $94.52 $6.77 $0.00 $0.90 $95.42(14) 400 Watts - 28,000 Lumen $642.11 $783.05 13.69% $107.16 $0.00 $0.00 $107.16 $7.67 $0.00 $1.02 $108.18Metal Halide Cut Off (“Shoebox”)(15) 175 Watts – 12,000 Lumen $655.54 $799.44 13.69% $109.40 $0.00 $0.00 $109.40 $7.83 $0.00 $1.04 $110.44(16) 250 Watts - 16,000 Lumen $695.88 $848.62 13.69% $116.13 $0.00 $0.00 $116.13 $8.32 $0.00 $1.11 $117.24(17) 400 Watts - 28, 000 Lumen $752.20 $917.31 13.69% $125.53 $0.00 $0.00 $125.53 $8.99 $0.00 $1.19 $126.73Metal Halide Post Top(18) 70 Watts – 4,000 Lumen $630.82 $769.29 13.69% $105.28 $0.00 $0.00 $105.28 $7.54 $0.00 $1.00 $106.28(19) 100 Watts- 5,800 Lumen $649.85 $792.50 13.69% $108.45 $0.00 $0.00 $108.45 $7.77 $0.00 $1.03 $109.49(20) 175 Watts - 12,000 Lumen $623.63 $760.51 13.69% $104.08 $0.00 $0.00 $104.08 $7.45 $0.00 $0.99 $105.07High Pressure Sodium Special Luminaires(21) 250 Watts - 24,700 - Hiway Liter $1,554.55 $1,895.77 13.69% $259.44 $0.00 $0.00 $259.44 $18.58 $0.00 $2.47 $261.91(22) 400 Watts - 45,000 - Hiway Liter $1,331.91 $1,624.27 13.69% $222.28 $0.00 $0.00 $222.28 $15.92 $0.00 $2.12 $224.40(23) 150 Watts - 14,400 - Turnpike $921.12 $1,123.30 13.69% $153.72 $0.00 $0.00 $153.72 $11.01 $0.00 $1.46 $155.19(24) 250 Watts - 24,700 - Turnpike $933.55 $1,138.47 13.69% $155.80 $0.00 $0.00 $155.80 $11.16 $0.00 $1.48 $157.28(25) 400 Watts - 45,000 - Turnpike $994.48 $1,212.77 13.69% $165.97 $0.00 $0.00 $165.97 $11.89 $0.00 $1.58 $167.55(26) 150 Watts - 14,400 - Floodlight $618.92 $754.78 13.69% $103.29 $0.00 $0.00 $103.29 $7.40 $0.00 $0.98 $104.27(27) 250 Watts - 24,700 - Floodlight $631.18 $769.72 13.69% $105.34 $0.00 $0.00 $105.34 $7.54 $0.00 $1.00 $106.34(28) 400 Watts - 45,000 - Floodlight $631.92 $770.63 13.69% $105.46 $0.00 $0.00 $105.46 $7.55 $0.00 $1.00 $106.46Metal Halide - Floodlights(29) 250 Watts - 16,000 Lumen $654.16 $797.75 13.69% $109.17 $0.00 $0.00 $109.17 $7.82 $0.00 $1.04 $110.21(30) 400 Watts - 28,000 Lumen $629.49 $767.66 13.69% $105.06 $0.00 $0.00 $105.06 $7.52 $0.00 $1.00 $106.05Pole Installed by the Corporation(31) Standard Wood Pole $378.83 $461.99 12.14% $56.08 $51.66 $53.19 $109.26 $4.53 $6.65 $1.49 $110.75(32) Wood Pole - high mount use (45' or greater) $540.94 $659.67 12.14% $80.07 $51.66 $53.19 $133.26 $6.46 $6.65 $1.74 $135.00(33) Aluminum Pole 16' and under $365.16 $445.31 12.14% $54.05 $0.00 $0.00 $54.05 $4.36 $0.00 $0.58 $54.63(34) Alum. Pole over 16' installed prior to August 1, 1987 $581.70 $709.38 12.14% $86.11 $0.00 $0.00 $86.11 $6.95 $0.00 $0.92 $87.03(35) Alum. Pole over 16' direct embedded installed after July 31, 1987 $581.70 $709.38 12.14% $86.11 $0.00 $0.00 $86.11 $6.95 $0.00 $0.92 $87.03(36) Alum. Pole over 16' pedestal mounted $691.82 $843.67 12.14% $102.41 $0.00 $0.00 $102.41 $8.27 $0.00 $1.10 $103.51(37) Fiberglass Pole 18' and under $350.42 $427.34 12.14% $51.87 $4.61 $4.74 $56.61 $4.19 $0.59 $0.64 $57.25(38) Fiberglass Pole 18' to 22' $350.42 $427.34 12.14% $51.87 $4.61 $4.74 $56.61 $4.19 $0.59 $0.64 $57.25Screw-in steel base for pedestal mounted poles:(39) Light Duty $242.73 $296.00 12.14% $35.93 $0.00 $0.00 $35.93 $2.90 $0.00 $0.39 $36.32(40) Heavy Duty $249.75 $304.57 12.14% $36.97 $0.00 $0.00 $36.97 $2.98 $0.00 $0.40 $37.37Special Brackets(41) Standard Bracket - 16' and over $348.00 $424.38 12.14% $51.51 $0.00 $0.00 $51.51 $4.16 $0.00 $0.55 $52.07Circuit Control(42) Group Controllers $587.00 $715.85 12.14% $86.89 $0.00 $0.00 $86.89 $7.02 $0.00 $0.93 $87.82Circuits (Per Trench Foot**)(43) Cable and Conduit $2.31 $2.82 12.14% $0.34 $0.00 $0.00 $0.34 $0.03 $0.00 $0.00 $0.35(44) Direct Burial Cable $1.73 $2.11 12.14% $0.26 $0.00 $0.00 $0.26 $0.02 $0.00 $0.00 $0.26(45) Cable Only (Conduit Supplied by Customer) $1.31 $1.60 12.14% $0.19 $0.00 $0.00 $0.19 $0.02 $0.00 $0.00 $0.20(46) Underground Circuits $2.31 $2.82 12.14% $0.34 $0.00 $0.00 $0.34 $0.03 $0.00 $0.00 $0.3538
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 44 of 56VIII. 2010 SUMMARY TABLES AND EFFICIENT PRICESAnnual marginal upstream substation and distribution substation and trunkline feeder costs weretime-differentiated using the probability of peak analysis described in Section IV.A.2 above. InTable 25 we show these monthly costs, adjusted by losses, for each TOD period, season, andaveraged over the entire year. These costs can also be expressed on a per-kWh basis by dividingby the number of hours in the period, as shown on Table 26 A. Table 26 A also includes the perkWhmarginal transmission costs. Table 26 B shows only the per-kWh transmission costs.Table 25. Summary of Monthly Marginal Upstream Substation, Distribution Substationand Trunkline Feeder Costs per kWSummer Season Winter Season Off SeasonAnnualOn-Peak Shoulder Off-Peak On-Peak Shoulder Off-Peak On-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak--------------------------------------------------------------------------------------- (2010 Dollars per kW per month) ---------------------------------------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12)Residential TOU PeriodsSecondary Service(1) TOD Upstream Dist. $4.86 $0.54 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $2.47 $0.11 $0.00(2) Dist. Substation $5.94 $0.66 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $3.02 $0.13 $0.00$10.80 $1.20 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $5.49 $0.24 $0.00(3) Seasonal Upstream Dist. $5.41 $0.00 $0.00(4) Dist. Substation $6.60 $0.00 $0.00$12.00 $0.00 $0.00(5) Annual Upstream Dist. $1.35(6) Dist. Substation $1.65$3.00LGS TOU PeriodsTransmission Service(7) TOD $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 0.00 0.00(8) Seasonal $0.00 $0.00 $0.00(9) Annual $0.00Primary Service(10) TOD Upstream Dist. $5.11 $0.05 $0.00 $0.00 $0.00 $0.00 $1.13 $0.01(11) Dist. Substation $6.23 $0.06 $0.00 $0.00 $0.00 $0.00 1.38 0.02$11.34 $0.11 $0.00 $0.00 $0.00 $0.00 $2.51 $0.03(12) Seasonal Upstream Dist. $5.16 $0.00 $0.00(13) Dist. Substation $6.29 $0.00 $0.00$11.45 $0.00 $0.00(14) Annual Upstream Dist. $1.29(15) Dist. Substation $1.57$2.86Secondary Service(16) TOD Upstream Dist. $5.35 $0.05 $0.00 $0.00 $0.00 $0.00 $1.18 $0.01(17) Dist. Substation $6.54 $0.06 $0.00 $0.00 $0.00 $0.00 $1.44 $0.02$11.89 $0.11 $0.00 $0.00 $0.00 $0.00 $2.63 $0.03(18) Seasonal Upstream Dist. $5.41 $0.00 $0.00(19) Dist. Substation $6.60 $0.00 $0.00$12.00 $0.00 $0.00(20) Annual Upstream Dist. $1.35(21) Dist. Substation $1.65$3.00Day Night PeriodsSecondary Service(22) TOD Upstream Dist. $5.41 $0.00 $0.00 $0.00 $0.00 $0.00 $1.36 $0.00(23) Dist. Substation $6.60 $0.00 $0.00 $0.00 $0.00 $0.00 1.66 0.00$12.00 $0.00 $0.00 $0.00 $0.00 $0.00 $3.03 $0.00(24) Seasonal Upstream Dist. $5.41 $0.00 $0.00(25) Dist. Substation $6.60 $0.00 $0.00$12.00 $0.00 $0.00(26) Annual Upstream Dist. $1.35(27) Dist. Substation $1.65$3.0039
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 45 of 56Table 26 A. Summary of Marginal Transmission, Upstream Substation, DistributionSubstation and Trunkline Feeder Costs, on a per-kWh BasisSummer Season Winter Season Off SeasonAnnualOn-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak----------------------------------------------------------------------------------------------- (2010 Dollars per kWh) ----------------------------------------------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12)Residential TOU PeriodsSecondary Service(1) TOD Transmission $0.00382 $0.00378 $0.00372 $0.00382 $0.00379 $0.00375 $0.00377 $0.00371 $0.00382 $0.00378 $0.00372(2) Upstream Dist. $0.02806 $0.00163 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.01426 $0.00033 $0.00000(3) Dist. Substation $0.03425 $0.00199 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.01741 $0.00040 $0.00000$0.06612 $0.00740 $0.00372 $0.00382 $0.00379 $0.00375 $0.00377 $0.00371 $0.03549 $0.00450 $0.00372(4) Seasonal Transmission $0.00377 $0.00379 $0.00375(5) Upstream Dist. $0.00734 $0.00000 $0.00000(6) Dist. Substation $0.00896 $0.00000 $0.00000$0.02008 $0.00379 $0.00375(7) Annual Transmission $0.00376(8) Upstream Dist. $0.00185(9) Dist. Substation $0.00226$0.00788LGS TOU PeriodsTransmission Service(10) TOD Transmission $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352(11) Seasonal Transmission $0.00352 $0.00352 $0.00352(12) Annual Transmission $0.00352Primary Service(13) TOD Transmission $0.00376 $0.00370 $0.00376 $0.00372 $0.00373 $0.00369 $0.00375 $0.00370(14) Upstream Dist. $0.01572 $0.00012 $0.00000 $0.00000 $0.00000 $0.00000 $0.00347 $0.00003(15) Dist. Substation $0.01918 $0.00014 $0.00000 $0.00000 $0.00000 $0.00000 $0.00424 $0.00004$0.03865 $0.00397 $0.00376 $0.00372 $0.00373 $0.00369 $0.01146 $0.00377(16) Seasonal Transmission $0.00373 $0.00375 $0.00371(17) Upstream Dist. $0.00701 $0.00000 $0.00000(18) Dist. Substation $0.00855 $0.00000 $0.00000$0.01928 $0.00375 $0.00371(19) Annual Transmission $0.00372(20) Upstream Dist. $0.00177(21) Dist. Substation $0.00216$0.00764Secondary Service(22) TOD Transmission $0.00381 $0.00374 $0.00381 $0.00376 $0.00378 $0.00373 $0.00379 $0.00374(23) Upstream Dist. $0.01648 $0.00012 $0.00000 $0.00000 $0.00000 $0.00000 $0.00364 $0.00004(24) Dist. Substation $0.02011 $0.00015 $0.00000 $0.00000 $0.00000 $0.00000 $0.00444 $0.00004$0.04039 $0.00402 $0.00381 $0.00376 $0.00378 $0.00373 $0.01188 $0.00381(25) Seasonal Transmission $0.00377 $0.00380 $0.00375(26) Upstream Dist. $0.00734 $0.00000 $0.00000(27) Dist. Substation $0.00896 $0.00000 $0.00000$0.02008 $0.00380 $0.00375(28) Annual Transmission $0.00377(29) Upstream Dist. $0.00185(30) Dist. Substation $0.00226$0.00788Day Night PeriodsSecondary Service(31) TOD Transmission $0.00380 $0.00372 $0.00380 $0.00375 $0.00377 $0.00371 $0.00378 $0.00372(32) Upstream Dist. $0.01068 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00269 $0.00000(33) Dist. Substation $0.01304 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00329 $0.00000$0.02752 $0.00372 $0.00380 $0.00375 $0.00377 $0.00371 $0.00976 $0.00372(34) Seasonal Transmission $0.00377 $0.00379 $0.00375(35) Upstream Dist. $0.00734 $0.00000 $0.00000(36) Dist. Substation $0.00896 $0.00000 $0.00000$0.02008 $0.00379 $0.00375(37) Annual Transmission $0.00377Upstream Dist. $0.00185Dist. Substation $0.00226$0.0078840
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 46 of 56Table 26 B. Summary of Marginal Transmission Costs per-kWhSummer Season Winter Season Off SeasonAnnualOn-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak--------------------------------------------------------------------------------------------- (2010 Dollars per kWh) ---------------------------------------------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12)LOSS ADJUSTED MARGINAL TRANSMISSION COSTSResidential TOU (SC 12) PeriodsSecondary Service(1) TOD $0.00382 $0.00378 $0.00372 $0.00382 $0.00379 $0.00375 $0.00377 $0.00371 $0.00382 $0.00378 $0.00372(2) Seasonal $0.00377 $0.00379 $0.00375(3) Annual $0.00376LGS TOU (SC 7) PeriodsTransmission Service(4) TOD $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352(5) Seasonal $0.00352 $0.00352 $0.00352(6) Annual $0.00352Primary Service(7) TOD $0.00376 $0.00370 $0.00376 $0.00372 $0.00373 $0.00369 $0.00375 $0.00370(8) Seasonal $0.00373 $0.00375 $0.00371(9) Annual $0.00372Secondary Service(10) TOD $0.00381 $0.00374 $0.00381 $0.00376 $0.00378 $0.00373 $0.00379 $0.00374(11) Seasonal $0.00377 $0.00380 $0.00375(12) Annual $0.00377Day-Night (SC 8 & 9) PeriodsSecondary Service(13) TOD $0.00380 $0.00372 $0.00380 $0.00375 $0.00377 $0.00371 $0.00378 $0.00372(14) Seasonal $0.00377 $0.00379 $0.00375(15) Annual $0.00377Note: Based on average TSC charges from Aug-Dec, 2007 and Jan-Jul, 2009, from NYISO website.Table 27 A summarizes monthly marginal customer-related and local distribution facilities costsper kW of design demand and on a per customer basis, by service classification. The monthlycosts on this table exclude the portion of paid for upfront in customer contributions. Table 27 Bshows the same marginal cost components, but includes all costs.41
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 47 of 56Table 27 A. Summary of Monthly Marginal Customer and Local Distribution FacilitiesCosts (after CIAC payments)MonthlyMonthly Distribution MonthlyDistribution Typical Facilities Marginal TotalFacilities Marginal Design Cost per Customer MonthlyCustomer Class Unit Costs Demand Customer Unit Costs Costs(2010 $/kW/Month) (kW) (2010 $/Month) (2010 $/Month) (2010 $/Month)(1) x (2) (3) + (4)(1) (2) (3) (4) (5)(1) SC 1 Residential Service $9.20 4.00 36.80 $11.77 $48.57(2) SC 8 Residential Service Day Night Service $9.20 4.00 36.80 $14.25 $51.05(3) SC 12 Residential Service with Time-of-Use Metering $9.20 10.00 92.00 $18.07 $110.07(4) SC 2 General Service with Demand Metering $6.11 24.00 146.64 $39.41 $186.05(5) SC 3 Primary Service - 25 kW or more - Primary $3.18 102.00 324.36 $167.97 $492.33(6) SC5 Outdoor Lighting Service NA NA NA $1.42 $1.42(7) SC 6 General Service $8.78 5.00 43.90 $7.05 $50.95(8) SC 7-1 LGS with TOU Metering - Secondary $2.29 83.00 190.07 $93.41 $283.48(9) SC 7-2 LGS with TOU - Primary $3.18 733.00 2,330.94 $230.74 $2,561.68(10) SC 7-4 LGS with TOU Metering - Transmission NA NA NA $2,062.64 $2,062.64(11) SC 9 General Service - Day Night Service $8.78 5.00 43.90 $7.88 $51.78(12) SL 1 Street Lighting - Contributory Provisions NA NA NA $4.36 $4.36(13) SL 2 Street Lighting - Energy and Limited Maintenance NA NA NA $4.36 $4.36(14) SL 3 Standard Street Lighting Service NA NA NA $4.36 $4.36Table 27 B. Summary of Total Monthly Marginal Customer and Local DistributionFacilities Costs (total before CIAC payments)MonthlyMonthly Distribution MonthlyDistribution Typical Facilities Marginal TotalFacilities Marginal Design Cost per Customer MonthlyCustomer Class Unit Costs Demand Customer Unit Costs Costs(2010 $/kW/Month) (kW) (2010 $/Month) (2010 $/Month) (2010 $/Month)(1) x (2) (3) + (4)(1) (2) (3) (4) (5)(1) SC 1 Residential Service $11.31 4.00 45.24 $15.33 $60.57(2) SC 8 Residential Service Day Night Service $11.31 4.00 45.24 $17.81 $63.05(3) SC 12 Residential Service with Time-of-Use Metering $11.31 10.00 113.10 $21.63 $134.73(4) SC 2 General Service with Demand Metering $7.99 24.00 191.76 $87.58 $279.34(5) SC 3 Primary Service - 25 kW or more - Primary $3.18 102.00 324.36 $193.47 $517.83(6) SC5 Outdoor Lighting Service na na na $1.42 $1.42(7) SC 6 General Service $10.61 5.00 53.05 $11.26 $64.31(8) SC 7-1 LGS with TOU Metering - Secondary $2.29 83.00 190.07 $146.56 $336.63(9) SC 7-2 LGS with TOU - Primary $3.18 733.00 2,330.94 $256.24 $2,587.18(10) SC 7-4 LGS with TOU Metering - Transmission na na na $2,062.64 $2,062.64(11) SC 9 General Service - Day Night Service $10.61 5.00 53.05 $12.10 $65.15(12) SL 1 Street Lighting - Contributory Provisions na na na $9.51 $9.51(13) SL 2 Street Lighting - Energy and Limited Maintenance na na na $9.51 $9.51(14) SL 3 Standard Street Lighting Service na na na $9.51 $9.5142
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 48 of 56Tables 28 - 30 summarize monthly lighting costs per unit.Table 28. Summary of Monthly Marginal Outdoor Lighting Cost per ComponentComponentMonthly MarginalCost Per Unit(2010 Dollars per Unit)Safeguard Luminaires(1) 14,500 Nominal Lumen 150 Watt H.P.S. (replacing 7,000 L. 175 Watt M.V.) $7.35(2) 43,000 Nominal Lumen 400 Watt H.P.S. (replacing 17,200 L. 400 Watt M.V.) $8.19(3) 123,000 Nominal Lumen 940 Watt H.P.S. (replacing 48,000 L. 1,000 Watt M.V.) $11.56Area Lights(4) 8,500 Nominal Lumen (100 Watt) H.P.S.* $0.42(5) 8,500 Nominal Lumen (100 Watt) H.P.S. Power Bracket $7.98(6) 14,400 Nominal Lumen (150 Watt) H.P.S. $7.35(7) 24,700 Nominal Lumen (250 Watt) H.P.S. $7.74(8) 45,000 Nominal Lumen (400 Watt) H.P.S. $8.19(9) 126,000 Nominal Lumen (1,000 Watt) H.P.S. $11.56(10) 10,500 Nominal Lumen (175 Watt) Metal Halide Power Bracket $9.18(11) 16,000 Nominal Lumen (250 Watt) Metal Halide $7.83(12) 28,000 Nominal Lumen (400 Watt) Metal Halide $8.18Flood Lights(13) 14,400 Nominal Lumen (150 Watt) H.P.S. $8.49(14) 24,700 Nominal Lumen (250 Watt) H.P.S $8.66(15) 45,000 Nominal Lumen (400 Watt) H.P.S. $8.66(16) 126,000 Nominal Lumen (1,000 Watt) H.P.S. $10.06(17) 16,000 Nominal Lumen (250 Watt) Metal Halide $8.62(18) 28,000 Nominal Lumen (400 Watt) Metal Halide $8.62(19) 88,000 Nominal Lumen (1,000 Watt) Metal Halide $9.86"Shoebox" Luminaire(20) 14,400 Nominal Lumen (150 Watt) H.P.S. $9.88(21) 24,700 Nominal Lumen (250 Watt) H.P.S. $9.91(22) 45,000 Nominal Lumen (400 Watt) H.P.S. $10.67(23) 16,000 Nominal Lumen (250 Watt) Metal Halide $10.50(24) 28,000 Nominal Lumen (400 Watt) Metal Halide $10.34(25) 88,000 Nominal Lumen (1,000 Watt) Metal Halide $11.84Post Tops(26) 5,200 Nominal Lumen (70 Watt) H.P.S. $7.20(27) 8,500 Nominal Lumen (100 Watt) H.P.S. $7.28(28) Brackets 16' and over $2.83(29) Additional Wood Pole Installed for Lamp $11.83(30) Wire Service (Overhead) (Per circuit foot of extension) $0.02(31) 18' Fiberglass Pole - Direct Embedded $7.30(32) 20' Fiberglass Pole - Pedestal Mount $7.30(33) 20' Metal Pole - Pedestal Mount $12.68(34) 30' Metal Pole - Pedestal Mount $14.39(35) 30' Fiberglass Pole - Pedestal Mount $18.22(36) 30' Fiberglass Pole - Direct Embedded $18.22(37) Screw Base for Pedestal Mounted Pole - Light Duty $8.58(38) Screw Base for Pedestal Mounted Pole - Heavy Duty $8.6843
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 49 of 56Table 29. Summary of Monthly Marginal Standard Lighting Service Cost per ComponentComponentMonthly MarginalCost Per Unit(2010 Dollars per Unit)High Pressure Sodium Cobra(1) 70 Watts - 5,200 Lumen $7.44(2) 150 Watts - 14,400 Lumen $7.56(3) 250 Watts - 24,700 Lumen $7.95(4) 400 Watts - 45,000 Lumen $8.40(5) 1000 Watts - 126,000 Lumen $12.12High Pressure Sodium Post Top(6) 50 Watts - 3,300 Lumen $8.41(7) 70 Watts - 5,200 Lumen $8.30(8) 150 Watts - 14,400 Lumen $8.48High Pressure Sodium Cut Off ("Shoebox")(9) 250 Watts - 24,700 Lumen $10.12(10) 400 Watts - 45,000 Lumen $11.30Metal Halide Cobra(11) 100 Watts – 5,800 Lumen $8.31(12) 175 Watts – 12,000 Lumen $7.99(13) 250 Watts - 16,000 Lumen $7.95(14) 400 Watts - 28,000 Lumen $9.02Metal Halide Cut Off (“Shoebox”)(15) 175 Watts – 12,000 Lumen $9.20(16) 250 Watts - 16,000 Lumen $9.77(17) 400 Watts - 28, 000 Lumen $10.56Metal Halide Post Top(18) 70 Watts – 4,000 Lumen $8.86(19) 100 Watts- 5,800 Lumen $9.12(20) 175 Watts - 12,000 Lumen $8.76High Pressure Sodium Special Luminaires(21) 250 Watts - 24,700 - Hiway Liter $21.83(22) 400 Watts - 45,000 - Hiway Liter $18.70(23) 150 Watts - 14,400 - Turnpike $12.93(24) 250 Watts - 24,700 - Turnpike $13.11(25) 400 Watts - 45,000 - Turnpike $13.96(26) 150 Watts - 14,400 - Floodlight $8.69(27) 250 Watts - 24,700 - Floodlight $8.86(28) 400 Watts - 45,000 - Floodlight $8.87Metal Halide - Floodlights(29) 250 Watts - 16,000 Lumen $9.18(30) 400 Watts - 28,000 Lumen $8.84Pole Installed by the Corporation(31) Standard Wood Pole $9.23(32) Wood Pole - high mount use (45' or greater) $11.25(33) Aluminum Pole 16' and under $4.55(34) Alum. Pole over 16' installed prior to August 1, 1987 $7.25(35) Alum. Pole over 16' direct embedded installed after July 31, 1987 $7.25(36) Alum. Pole over 16' pedestal mounted $8.63(37) Fiberglass Pole 18' and under $4.77(38) Fiberglass Pole 18' to 22' $4.77Screw-in steel base for pedestal mounted poles:(39) Light Duty $3.03(40) Heavy Duty $3.11Special Brackets(41) Standard Bracket - 16' and over $4.34Circuit Control(42) Group Controllers $7.32Circuits (Per Trench Foot**)(43) Cable and Conduit $0.03(44) Direct Burial Cable $0.02(45) Cable Only (Conduit Supplied by Customer) $0.02(46) Underground Circuits $0.0344
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 50 of 56Table 30. Summary of Monthly Relamping Expense per ComponentLamp TypeMonthly Costper Unit(2010 Dollars per Unit)High Pressure Sodium50 Watts - 3,300 Lumen $1.4470 Watts - 5,200 Lumen $1.44100 Watts - 8,500 Lumen $1.48150 Watts - 14,400 Lumen $1.49250 Watts - 24,700 Lumen $1.49400 Watts - 45,000 Lumen $1.51940 Watts - 123,000 Lumen $1.921000 Watts - 126,000 Lumen $1.92Metal Halide70 Watts – 4,000 Lumen $1.69100 Watts - 5,800 Lumen $2.01175 Watts - 10,500 or 12,000 Lumen $1.50250 Watts - 16,000 Lumen $1.50400 Watts - 28,000 Lumen $1.511000 Watts - 88,000 Lumen $1.68Mercury Vapor100 Watts - 3,200 Lumen $1.54175 Watt - 7,000 Lumen $1.54250 Watts - 9,400 Lumen $1.54400 Watts - 17,200 Lumen $1.541000 Watts - 48,000 Lumen $1.54Efficient rates would mirror the structure of NYSEG’s marginal costs and have charges for eachrate component set equal to marginal cost. Efficient rate designs for NYSEG’s electric deliveryservice customers consist of a fixed monthly customer charge, a monthly facilities charge basedon kW of design demand (perhaps based on annual peak demand), and time-differentiatedcharges based on monthly use. The upstream substation and distribution substation and trunklinefeeder costs could be recovered either in a demand charge (using the per kW costs in Table 25)or combined with marginal transmission costs in time-differentiated energy charges (using theper kWh costs in Table 26). There is clear seasonality to the non-local-facilities distribution andtransmission marginal costs, so even customers without time-of-day meters would see moreefficient prices if these cost components were seasonally differentiated. Of course rates set equalto these marginal costs would not produce match NYSEG’s revenue requirement. Someadjustment would be necessary.The next set of tables compares current charges to efficient prices equal to marginal cost for eachservice classification using current rate designs. Again, adjustment would be necessary toproduce the target revenue requirement.45
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 51 of 56Table 31 A. Marginal Costs Compared to Current Rates (Non-Lighting)Current RatesMarginal CostsService Classification"Total"CustomerChargeDemandDelivery withoutSBCRKVAHCustomerand FacilitiesCost afterCIAC Demand DeliveryDeliveryCosts by TOD($/month) ($/kw /mo) ($/kwh) ($/rkvah)(2010$/month)(2010$/kw/mo) ----- (2010$/kWh) ---------SC 1 All $14.00 $0.0347 $48.57 $0.00788SC 8 Day $0.0359 $0.00976$16.29$51.05Night $0.0171 $0.00372SC 12 On $0.0716 $0.03549Mid $23.00$0.0328 $110.07$0.00450Off $0.0171 $0.00372SC 6 All $15.49 $0.0378 $50.95 $0.00788SC 9 Day $0.0398 $0.00976$18.14$51.78Night $0.0191 $0.00372SC 2 All Blocks $14.00 $8.00 $0.00416 $0.00095 $186.05 $3.00 $0.00376SC 2, 6 and 9 Space Heating All Blocks $0.01361See marginal costs under SC 2, 6 and 9SC 2 I/HLF All Blocks $14.00 $2.30 $0.00102 $0.00095 $186.05 $3.00 $0.00376SC 7-1 On $8.60 $0.00153 $0.00095 $3.00 $0.00379$30.00$283.48Off $0.00153 $0.00374SC 7-1 I/HLF On $3.67 $0.00137 $0.00095 $3.00 $0.00379$30.00$283.48Off $0.00137 $0.00374SC 3P All Blocks $60.00 $4.60 $0.00409 $0.00095 $492.33 $2.86 $0.00372SC 3P I/HLF All Blocks $60.00 $1.84 $0.00151 $0.00095 $492.33 $2.86 $0.00372SC 7-2 On $7.50 $0.00262 $0.00095 $2.86 $0.00375$210.00$2,561.68Off $0.00262 $0.00370SC 7-2 I/HLF On $2.97 $0.00236 $0.00095 $2.86 $0.00375$210.00$2,561.68Off $0.00236 $0.00370SC 3S All Blocks $200.00 $3.75 $0.00265 $0.00095 NA NA NASC 3S I/HLF All Blocks $200.00 $1.74 $0.00149 $0.00095 NA NA NASC 7-3 I/HLF On$320.00$0.25 $0.00192 $0.00095 NA NA NAOff $0.00192 NASC 7-4 On$850.00$1.73 $0.00212 $0.00095$2,062.64$0.00 $0.00352Off $0.00212 $0.00352SC 7-4 I/HLF On $0.00 $0.00157 $0.00095 $0.00 $0.00352$850.00$2,062.64Off $0.00157 $0.00352Table 31 B. Marginal Costs Compared to Current Rates (Lighting Delivery and FixedChargesCurrent RatesMarginal CostsService ClassificationDelivery withoutSBC (per kWh)Bill IsuanceChargeDelivery(2010$ perkWh)Customer Charge(2010 $ per month)SC 5 (Outdoor) $0.02500 $0.0079 $1.42SC 1 (Street Lighting) 0.02500 0.89 $0.0079 $4.36SC 2 (Street Lighting) 0.02500 0.89 $0.0079 $4.36SC 3 (Street Lighting) 0.02500 0.89 $0.0079 $4.3646
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 52 of 56Table 31 C. Marginal Costs Compared to Current Rates (SC1 and SC2 O&M Charges)Current RatesMarginal CostsLumen WattsMonthlyO&M ChargeMonthlyRelamping($ per light) (2010$ per light)Street Lighting SC-1High Pressure Sodium 3,300 50 $2.57 $1.44High Pressure Sodium 5,200 70 $2.61 $1.44High Pressure Sodium 8,500 100 $2.61 $1.49High Pressure Sodium 14,400 150 $2.61 $1.49High Pressure Sodium 24,700 250 $2.61 $1.51High Pressure Sodium 45,000 400 $2.61 $1.92High Pressure Sodium 126,000 1,000 $3.72 $1.92Metal Halide 16,000 250 $2.86 $1.50Metal Halide 28,000 400 $2.86 $1.51Mercury Vapor 3,200 100 $2.26 $1.54Mercury Vapor 7,000 175 $2.26 $1.54Mercury Vapor 9,400 250 $2.26 $1.54Mercury Vapor 17,200 400 $2.26 $1.54Mercury Vapor 48,000 1,000 $2.54 $1.54Street Lighting SC-2 (customer-owned equipment)High Pressure Sodium 3,300 50 $1.17 $1.44High Pressure Sodium 5,200 70 $1.17 $1.44High Pressure Sodium 8,500 100 $1.18 $1.49High Pressure Sodium 14,400 150 $1.18 $1.49High Pressure Sodium 19,800 200 $1.19 $1.49High Pressure Sodium 24,700 250 $1.20 $1.49High Pressure Sodium 45,000 400 $1.22 $1.51High Pressure Sodium 126,000 1,000 $2.30 $1.92Mercury Vapor 3,200 100 $0.80 $1.54Mercury Vapor 7,000 175 $0.82 $1.54Mercury Vapor 9,400 250 $0.84 $1.54Mercury Vapor 17,200 400 $0.88 $1.54Mercury Vapor 48,000 1,000 $1.12 $1.54Incandescent 4,000 327 $2.78 $1.44Flourescent 5,000 95 $1.46 $1.44Flourescent 10,000 235 $1.59 $1.49Flourescent 20,000 380 $1.83 $1.49Metal Hallide 4,000 70 $2.37 $8.86Metal Hallide 5,800 100 $2.37 $8.31Metal Hallide 12,000 175 $2.37 $7.99Metal Hallide 16,000 250 $2.39 $7.95Metal Hallide 28,000 400 $2.44 $9.02Metal Hallide 88,000 1000 $3.96 na47
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 53 of 56Table 31 D. Marginal Costs Compared to Current Rates (SC 3 Fixture Charges)Street Lighting SC-3Current Monthly Luminaire ChargeMonthly Marginal CostsCut Off /Cut Off / MonthlyLumen Watts Cobra Post Top Shoebox Cobra Post Top Shoebox Relamping------------------- ($ per light) ------------------ ------------------------ (2010 $ per light) -----------------------High Pressure Sodium 3,300 50 $6.60 $7.62 n.a. $8.41 $1.44High Pressure Sodium 5,200 70 $6.60 $7.62 $13.37 $7.44 $8.30 na $1.44High Pressure Sodium 8,500 100 $6.60 $8.65 $13.37 $7.48 $8.39 na $1.49High Pressure Sodium 14,400 150 $6.60 $9.68 $13.37 $7.56 $8.48 na $1.49High Pressure Sodium 24,700 250 $6.60 $9.68 $11.80 $7.95 na $10.12 $1.51High Pressure Sodium 45,000 400 $6.98 $10.05 $14.27 $8.40 na $11.30 $1.92High Pressure Sodium 126,000 1,000 $10.34 $13.42 $12.12 na $1.92Metal Halide 4,000 70 $4.56 $8.86 $1.69Metal Halide 5,800 100 $4.03 $4.63 $8.31 $9.12 $2.01Metal Halide 12,000 175 $3.98 $4.70 $5.48 $7.99 $8.76 $9.20 $1.50Metal Halide 16,000 250 $12.84 $15.75 $7.95 $9.77 $1.50Metal Halide 28,000 400 $12.84 $16.56 $9.02 $10.56 $1.51Mercury Vapor 3,200 100 $3.61 $4.66 $7.44 $8.30 $1.54Mercury Vapor 7,000 175 $3.61 $4.70 $8.31 $9.12 $1.54Mercury Vapor 9,400 250 $3.76 $4.75 $7.48 $8.39 $1.54Mercury Vapor 17,200 400 $3.82 $4.82 $7.95 $8.48 $1.54Mercury Vapor 48,000 1,000 $5.60 $6.59 $12.12 $8.48 $1.54Incandescent 1,000 103 $5.09 $5.74 na $8.41 $1.44Fluorescent 5,000 95 $6.69 $7.44 $1.44Fluorescent 10,000 235 $6.83 $7.48 $1.49Fluorescent 20,000 380 $7.58 $7.56 $1.4948
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 54 of 56Table 31 E. Marginal Costs Compared to Current Rates (SC 3 Circuit Charges)Current Rates Marginal CostStreet Lighting SC-3Monthly FacilityChargeMonthly FacilitiesCost($ per unit) (2010 $ per unit)Pole Installed by the CorporationStandard Wood Pole $9.92 $9.23Wood Pole - high mount use (45' or greater) 27.15 11.25Steel Pole 4.39 8.63Square Steel Pole 30' 15.95 8.63Aluminum Pole 16' and under 5.98 4.55Alum. Pole over 16' installed prior to August 1, 1987 15.87 7.25Alum. Pole over 16' direct embedded installed after July 31, 1987 15.87 7.25Alum. Pole over 16' pedestal mounted 23.7 8.63Concrete Pole 4.99 4.77Laminated Wood Pole 3.99 4.77Fiberglass Pole 18' and under 5.57 4.77Fiberglass Pole 18' to 22' 7.58 4.77Concrete Base for pedestal mounted poles 21.05 3.11Screw-in steel base for pedestal mounted poles:Light Duty 13.05 3.03Heavy Duty 16.61 3.11Special BracketsStandard Bracket - 16' and over $2.34 4.34Bracket allowance (0.62) naBracket for post-top use on wood poles 0.4 4.34Circuit ControlGroup Controllers $2.99 7.323000 Watt Photo Cell 1.99 7.32Circuits (Per Trench Foot**)Cable and Conduit $0.08 0.03Direct Burial Cable 0.0666 0.02Cable Only (Conduit Supplied by Customer) 0.0355 0.02Underground Circuits 0.0473 0.0349
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 55 of 56Table 31 F. Marginal Costs Compared to Current Rates (SC 5 Charges)Marginal Monthly CostNYSEG Street Lighting SC-5Current Rates(Monthly)(excluding Lamp andPhoto Eye)($ per unit) ($ per unit)Safeguard Luminaires14,500 Nominal Lumen 150 Watt H.P.S. (replacing 7,000 L. 175 Watt M.V.) $5.89 $7.3543,000 Nominal Lumen 400 Watt H.P.S. (replacing 17,200 L. 400 Watt M.V.) 8.65 8.19123,000 Nominal Lumen 940 Watt H.P.S. (replacing 48,000 L. 1,000 Watt M.V.) 7.17 11.56Area Lights3,300 Nominal Lumen (50 Watt) H.P.S.* (PACKLITE) 3.20 7.985,200 Nominal Lumen (70 Watt) H.P.S.* (PACKLITE) 3.15 7.988,500 Nominal Lumen (100 Watt) H.P.S.* 3.12 5.083,200 Nominal Lumen (100 Watt) Mercury (PACKLITE)* 3.03 9.188,500 Nominal Lumen (100 Watt) H.P.S. Power Bracket 6.57 7.9814,400 Nominal Lumen (150 Watt) H.P.S. 10.83 7.3524,700 Nominal Lumen (250 Watt) H.P.S. 10.62 7.7445,000 Nominal Lumen (400 Watt) H.P.S. 10.38 8.19126,000 Nominal Lumen (1,000 Watt) H.P.S. 9.68 11.5610,500 Nominal Lumen (175 Watt) Metal Halide Power Bracket 4.47 9.1816,000 Nominal Lumen (250 Watt) Metal Halide 11.51 7.8328,000 Nominal Lumen (400 Watt) Metal Halide 11.36 8.18Flood Lights14,400 Nominal Lumen (150 Watt) H.P.S. 11.55 8.4924,700 Nominal Lumen (250 Watt) H.P.S 11.35 8.6645,000 Nominal Lumen (400 Watt) H.P.S. 11.15 8.66126,000 Nominal Lumen (1,000 Watt) H.P.S. 12.42 10.0616,000 Nominal Lumen (250 Watt) Metal Halide 10.76 8.6228,000 Nominal Lumen (400 Watt) Metal Halide 11.86 8.6288,000 Nominal Lumen (1,000 Watt) Metal Halide 12.37 9.86"Shoebox" Luminaire14,400 Nominal Lumen (150 Watt) H.P.S. 12.20 9.8824,700 Nominal Lumen (250 Watt) H.P.S. 14.39 9.9145,000 Nominal Lumen (400 Watt) H.P.S. 15.26 10.6716,000 Nominal Lumen (250 Watt) Metal Halide 11.53 10.5028,000 Nominal Lumen (400 Watt) Metal Halide 11.37 10.3488,000 Nominal Lumen (1,000 Watt) Metal Halide 16.37 11.84Post Tops3,300 Nominal Lumen (50 Watt) H.P.S. 8.87 7.205,200 Nominal Lumen (70 Watt) H.P.S. 8.87 7.208,500 Nominal Lumen (100 Watt) H.P.S. 8.85 7.28Brackets 16' and over 2.17 2.83Additional Wood Pole Installed for Lamp 11.08 11.83Wire Service (Overhead) (Per circuit foot of extension) 0.031 0.0218' Fiberglass Pole - Direct Embedded 11.44 7.3020' Fiberglass Pole - Pedestal Mount 39.73 7.3020' Metal Pole - Pedestal Mount 39.73 12.6830' Metal Pole - Pedestal Mount 39.73 14.3930' Fiberglass Pole - Pedestal Mount 39.73 18.2230' Fiberglass Pole - Direct Embedded 17.40 18.22Screw Base for Pedestal Mounted Pole - Light Duty 12.1 8.58Screw Base for Pedestal Mounted Pole - Heavy Duty 15.44 8.6850
Exhibit __ (NYSEGHP-2) <strong>Rebuttal</strong>Page 56 of 56NERA Economic ConsultingSuite 1950Los Angeles, California 90017Tel: +1 213 346 3000Fax: +1 213 346 3030www.nera.com51
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 1 of 38February 8, 2010RG&EMarginal Cost of Gas Delivery Service StudyPrepared for:Rochester Gas & Electric
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 2 of 38Project Team<strong>Hethie</strong> ParmesanoAmparo NietoWilliam RankinJordan NarducciNicholas AmabileNERA Economic Consulting777 South Figueroa Street, Suite 1950Los Angeles, California 90017Tel: +1 213 346 3000Fax: +1 213 346 3030www.nera.com
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 3 of 38ContentsI. INTRODUCTION........................................................................................................................1II. MARGINAL HIGH-PRESSURE AND UPPER MEDIUM-PRESSURE DELIVERYCOSTS .................................................................................................................................3A. Transmission Mains Investment ..........................................................................................3B. High-Pressure Regulator Station Investment.......................................................................3C. Upper Medium-Pressure Distribution Mains Investment....................................................3D. Time-Differentiation............................................................................................................4E. Underground Reliability Storage .........................................................................................5III. MARGINAL INVESTMENT IN LOCAL DISTRIBUTION FACILITIES.............................6A. Regulator Station Investment...............................................................................................7B. Mains Investment.................................................................................................................7IV. DISTRIBUTION OPERATION AND MAINTENANCE EXPENSES...................................8V. MARGINAL CUSTOMER-RELATED COSTS .....................................................................11A. Meter, House Regulator and Service Lateral.....................................................................11B. Customer Accounts Expenses............................................................................................16C. Customer Service and Informational Expenses .................................................................18VI. OTHER MARGINAL COSTS................................................................................................18A. Administrative and General Expenses...............................................................................18B. General Plant......................................................................................................................19VII. COMPUTATION OF CARRYING CHARGES ...................................................................19VIII. COMPUTATION OF ANNUAL MARGINAL COSTS......................................................21A. Annual Upper Medium-Pressure Mains and High-Pressure Regulator StationMarginal Costs...................................................................................................................21B. Annual Lower Medium- and Low-Pressure Mains and Regulator Station MarginalCosts...................................................................................................................................22C. Annual Customer-Related Costs........................................................................................23IX. SUMMARY TABLES AND EFFICIENT PRICES ...............................................................27NERA Economic Consultingi
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 4 of 38List of Tables and FiguresFigure 1. Simplified RG&E Gas Delivery System ..................................................2Table 1. Marginal Investment in Upper Medium-Pressure Mains and High-Pressure Regulator Stations ..............................................................................4Table 2. Relative Probability of Peak Day...............................................................5Table 3. Marginal Reliability Storage Cost per Therm............................................6Table 4. Derivation of Marginal Investment in Medium- and Low-PressureRegulator Stations.............................................................................................7Table 5. Derivation of Marginal Investment in Lower-Medium and Low-Pressure Mains..................................................................................................8Table 6. Regulator Station O&M Expense per MCF/Day.......................................9Table 7. Upper Medium-Pressure Mains O&M Expense per MCF/Day...............10Table 8. Marginal Lower Medium- and Low-Pressure Mains O&M Expenseper MCF/Day..................................................................................................10Table 9. Installed Cost of Meter & House Regulator by ServiceClassification ..................................................................................................11Table 10. Installed Cost of Service Lateral by Service Classification..................12Table 11. Meter and House Regulator O&M Expense per WeightedCustomer.........................................................................................................13Table 12. Meter and House Regulator O&M Expense by ServiceClassification ..................................................................................................14Table 13. Service Lateral O&M Expense per Customer ......................................15Table 14. Service Lateral O&M Expense by Service Classification....................16Table 15. Adjustment Factor for Uncollectibles....................................................17Table 16. Customer Accounts and Uncollectibles Expense by ServiceClassification ..................................................................................................17Table 17. Customer Services and Informational Expenses by ServiceClassification ..................................................................................................18Table 18. Loading Factors for A&G Expenses and General Plant........................19Table 19. Incremental Capital Structure and Cost.................................................20Table 20. Economic Carrying Charges..................................................................21Table 21. Annual Upper Medium-Pressure Mains and High-PressureRegulator Station Marginal Costs...................................................................22Table 22. Annual Lower Medium- and Low-Pressure Main and RegulatorStation Marginal Costs ...................................................................................23Table 23 A. Computation of Annual Customer-Related Marginal Costs..............24Table 23 B. Computation of Annual Customer-Related Marginal Costs ..............25Table 23 C. Computation of Annual Customer-Related Marginal Costs ..............26Table 24. Summary of Marginal Upper Medium-Pressure Mains, High-Pressure Regulator Station and Reliability Storage Marginal Costs ..............27Table 25. Summary of Monthly Medium & Low-Pressure Mains and Reg.Station Marginal Costs (Local Facilities) by Service Classification..............28NERA Economic Consultingii
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 5 of 38Table 26. Summary of Monthly Marginal Customer-Related Cost byService Classification .....................................................................................29Table 27 A. Marginal Costs Compared to Current Rates ......................................31Table 27 B. Marginal Costs Compared to Current Rates ......................................32NERA Economic Consultingiii
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 6 of 38INTRODUCTIONI. INTRODUCTIONRochester Gas & Electric Corporation (RG&E) retained NERA Economic Consulting (NERA)to prepare an estimate of the company’s marginal costs of gas delivery service. This reportdescribes the methods for estimating the transmission, distribution and customer-related costs,and presents summary tables of the results.What are marginal costs? Marginal cost is defined as the change in total cost with respect to asmall change in output. To quantify the marginal costs of gas service one must ask and answerthe question: What are the additional costs that would be incurred with changes gas deliveredand consumed at different times of the year and size and number of customers served.Our method for estimating marginal costs is based on the system planning process. Wedetermine the marginal cost of gas by examining the utility’s planning processes to determinewhat drives new investment and purchase decisions and how changes in consumption affectsystem operations. The method is not a formula, but a series of guidelines outlining what shouldbe measured and how the measurements can be made. The components of gas delivery servicecan be grouped in four main categories:1. transmission mains;2. high-pressure regulator stations, upper-medium pressure distribution mains andreliability storage;3. local distribution facilities consisting of medium-pressure regulator stations, lowermediumpressure mains and low-pressure regulator stations and mains; and4. customer-related facilities and functions, including:a. Meters, house regulators, relief valves and service laterals;b. Customer-related services (meter-reading, billing, accounting, customerinformation and customer service).Figure 1 is a simplified diagram of the components of RG&E’s gas delivery system.1
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 7 of 38INTRODUCTIONFigure 1. Simplified RG&E Gas Delivery SystemTRANSMISSIONTransmissionCustomerMeter &house reg.Service lateralTRANSMISSIONMAIN (>125 psi)UPPER MEDIUM-PRESSUREDISTRIBUTIONHPCustomerMeter &house reg.HIGH-PRESSUREREGULATOR STATION300/250 psi to
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 8 of 38MARGINAL HIGH-PRESSURE AND UPPER MEDIUM-PRESSURE DELIVERYCOSTSII. MARGINAL HIGH-PRESSURE AND UPPER MEDIUM-PRESSUREDELIVERY COSTSRG&E’s transmission mains, high-pressure regulator stations and upper-medium pressuredistribution mains are planned to meet near-term system design-day requirements, taking intoconsideration the expected peak-day demands under severe weather conditions.A. Transmission Mains InvestmentAs Figure 1 above illustrates, RG&E’s high-pressure transmission mains move the gas to thehigh-pressure regulator stations that feed the distribution system. Marginal transmission costscan be estimated by dividing the cost of planned transmission investment related to growth bythe demand growth triggering that investment. The annualized investment per MCF/day can thenbe assigned to periods of the year based on the relative likelihood that demand growth in eachperiod will require additional investment (typically the measure used is probability of peak).However, RG&E has not undertaken a transmission project in the past five years and it is notplanning any investment in the near term. Demand growth can be accommodated in the nearterm without the addition of transmission mains capacity. Therefore the marginal cost oftransmission mains is zero in the near term for RG&E.B. High-Pressure Regulator Station InvestmentAs Figure 1 above illustrates, high-pressure regulator stations connect the high-pressure systemto the upper medium-pressure system. Regulator stations are sized based on downstreamdemand, making an allowance for future load growth potential in the area and adequate reservesto insure system reliability as expressed in cubic feet per hour. RG&E expects to add two highpressureregulator stations in the next few years, as part of the Avon and Farmington projects.To estimate the Company’s marginal investment in high-pressure regulator stations, wecomputed the cost of these two stations per MCF/day of capacity. Because capacity in excess ofexpected load must be installed to provide reliable service, we adjusted upwards the cost perMCF/day of capacity by an estimated reserve margin of 7.5% to convert the investment per unitof capacity to an investment per unit of load. We made a further adjustment to reflect the factthat RG&E has adequate high-pressure regulator station capacity to handle load growth in asignificant portion of its service territory. The estimated marginal investment in high-pressureregulator stations is thus the previous value multiplied by the percentage of the system in whichnear-term load growth is likely to trigger addition investment in these stations (2%). Thesecalculations are shown on Table 1.C. Upper Medium-Pressure Distribution Mains InvestmentInvestment in upper medium-pressure distribution mains is also driven by increases in the neartermpeak day demand. RG&E’s planned Avon and Farmington projects include upper medium-3
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 9 of 38MARGINAL HIGH-PRESSURE AND UPPER MEDIUM-PRESSURE DELIVERYCOSTSpressure mains investment. Following the same procedure described for high-pressure regulatorstations, we divided the planned investment in upper medium-pressure mains in these projects bytheir capacity, and adjusted the quotient for the estimated reserve margin and the portion of thesystem in which growth is likely to trigger upper medium-pressure mains investment. Thesecalculations are also shown on Table 1.Table 1. Marginal Investment in Upper Medium-Pressure Mains and High-PressureRegulator Stations(1) Typical Investment 2009-2012Upper-MediumPressure MainsHigh-PressureRegulator Stations(1) (2)(Thousands of 2010 Dollars) $5,910 $510(2) Long-Term Capacity in These Projects(MCF/Day) 13,390 28,080(3) Marginal Investment in Upper-Medium PressureMains and High-Pressure Regulator Stations(2010 Dollars/MCF/Day) (1) x 1000 / (2) $441.39 $18.14(4) Adjustment for Typical Reserve Marginin Upper-Medium Pressure Mains andHigh-Pressure Regulator Stations(3) x 1.075 $474.49 $19.51(5) Adjustment for Share of System in WhichLoad Growth Will Trigger Such Investment(4) x 2% $9.49 $0.39D. Time-DifferentiationThe need for investment in both high-pressure regulator stations and upper medium-pressuremains is driven by near-term growth in system peak demand. Growth at times of the year that areunlikely to be the system peak do not trigger such investment. Using a statistical analysis of thedistribution daily system gas flows over the period 2004-2008, we produced estimates of therelative likelihood of each month’s having the peak-day demand. These monthly values areshown on Table 2. Based on these monthly probabilities, we grouped the months of Decemberthrough March as the Winter season and April through November as the Summer Season. Totime-differentiate the high-pressure station and upper medium-pressure mains costs, wemultiplied the annualized costs (discussed later) by the seasonal probabilities of peak. The resultsof these calculations are shown on the summary tables later in this report.4
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 10 of 38MARGINAL HIGH-PRESSURE AND UPPER MEDIUM-PRESSURE DELIVERYCOSTSTable 2. Relative Probability of Peak DayRelativeSeasonal ProbabilitiesProbability Winter SummerMonth of Peak (Dec. - Mar.) (April - Nov.)(1) (2) (3)Jan 78.68% 100.000% 0.000%Feb 17.05%Mar 3.46%April 0.00%May 0.00%June 0.00%July 0.00%Aug 0.00%Sept 0.00%Oct 0.00%Nov 0.00%Dec 0.82%E. Underground Reliability StorageRG&E has some underground storage that provides reliability benefits to the distribution system.For each additional unit of gas delivered, RG&E plans for an incremental change in reliabilityneeds. Thus there is a marginal reliability storage cost.RG&E has developed an estimate of the embedded cost per therm of these resources, includingcapacity costs and carrying charges on the stored gas, which will be used as the basis for aproposed reliability surcharge. We used as our estimate of the marginal cost of this element ofservice the surcharge calculated by RG&E, escalated to 2010 dollars and adjusted for losses, asshown in Table 3. This element of marginal cost is applicable to RG&E’s SC1 and SC5customers.5
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 11 of 38MARGINAL INVESTMENT IN LOCAL DISTRIBUTION FACILITIESTable 3. Marginal Reliability Storage Cost per Therm(1) Reliability Surcharge per Therm(2008 Dollars per Therm) $0.0206(2) Reliability Surcharge per Therm(2010 Dollars per Therm): (1) x 1.0192 $0.0214(3) Reliability Storage Marginal Cost per Therm(2) x 1.0147(2010 Dollars per Therm) $0.0217III.MARGINAL INVESTMENT IN LOCAL DISTRIBUTION FACILITIESAs illustrated in Figure 1 above, local distribution facilities include medium and low-pressureregulator stations, lower medium-pressure mains and low-pressure mains. These facilities aretypically designed using engineering standards that take into consideration the expected longtermmaximum demands of customers that will use them, not specifically the number ofcustomers or their near-term design-day demands. The costs of this portion of the system aremarginal when the mains and regulator stations are installed and when they are replaced becauseof age, but typically do not vary with customers’ actual gas usage from month to month or yearto year. The capacity of these facilities would be expanded if there were a major increase in thedesign demands of the customers using them. Ideally these costs should be recovered in a fixedcomponent of the rate design (on a per-unit-of-design-demand basis), rather than in chargesbased on gas consumption. We used the same basic approach to estimate marginal investment foreach element of local distribution facilities, using the following three assumptions:• The characteristics of local facilities installed for customers of various design demandsare relatively constant over time.• The average replacement cost of such facilities on the entire RG&E system is typical ofthe marginal cost of installing and replacing these facilities going forward.• Meter capacity is a reasonable basis for estimating long-term design-day demand,provided that residential meter capacity is adjusted to reflect the fact that meter capacityfor these customers is about 1.66 times their connected load.For each component of local distribution facilities, we computed the current replacement cost (in2010 dollars) of all such facilities on RG&E’s system. Some local distribution facilities costs arerecovered up front through a customer contribution in aid of construction (CIAC); the remainingcosts are recovered over time through rates. At the Company’s request, we developed estimatesof local distribution facilities before and after these customer contributions. In the version thatrecognizes customer contributions, we subtracted the share of investment typically paid for upfront by customers. Finally, we divided the net replacement cost by the aggregate design demandat the customer premises, using meter capacity (with the adjustment for residential meters) as themeasure of long-term design-day demand.6
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 12 of 38MARGINAL INVESTMENT IN LOCAL DISTRIBUTION FACILITIESA. Regulator Station InvestmentFor medium- and low-pressure regulator stations, we used the weighted average of the 2010replacement cost of typical stations and multiplied by the number of these stations on the system.Typically customers do not pay upfront for any portion of these stations, so no adjustment forCIAC was required. We then divided the total net replacement cost of medium-and low-pressureregulator stations by the aggregate design-day demand at the customer premises. (See Table 4.)Table 4. Derivation of Marginal Investment in Medium- and Low-Pressure RegulatorStations(1) Replacement Cost of Weighted AverageMedium- and Low-pressure Regulator Stations(Thousands of 2010 Dollars) $165(2) Total Number of Medium- and Low-pressure RegulatorStations in the System 325(3) Total Replacement Cost of Medium- and LowpressureRegulator Stations [(1) * (2)](Thousands of 2010 Dollars) $53,508(4) 2008 Aggregate Long-Term Design Demand at Customer Premises(MMCF/Day) 1,288(5) Marginal Investment in Medium- andLow-pressure Regulator Stations [(3) / (4)](2010 Dollars/MCF/day) $41.53B. Mains Investment1. Lower Medium- and Low-Pressure MainsTable 5 shows the derivation of marginal investment in lower medium-pressure distributionmains and low-pressure distribution mains. We divided the replacement cost (2010 dollars) of allexisting low and lower-medium pressure mains by the aggregate design demand at the customerpremises (discussed above). The investment is shown before and after adjusting for CIAC. TheCIAC percentage of such investment (13%) is based on customer contributions as a percent oftotal mains investment in 2008. 11 RG&E indicated that all of the customer contributions were for lower medium-pressure mains, and that theamount of total added mains that was not lower medium-pressure was not statistically significant. We assumedthat the same percentage would apply to low-pressure mains.7
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 13 of 38DISTRIBUTION OPERATION AND MAINTENANCE EXPENSESTable 5. Derivation of Marginal Investment in Lower-Medium and Low-Pressure Mains(1) Replacement Cost of Existing Lower Mediumand Low-Pressure Distribution Mains (after CIAC)(Thousands of 2010 Dollars) $1,637,375(2) Total Replacement Cost of Existing Lower Mediumand Low-Pressure Distribution Mains (before CIAC)(Thousands of 2010 Dollars) $1,882,040(3) 2008 Aggregate Long-Term Design Demand at Customer Premises(MMCF/Day) 1,288(4) Marginal Investment in Lower Medium and Low-Pressure Distribution Mains (after CIAC)(2010 Dollars/MCF/Day) (1) / (3) $1,270.98(5) Total Marginal Investment in Lower Medium and Low-Pressure Distribution Mains (before CIAC)(2010 Dollars/MCF/Day) (2) / (3) $1,460.89IV.DISTRIBUTION OPERATION AND MAINTENANCE EXPENSESO&M expenses depend on the amount of plant in service. The addition of distributionequipment to meet increments in near-term or long-term design-day demand gives rise toincreased O&M expenses as well. Distribution O&M expenses on marginal investment are,therefore, marginal costs. We used RG&E’s average level of distribution O&M expenses in thepast five years as a guide for estimating marginal O&M costs. 2RG&E’s accounting system does not show separate O&M expenses for equipment of variouspressure levels. We allocated Main and Service Operation Expenses (Account #874) to thevarious distribution pressure mains and to service laterals in proportion to mileage. Distributionoverheads 3 were allocated to each type of main, as well as to services and meter and houseregulators in proportion to their shares of total distribution O&M less these overhead accounts.We allocated O&M expenses related to regulator stations to pressure categories in proportion tothe number of regulator stations at each level and the typical O&M per regulator station2 We excluded Account 871 (Load Dispatching) as non-marginal, and Account 881 (Rents) because it is a substitutefor past investment and, therefore not a marginal expense.3 Distribution overheads include: Operation Supervision and Engineering (870), Other Expenses (880),Maintenance Supervision and Engineering (885), Maintenance of Other Equipment (894) and Maintenance ofStructures and Improvements (886).8
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 14 of 38DISTRIBUTION OPERATION AND MAINTENANCE EXPENSES(categorized by their outlet pressure). Since RG&E’s marginal transmission main investmentsare zero, there is no marginal O&M cost associated with this system element in the near term. 4On Table 6 we divided regulator station O&M by total system design-day demand and adjustedthese historical costs to 2010 dollars. After examining the trend in unit costs over the five-yearperiod and consulting with RG&E, we selected the 2008 value as likely to be representative offuture marginal levels of these costs. RG&E provided typical O&M expenses for each pressurelevel station, which we used to apportion the regulator station expenses to low/medium- andhigh-pressure stations. One additional adjustment is required for the high-pressure station O&M.Because load growth is not likely to trigger high-pressure regulatory station additions in all partsof the service territory, using an O&M expense estimate based on average O&M on the currentsystem would overstate marginal O&M. Therefore, we adjusted the high-pressure O&M estimateby the same percentage of the system likely to require capacity additions as used for the highpressureregulator marginal investment calculation (2%).Table 6. Regulator Station O&M Expense per MCF/DayTotal O&M WeightedSystem Expense Per Labor and Reg. StationReg. Station Design Demand MCF of Design Materials O&M per MCFYear O&M Expenses Demand Demand Cost Index of Design Demand(000 Dollars) (MMCF/day) ($/MCF/day) (2010=1.00) (2010$/MCF/day)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 155 1,288.28 0.12 0.7833 0.15(2) 2005 979 1,288.28 0.76 0.8373 0.91(3) 2006 1,038 1,288.28 0.81 0.8724 0.92(4) 2007 1,332 1,288.28 1.03 0.8957 1.15(5) 2008 2,202 1,288.28 1.71 0.9494 1.80(6) Estimated Annual Marginal Reg. Station O&M per MCF/day[Value for 2008] $1.80(7) Low and Medium Pressure Share (6) x Share of Total (90.6%) $1.63(8) High-Pressure Share (6) x Share of Total (9.4%) $0.17(9) High-Pressure Station O&M Adjusted for Share of System Requiring AdditionalCapacity in Response to Load Growth (8) x 2% $0.00The process for developing estimates of upper medium-pressure mains O&M followed the sameapproach, but included losses in the design-day demands used as the denominator, and used the4 In addition, marginal demand reductions would not reduce the expenses associated with operating andmaintaining the existing transmission mains.9
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 15 of 38DISTRIBUTION OPERATION AND MAINTENANCE EXPENSESsame adjustment for the percent of the system not likely to require upper medium-pressure mainsexpansion in response to marginal load growth. Table 7 shows the computations. Table 8 showsa corresponding calculation for low- and lower medium-pressure mains.Table 7. Upper Medium-Pressure Mains O&M Expense per MCF/DayTotalUpper System O&M Weighted Upper Medium &Medium-Pressure Design Expense Per Labor and Distribution MainsMains Demand MCF of Materials O&M per MCF ofYear O&M Expense Incl. Losses Design Demand Cost Index Design Demand(000 Dollars) (MMCF/day) ($/MCF/day) (2010=1.00) (2010$/MCF/day)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 $45.70 1,307.22 $0.03 0.7833 $0.04(2) 2005 45.99 1,307.22 0.04 0.8373 0.04(3) 2006 42.93 1,307.22 0.03 0.8724 0.04(4) 2007 44.82 1,307.22 0.03 0.8957 0.04(5) 2008 40.55 1,307.22 0.03 0.9494 0.03(6) Estimated Annual Upper Medium and DistributionMains O&M per MCF/day [Value for 2008] $0.03(7) Adjustment for percent of system requiring upper medium-pressuremains investment in response to load growth (6) x 2% $0.00Table 8. Marginal Lower Medium- and Low-Pressure Mains O&M Expense per MCF/DayLow andLower-Medium and Total O&M Weighted Lower-MediumLow-Pressure System Expense Per Labor and Pressure MainMain Design MCF of Materials O&M per MCF ofYear O&M Expense Demand Design Demand Cost Index Design Demand(000 Dollars) (MMCF/day) ($/MCF/day) (2010=1.00) (2010$/MCF/day)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 $10,254 1,288.28 $7.96 0.7833 $10.16(2) 2005 10,320 1,288.28 8.01 0.8373 9.57(3) 2006 9,634 1,288.28 7.48 0.8724 8.57(4) 2007 10,056 1,288.28 7.81 0.8957 8.71(5) 2008 9,099 1,288.28 7.06 0.9494 7.44(6) Estimated Annual Low- and Lower-Medium Pressure Mains O&M per MCF/day[Value for 2008] $7.4410
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 16 of 38V. MARGINAL CUSTOMER-RELATED COSTSA. Meter, House Regulator and Service LateralMARGINAL CUSTOMER-RELATED COSTS1. Marginal Investment of Meter, House Regulator and ServiceLateralRG&E supplied the current weighted-average installed costs of meters, including houseregulators and relief valves for each customer classification. RG&E also supplied typical costs ofservice laterals by class. These customer-related marginal investments, converted to 2010dollars, are shown on Tables 9 and 10.Table 9. Installed Cost of Meter & House Regulator by Service ClassificationAverage CostCustomer Class Description Per Customer(2010$)(1) SC1RNH SC 1 Residential Non Heat $271.63(2) SC1RH SC 1 Residential Heat 271.63(3) SC1C SC 1 Commercial 476.43(4) SC1IND SC 1 Industrial 1,750.34(5) SC1MUN SC 1 Municipal 1,170.98(6) SC3C SC 3 Large T Commercial 5,164.92(7) SC3IND SC 3 Large T Industrial 6,685.48(8) SC3MUN SC 3 Large T Municipal 5,255.69(9) SC3 HP SC 3 Large Transportation High-Pressure 49,540.00(10) SC5RNH SC 5 Small Transportation Residential Non Heat 271.63(11) SC5RH SC 5 Small Transportation Residential Heat 271.63(12) SC5C SC 5 Small Transport Commercial 720.21(13) SC5IND SC 5 Small Transport Industrial 1,951.27(14) SC5MUN SC 5 Small Transport Municipal 1,309.69(15) SC7T SC 7 Non-Residential Transportation for DG 7,650.0011
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 17 of 38MARGINAL CUSTOMER-RELATED COSTSTable 10. Installed Cost of Service Lateral by Service ClassificationAverage CostCustomer Class Description Per Customer(2010$)(1) SC1RNH SC 1 Residential Non Heat $1,158.28(2) SC1RH SC 1 Residential Heat 1,158.25(3) SC1C SC 1 Commercial 1,464.94(4) SC1IND SC 1 Industrial 1,908.76(5) SC1MUN SC 1 Municipal 1,908.76(6) SC3C SC 3 Large T Commercial 3,042.58(7) SC3IND SC 3 Large T Industrial 6,625.79(8) SC3MUN SC 3 Large T Municipal 3,042.58(9) SC3 HP SC 3 Large Transportation High-Pressure 8,995.73(10) SC5RNH SC 5 Small Transportation Residential Non Heat 1,158.75(11) SC5RH SC 5 Small Transportation Residential Heat 1,158.23(12) SC5C SC 5 Small Transport Commercial 1,464.94(13) SC5IND SC 5 Small Transport Industrial 1,908.76(14) SC5MUN SC 5 Small Transport Municipal 1,908.76(15) SC7T SC 7 Non-Residential Transportation for DG n/a2. Meter, House Regulator and Service Lateral O&M ExpenseMeter and House Regulator O&M expenses vary by service classification. We divided theseexpenses, along with their associated overheads (as explained in Section IV), by weightednumber of customers, where the weights reflect an allocation of 10% of the expenses toresidential customers and 90% to non-residential customers, with the non-residential componentfurther segmented based on relative meter cost (See Table 11). After converting the historicalcosts per weighted customer to 2010 dollars, we reviewed the trend and, in consultation withRG&E, chose the 2008 value as best representing the future levels of these expenses. Table 12shows the Meter and House Regulator O&M for each service classification. These values are thecost per weighted customer multiplied by each service classification’s weight.12
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 18 of 38MARGINAL CUSTOMER-RELATED COSTSTable 11. Meter and House Regulator O&M Expense per Weighted Customer2004 2005 2006 2007 2008(1) (2) (3) (4) (5)(1) Meter Operation and MaintenanceExpenses (Thousand Dollars) $9,355 10,002 8,250 6,123 5,084(2) Number of Customers 293,334 294,646 295,373 296,473 297,778(3) Weighted Customers(2) x 9.24 2,709,698 2,721,819 2,728,537 2,738,696 2,750,750(4) Expense Per WeightedCustomer (Dollars)[(1) / (3)] x 1000 $3.45 $3.67 $3.02 $2.24 $1.85(5) Labor Cost Index (2010 = 1.00) 0.8375 0.8626 0.8885 0.9151 0.9426(6) Expense Per WeightedCustomer in 2010 Dollars(4) / (5) $4.12 $4.26 $3.40 $2.44 $1.96(7) Estimated Annual MarginalExpense per Weighted Customer(Value for 2008)(2010 Dollars) $1.9613
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 19 of 38MARGINAL CUSTOMER-RELATED COSTSTable 12. Meter and House Regulator O&M Expense by Service ClassificationMeterO&M Annual MeterWeighting O&M ExpenseRate Class Factor per Customer(2010 Dollars)(1) x $1.96(1) (2)(1) SC1RNH SC 1 Residential Non Heat 1.00 $1.96(2) SC1RH SC 1 Residential Heat 1.00 1.96(3) SC1C SC 1 Commercial 68.55 134.41(4) SC1IND SC 1 Industrial 251.84 493.80(5) SC1MUN SC 1 Municipal 168.48 330.35(6) SC3C SC 3 Commercial 743.13 1,457.11(7) SC3IND SC 3 Industrial 961.90 1,886.09(8) SC3MUN SC 3 Municipal 756.19 1,482.72(9) SC3 HP SC 3 High-Pressure 7,127.80 13,976.07(10) SC5RNH SC 5 Residential Non Heat 1.00 1.96(11) SC5RH SC 5 Residential Heat 1.00 1.96(12) SC5C SC 5 Commercial 103.62 203.18(13) SC5IND SC 5 Industrial 280.75 550.49(14) SC5MUN SC 5 Municipal 188.44 369.48(15) SC7T SC 7 Non-Residential for DG 1,100.68 2,158.19Service lateral O&M expenses are the same for service laterals of all sizes. However, on average,residential customers have less than one service line per customer. We divided service O&Mexpenses, along with their associated overheads, by the average number of services to computemarginal service-related O&M costs per service. (See Table 13.) After converting the historicalcosts to 2010 dollars, we reviewed the trend and, in consultation with RG&E, chose the 2008value as best representing the future levels of these expenses. Table 14 shows the service O&Mfor each service classification. These values are the cost per service multiplied by averageservices per customer.14
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 20 of 38MARGINAL CUSTOMER-RELATED COSTSTable 13. Service Lateral O&M Expense per CustomerTotalService Lateral Weighted AnnualOperation & Average Service Lateral Labor and Service LateralMaintenance Number of Expense Materials ExpenseYear Expenses Services Per Service Cost Index Per Service(000 Dollars) (Dollars) (2010=1.00) (2010 Dollars)[(1) x 1000]/(2) (4)/(5)(1) (2) (3) (4) (5)(1) 2004 $2,005 266,523 $7.52 0.7833 $9.61(2) 2005 3,422 267,705 12.78 0.8373 15.27(3) 2006 3,371 268,350 12.56 0.8724 14.40(4) 2007 2,176 269,328 8.08 0.8957 9.02(5) 2008 2,489 270,515 9.20 0.9494 9.69(6) Estimated Annual Marginal Service Lateral O&M Expense[Value for 2008] $9.6915
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 21 of 38MARGINAL CUSTOMER-RELATED COSTSTable 14. Service Lateral O&M Expense by Service ClassificationAnnualService LateralCustomer Services per O&M ExpenseClass Description Customer Per Customer(2010 Dollars)(1) SC1RNH SC 1 Residential Non Heat 0.901 $8.73(2) SC1RH SC 1 Residential Heat 0.901 8.73(3) SC1C SC 1 Commercial 1.000 9.69(4) SC1IND SC 1 Industrial 1.000 9.69(5) SC1MUN SC 1 Municipal 1.000 9.69(6) SC3C SC 3 Commercial 1.000 9.69(7) SC3IND SC 3 Industrial 1.000 9.69(8) SC3MUN SC 3 Municipal 1.000 9.69(9) SC3 HP SC 3 High-Pressure 1.000 9.69(10) SC5RNH SC 5 Residential Non Heat 0.901 8.73(11) SC5RH SC 5 Residential Heat 0.901 8.73(12) SC5C SC 5 Commercial 1.000 9.69(13) SC5IND SC 5 Industrial 1.000 9.69(14) SC5MUN SC 5 Municipal 1.000 9.69(15) SC7T SC 7 Non-Residential for DG 1.000 9.69B. Customer Accounts ExpensesCustomer accounts expenses, composed mainly of meter-reading and billing expenses anduncollectibles, 5 are costs directly attributable to the existence of customers on the system. Weexcluded expenses associated with the merchant function from the marginal delivery costestimates. For customer accounts expenses other than uncollectibles, in consultation with RG&E,we determined that the 2008 expenses are a reasonable proxy for the marginal cost in futureyears. We used the results from the 2008 embedded study to identify the cost per customer foreach class.In the case of uncollectibles, which had a two-fold increase from 2007 to 2008, we adjusted theannual cost per customer from the 2008 embedded study by the ratio of the two-year average tothe 2008 level to reduce the effect of the recession. Table 15 shows the calculation of thisuncollectibles ratio and Table 16 shows the estimated marginal costs by service classification.5 We dealt with uncollectibles separately because this component of customer accounts expense is not subject to thecash working capital adjustment, discussed later.16
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 22 of 38MARGINAL CUSTOMER-RELATED COSTSTable 15. Adjustment Factor for UncollectiblesYearUncollectibles2007 $6,677,7802008 $14,353,296Average $10,515,538Ratio Average to 2008 73.26%Table 16. Customer Accounts and Uncollectibles Expense by Service ClassificationCustomerCustomerAccounts Accounts EstimatedExpense (excl. Expense (excl. 2008 Marginaluncollectibles) Uncollectibles uncollectibles) Uncollectibles UncollectiblesRate Class per Customer per Customer per Customer per Customer per Customer(2008 Dollars) (2008 Dollars) (2010 Dollars) (2010 Dollars) (2010 Dollars)(1) / 0.9426 (2) / 0.9426 (4) x 0.7326(1) (2) (3) (4) (5)(1) SC1RNH SC 1 Residential Non Heat $18.45 $8.89 $19.57 $9.43 $6.91(2) SC1RH SC 1 Residential Heat 20.09 12.72 21.31 13.50 9.89(3) SC1C SC 1 Commercial 23.05 7.66 24.45 8.13 5.95(4) SC1IND SC 1 Industrial 31.04 18.87 32.94 20.02 14.67(5) SC1MUN SC 1 Municipal 31.04 18.87 32.94 20.02 14.67(6) SC3C SC 3 Commercial 150.40 163.89 159.56 173.87 127.38(7) SC3IND SC 3 Industrial 247.66 281.56 262.74 298.71 218.84(8) SC3MUN SC 3 Municipal 247.66 281.56 262.74 298.71 218.84(9) SC3 HP SC 3 High-Pressure 1,170.47 1,427.46 1,241.75 1,514.39 1,109.47(10) SC5RNH SC 5 Residential Non Heat 15.66 9.50 16.61 10.07 7.38(11) SC5RH SC 5 Residential Heat 16.67 11.86 17.68 12.58 9.22(12) SC5C SC 5 Commercial 20.98 10.14 22.26 10.76 7.88(13) SC5IND SC 5 Industrial 27.81 16.86 29.50 17.89 13.10(14) SC5MUN SC 5 Municipal 27.81 16.86 29.50 17.89 13.10(15) SC7T SC 7 Non-Residential for DG 89.45 95.94 94.90 101.78 74.5717
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 23 of 38OTHER MARGINAL COSTSC. Customer Service and Informational ExpensesCustomer service and informational expenses also vary with the number of customers on thesystem and are, therefore, marginal. 6 In consultation with RG&E we used the 2008 embeddedcost values per customer for each classification as our estimate of marginal customer service andinformational expenses. Table 17 shows the expense by service classification.Table 17. Customer Services and Informational Expenses by Service ClassificationCustomer CustomerService ServiceRate Class Expense Expense(2008 Dollars) (2010 Dollars)(1) / 0.9426(1) (2)(1) SC1RNH SC 1 Residential Non Heat $0.49 $0.52(2) SC1RH SC 1 Residential Heat 0.91 0.96(3) SC1C SC 1 Commercial 3.36 3.56(4) SC1IND SC 1 Industrial 11.23 11.92(5) SC1MUN SC 1 Municipal 11.23 11.92(6) SC3C SC 3 Commercial 14.04 14.89(7) SC3IND SC 3 Industrial 24.74 26.25(8) SC3MUN SC 3 Municipal 24.74 26.25(9) SC3 HP SC 3 High-Pressure 122.26 129.71(10) SC5RNH SC 5 Residential Non Heat 0.19 0.20(11) SC5RH SC 5 Residential Heat 0.23 0.25(12) SC5C SC 5 Commercial 0.90 0.96(13) SC5IND SC 5 Industrial 1.53 1.62(14) SC5MUN SC 5 Municipal 1.53 1.62(15) SC7T SC 7 Non-Residential for DG 11.15 11.82VI.OTHER MARGINAL COSTSA. Administrative and General ExpensesCertain general corporate administrative and general (A&G) expenses tend to vary withoperating and maintenance expenses. Based on our understanding of RG&E’s classification of6 Customer service expenses recovered in the Gas System Benefits Charge (beginning in 2008) are excluded fromthe costs in these calculations.18
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 24 of 38COMPUTATION OF CARRYING CHARGEScosts in the various FERC accounts for A&G expenses (including social security andunemployment taxes), we divided these expenses into two categories: (1) those associated withother types of expenses and (2) those associated with plant. We normally use regression analysison about 20 years of historical data to identify marginal A&G expenses and general plant.However, major changes at RG&E over this period make this approach inappropriate for theA&G loaders.After reviewing recent levels of potentially marginal non-plant related A&G expenses, we foundthat only social security and unemployment taxes are strongly linked to O&M. We developed thenon-plant related A&G loader by computing 2008 social security and unemployment taxes as apercent of non-fuel O&M. The loader is shown in Table 18 below.For plant-related A&G expenses, we found that the only A&G account directly related to theamount of plant on the system is property insurance. RG&E provided an estimate of the 2009property insurance rate per $100 of replacement cost of affected plant. Property insurance appliesto stock/inventory items, buildings and equipment and metering and regulation stations valuedover $100,000. We applied the factor only to regulator stations. The plant-related A&G loader isshown on Table 18 below.B. General PlantGeneral plant consists of items such as office buildings, warehouses, cars, trucks and otherequipment. When a utility adds transmission and distribution plant, its need for general plantincreases as well. Our estimate of RG&E’s general plant loader, shown on Table 18, is based ona regression of cumulative additions to general plant net of retirements, plus the gas portion ofcommon plant, on cumulative additions to total distribution plant net of retirements, all stated inconstant dollars, over the period 1992-2008. A dummy shift variable is included starting in 2006.The coefficient of the explanatory variable is the loader.Table 18. Loading Factors for A&G Expenses and General PlantLoadingFactor(1) Non-Plant Related Loader 2.48%(2) Plant-Related Loader 0.04%(3) General Plant 38.16%VII.COMPUTATION OF CARRYING CHARGESThe sections above describe the development of estimates of marginal investment in severalcategories of plant. To be useful in ratemaking and other marginal cost applications, theinvestment must be converted into annual costs using an economic carrying charge. The annual19
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 25 of 38COMPUTATION OF CARRYING CHARGEScharge reflects the elements of RG&E’s revenue requirement associated with incremental plant:return to stockholders and bondholders, depreciation, and taxes. For use in a marginal cost study,the appropriate stream of annual charges is a stream that rises at the rate of inflation net oftechnical progress and yields the total present value of all costs over the life of the investment.In such a stream, the first year's charge represents the cost in today's dollars of owning the plantor equipment for a year. It also represents the rental rate for such an investment in a competitivemarket.Key inputs for the economic carrying charge calculation include: (1) the utility’s incrementalcost of capital (mix of debt and equity and their respective long-term market costs), (2) theexpected inflation rate for that type of plant, net of technical progress, and (3) the average servicelife and patterns of failure (“Iowa curve”) for that type of plant.RG&E foresees financing of near-term incremental investment through additional equity(retained earnings and/or infusion of equity capital from the parent company) and long-term debtwith the capital structure and costs shown in Table 19.Table 19. Incremental Capital Structure and CostShare Cost(%) (%)Debt 51.88 7.00Common Stock 48.12 11.43Another integral part of the economic carrying charge calculation is the estimation of the rate ofinflation net of technical progress applicable over the life of the investment. We used 1.9 percentas an approximation of the rate of future inflation net of technical progress, based on RG&E’srecommendation. 7Finally, an adjustment is required for the fact that not all plant and equipment will last itsestimated service life. Some components will require early replacement, causing added costs,while some will last longer than expected and produce savings. The pattern of expected requiredreplacement for each type of plant is defined by an Iowa Curve. An adjustment for this dispersedpattern of replacements using Iowa Curves was included in the derivation of the economiccarrying charges. The results of these economic carrying charge calculations are presented onTable 20 below. The adjustments for dispersed retirements are shown on line (2) of this table.7 This percentage is RG&E’s expectation for long-term inflation. We assumed that the rate of technologicalprogress in gas delivery plant is subsumed in the inflation estimate.20
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 26 of 38COMPUTATION OF ANNUAL MARGINAL COSTSTable 20. Economic Carrying ChargesMetersRegulator Service and HouseMains Stations Laterals Regulators(1) (2) (3) (4)(1) Present Value of Revenue RequirementsRelated to Incremental $1,000 Investment $1,855.60 $1,726.01 $1,797.09 $1,768.47(2) Present Value Cost of ReplacingDispersed Retirements Related toIncremental $1,000 Investment $44.07 $83.57 $71.14 $43.37(3) Total Present Value Cost Related toIncremental $1,000 Investment (1)+(2) $1,899.68 $1,809.58 $1,868.23 $1,811.84(4) First-Year Annual Economic ChargeRelated to Incremental $1,000 Investment $113.34 $133.71 $120.18 $125.63(5) First-Year Annual Economic Charge Related toIncremental Investment [(4)/$1,000] 11.33% 13.37% 12.02% 12.56%VIII. COMPUTATION OF ANNUAL MARGINAL COSTSThe next step of the study was to apply the economic carrying charges to the marginalinvestment and add the associated expenses.A. Annual Upper Medium-Pressure Mains and High-PressureRegulator Station Marginal CostsThe marginal investments per MCF-day in upper medium-pressure mains and high-pressureregulator stations were adjusted upwards by the general-plant loading factor. We multiplied theresulting figures by the annual economic carrying charge percentage plus the plant-related A&Gloading factor, where appropriate, to yield the annualized plant costs. To these costs we addedthe associated O&M and non-plant related A&G expenses and the revenue requirements forworking capital. The computation of working capital includes cash working capital, materials,supplies and prepayments. Table 21 shows the total annual unit marginal cost calculations forupper medium-pressure mains and high-pressure regulator stations. These annualized costs wereadjusted for losses through the system, and converted to cents per therm, using system loadfactor. The last section of the table computes the costs on a seasonal basis.21
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 27 of 38COMPUTATION OF ANNUAL MARGINAL COSTSTable 21. Annual Upper Medium-Pressure Mains and High-Pressure Regulator StationMarginal CostsUpper Medium- High-PressurePressure Mains Regulator Stations(2010 Dollars per MCF of Near-Term DesignDay Demand)(1) Marginal Investment $9.49 $0.39(2) With General Plant Loading (1) x 1.3816 13.11 0.54(3) Annual Economic Carrying Charge Related toCapital Investment 11.33% 13.37%(4) A&G Loading (plant related) 0.00% 0.04%(5) Total Annual Carrying Charge (3) + (4) 11.33% 13.41%(6) Annualized Costs (2) x (5) $1.49 $0.07(7) O&M Expenses 0.00 0.00(8) O&M exp. with A&G Loading (Non-plant Related)(7) x 1.0248 0.00 0.00(9) Annual Cost (6) + (8) 1.49 0.08Working Capital(10) Material and Supplies (2) x 2.34% 0.31 0.01(11) Prepayments (2) x 1.04% 0.14 0.01(12) Cash Working Capital Allowance (8) x 12.50% 0.00 0.00(13) Total Working Capital (10) + (11) + (12) 0.44 0.02(14) Revenue Requirement for WorkingCapital (13) x 13.22% 0.06 0.00(15) Annual Marginal Unit Costs (9) + (14) 1.55 0.08(16) Annual Marginal Unit Costs (with losses)(15) * 1.0147 $1.57 $0.08(17) Winter Season (Dec. - Mar.) Marginal Unit Costs(with losses) - (16) x Winter Probability of Peak $1.57 $0.08(18) Summer Season (Apr. - Nov.) Marginal Unit Costs(with losses) - (16) x Summer Probability of Peak $0.0000 $0.00(2010 cents/therm) (2010 cents/therm)(19) Annual Unit Costs100 x (16) / [(Days in Year * Annual Load Factor ) / (1.03 * 10)] 0.11458 0.00580(20) Winter Season Unit Costs100 x (17) / [(Days in Winter * Winter Load Factor ) / (1.03 * 10)] 0.19325 0.00978(21) Summer Season Unit Costs100 x (18) / [Days in Summer * Summer Load Factor ) / (1.03 * 10)] 0.00000 0.00000B. Annual Lower Medium- and Low-Pressure Mains and RegulatorStation Marginal CostsThe annualization of marginal investments in lower medium- and low-pressure mains andregulator stations followed the same process as in the previous table. Table 22 shows the totalannual unit marginal cost calculations for mains and regulator stations operating at all pressurelevels. The plant-related A&G loading factor (based on property insurance costs) does not applyto the mains. The annualized costs are expressed in $/MCF of long-term design-day demand. The22
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 28 of 38COMPUTATION OF ANNUAL MARGINAL COSTSlower medium-pressure and low-pressure mains costs are shown before and after customercontributions.Table 22. Annual Lower Medium- and Low-Pressure Main and Regulator StationMarginal CostsMedium andLow-pressureReg. StationLower Medium andLow- PressureMains (after CIAC)Total LowerMedium and Low-Pressure Mains(before CIAC)(2010 Dollars per MCF of Long-Term Design Day Demand)(1) (2) (3)(1) Marginal Investment $41.53 $1,270.98 $1,460.89(2) With General Plant Loading (1) x 1.3816 $57.38 $1,828.45 * $2,018.37(3) Annual Economic Carrying Charge Related toCapital Investment 13.37% 11.33% 11.33%(4) A&G Loading (plant related) 0.04% 0.00% 0.00%(5) Total Annual Carrying Charge (3) + (4) 13.41% 11.33% 11.33%(6) Annualized Costs (2) x (5) $7.70 $207.24 $228.76(7) O&M Expenses $1.63 $7.44 $7.44(8) O&M exp. with A&G Loading (Non-plant Related)(7) x 1.0248 $1.67 $7.62 $7.62(9) Annual Cost (6) + (8) $9.37 $214.86 $236.38Working Capital(10) Material and Supplies (2) x 2.34% $1.34 $47.23 * $47.23(11) Prepayments (2) x 1.04% $0.60 $20.99 * $20.99(12) Cash Working Capital Allowance (8) x 12.50% $0.21 $0.95 $0.95(13) Total Working Capital (10) + (11) + (12) $2.15 $69.17 $69.17(14) Revenue Requirement for WorkingCapital (13) x 13.22% $0.28 $9.14 $9.14(15) Annual Marginal Unit Costs (9) + (14) $9.65 $224.00 $245.53* Adjustments related to investment are applied to the total cost, not the cost after CIAC.C. Annual Customer-Related CostsThe annual customer-related marginal costs were developed using a procedure similar to that forthe other types of plant. This component includes the cost of the meter and house regulator,service lateral, and customer-related expenses. The resulting costs (in $ per customer) are shownby service classification in Tables 23. The cash working capital component does not apply touncollectibles.23
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 29 of 38COMPUTATION OF ANNUAL MARGINAL COSTSTable 23 A. Computation of Annual Customer-Related Marginal CostsInvestment - Meter, House Regulators & ServicesSC1RNH SC1RH SC1CNH SC1IND SC1MUN------------------------------------ (2010 Dollars) ------------------------------------(1) (2) (3) (4) (5)(1) Meter & H. Regulator Investment (cost per unit) $271.63 $271.63 $476.43 $1,750.34 $1,170.98(2) With General Plant Loading (1) x 1.382 $375.29 $375.29 $658.24 $2,418.27 $1,617.83(3) Annual Economic Charge Related toCapital Investment 12.56% 12.56% 12.56% 12.56% 12.56%(4) Service Investment (cost per service) $1,158.28 $1,158.25 $1,464.94 $1,908.76 $1,908.76(5) With General Plant Loading (4) x 1.382 $1,600.28 $1,600.23 $2,023.97 $2,637.14 $2,637.14(6) Annual Economic Charge Related toCapital Investment 12.02% 12.02% 12.02% 12.02% 12.02%(7) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00%(8) Total Carrying Charge Meters & H. Reg. (3) + (7) 12.56% 12.56% 12.56% 12.56% 12.56%(9) Total Carrying Charge Services (6)+(7) 12.02% 12.02% 12.02% 12.02% 12.02%(10) Annualized Meter & H. Regulator Costs (2) x (8) $47.15 $47.15 $82.69 $303.80 $203.24(11) Annualized Service Costs (5) x (9) $192.31 $192.31 $243.23 $316.92 $316.92(12) Total Annualized Meter, H. Reg. & Service Costs (10)+(11) $239.46 $239.46 $325.92 $620.72 $520.16O&M - Meter, House Regulators & Services(13) Meter & H. Reg. O&M Expense $1.96 $1.96 $134.41 $493.80 $330.35(14) Service Lateral O&M Expense $8.73 $8.73 $9.69 $9.69 $9.69(15) Customer Accounts Expense (excluding uncollectables) $19.57 $21.31 $24.45 $32.94 $32.94(16) Uncollectibles $6.91 $9.89 $5.95 $14.67 $14.67(17) Customer Service and Informational Expense $0.52 $0.96 $3.56 $11.92 $11.92(18) A&G Loading [(13)+(14)+(15)+(17)] x 0.0248(Non-plant Related) $0.76 $0.82 $4.27 $13.59 $9.54Working Capital(19) Materials and Supplies [(2)+(5)] x 2.34% $46.23 $46.23 $62.76 $118.30 $99.57(20) Prepayments [(2)+(5)] x 1.040% $20.55 $20.55 $27.89 $52.58 $44.25(21) Cash Working Capital Allowance[(13)+(14)+(15)+(17)+(18)] x 12.50% $3.94 $4.22 $22.05 $70.24 $49.30(22) Revenue Requirement for Working Capital[(19)+(20)+(21)] x 13.22% $9.35 $9.39 $14.90 $31.88 $25.53(23) Total Customer-Related Costs (per customer per year)[(12)+(13)+(14)+(15)+(16)+(17)+(18)+(22)] $287.27 $292.51 $523.16 $1,229.20 $954.8024
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 30 of 38COMPUTATION OF ANNUAL MARGINAL COSTSTable 23 B. Computation of Annual Customer-Related Marginal CostsInvestment - Meter, House Regulators & ServicesSC3CH SC3IND SC3MUN SC3HP SC5RNH------------------------------------ (2010 Dollars) ------------------------------------(1) (2) (3) (4) (5)(1) Meter & H. Regulator Investment (cost per unit) $5,164.92 $6,685.48 $5,255.69 $49,540.00 $271.63(2) With General Plant Loading (1) x 1.382 $7,135.86 $9,236.66 $7,261.26 $68,444.46 $375.29(3) Annual Economic Charge Related toCapital Investment 12.56% 12.56% 12.56% 12.56% 12.56%(4) Service Investment (cost per service) $3,042.58 $6,625.79 $3,042.58 $8,995.73 $1,158.75(5) With General Plant Loading (4) x 1.382 $4,203.63 $9,154.19 $4,203.63 $12,428.50 $1,600.93(6) Annual Economic Charge Related toCapital Investment 12.02% 12.02% 12.02% 12.02% 12.02%(7) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00%(8) Total Carrying Charge Meters & H. Reg. (3) + (7) 12.56% 12.56% 12.56% 12.56% 12.56%(9) Total Carrying Charge Services (6)+(7) 12.02% 12.02% 12.02% 12.02% 12.02%(10) Annualized Meter & H. Regulator Costs (2) x (8) $896.45 $1,160.37 $912.21 $8,598.43 $47.15(11) Annualized Service Costs (5) x (9) $505.17 $1,100.11 $505.17 $1,493.61 $192.39(12) Total Annualized Meter, H. Reg. & Service Costs (10)+(11) $1,401.63 $2,260.48 $1,417.38 $10,092.04 $239.54O&M - Meter, House Regulators & Services(13) Meter & H. Reg. O&M Expense $1,457.11 $1,886.09 $1,482.72 $13,976.07 $1.96(14) Service Lateral O&M Expense $9.69 $9.69 $9.69 $9.69 $8.73(15) Customer Accounts Expense (excluding uncollectables) $159.56 $262.74 $262.74 $1,241.75 $16.61(16) Uncollectibles $127.38 $218.84 $218.84 $1,109.47 $7.38(17) Customer Service and Informational Expense $14.89 $26.25 $26.25 $129.71 $0.20(18) A&G Loading [(13)+(14)+(15)+(17)] x 0.0248(Non-plant Related) $40.68 $54.15 $44.15 $380.60 $0.68Working Capital(19) Materials and Supplies [(2)+(5)] x 2.34% $265.34 $430.35 $268.28 $1,892.43 $46.24(20) Prepayments [(2)+(5)] x 1.040% $117.93 $191.26 $119.23 $841.08 $20.55(21) Cash Working Capital Allowance[(13)+(14)+(15)+(17)+(18)] x 12.50% $210.24 $279.86 $228.19 $1,967.23 $3.52(22) Revenue Requirement for Working Capital[(19)+(20)+(21)] x 13.22% $78.46 $119.17 $81.40 $621.44 $9.30(23) Total Customer-Related Costs (per customer per year)[(12)+(13)+(14)+(15)+(16)+(17)+(18)+(22)] $3,289.40 $4,837.41 $3,543.17 $27,560.77 $284.4025
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 31 of 38COMPUTATION OF ANNUAL MARGINAL COSTSTable 23 C. Computation of Annual Customer-Related Marginal CostsInvestment - Meter, House Regulators & ServicesSC5RH SC5CH SC5IND SC5MUN SC7T------------------------------------ (2010 Dollars) ------------------------------------(1) (2) (3) (4) (5)(1) Meter & H. Regulator Investment (cost per unit) $271.63 $720.21 $1,951.27 $1,309.69 $7,650.00(2) With General Plant Loading (1) x 1.382 $375.29 $995.05 $2,695.88 $1,809.46 $10,569.24(3) Annual Economic Charge Related toCapital Investment 12.56% 12.56% 12.56% 12.56% 12.56%(4) Service Investment (cost per service) $1,158.23 $1,464.94 $1,908.76 $1,908.76 n/a(5) With General Plant Loading (1) x 1.382 $1,600.21 $2,023.97 $2,637.14 $2,637.14 $0.00(6) Annual Economic Charge Related toCapital Investment 12.02% 12.02% 12.02% 12.02% 12.02%(7) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00%(8) Total Carrying Charge Meters & H. Reg. (3) + (7) 12.56% 12.56% 12.56% 12.56% 12.56%(9) Total Carrying Charge Services (6)+(7) 12.02% 12.02% 12.02% 12.02% 12.02%(10) Annualized Meter & H. Regulator Costs (2) x (8) $47.15 $125.00 $338.67 $227.32 $1,327.78(11) Annualized Service Costs (5) x (9) $192.31 $243.23 $316.92 $316.92 $0.00(12) Total Annualized Meter, H. Reg. & Service Costs (10)+(11) $239.45 $368.24 $655.59 $544.24 $1,327.78O&M - Meter, House Regulators & Services(13) Meter & H. Reg. O&M Expense $1.96 $203.18 $550.49 $369.48 $2,158.19(14) Service Lateral O&M Expense $8.73 $9.69 $9.69 $9.69 $9.69(15) Customer Accounts Expense (excluding uncollectables) $17.68 $22.26 $29.50 $29.50 $94.90(16) Uncollectibles $9.22 $7.88 $13.10 $13.10 $74.57(17) Customer Service and Informational Expense $0.25 $0.96 $1.62 $1.62 $11.82(18) A&G Loading [(13)+(14)+(15)+(17)] x 0.0248(Non-plant Related) $0.71 $5.85 $14.65 $10.17 $56.37Working Capital(19) Materials and Supplies [(2)+(5)] x 2.34% $46.23 $70.64 $124.79 $104.05 $247.32(20) Prepayments [(2)+(5)] x 1.040% $20.55 $31.40 $55.46 $46.24 $109.92(21) Cash Working Capital Allowance[(13)+(14)+(15)+(17)+(18)] x 12.50% $3.67 $30.24 $75.74 $52.56 $291.37(22) Revenue Requirement for Working Capital[(19)+(20)+(21)] x 13.22% $9.31 $17.49 $33.84 $26.82 $85.75(23) Total Customer-Related Costs (per customer per year)[(12)+(13)+(14)+(15)+(16)+(17)+(18)+(22)] $287.31 $635.55 $1,308.50 $1,004.62 $3,819.0726
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 32 of 38SUMMARY TABLES AND EFFICIENT PRICESIX.SUMMARY TABLES AND EFFICIENT PRICESTable 24 summarizes the seasonal and annual per-therm costs of upper medium-pressure mainsand high-pressure regulator stations developed on Table 21 above, as well as the marginalreliability storage cost from Table 3.Table 24. Summary of Marginal Upper Medium-Pressure Mains, High-Pressure RegulatorStation and Reliability Storage Marginal CostsSeasonal CostsWinter Summer(Dec. - Mar.) (April - Nov.) Annual Cost(2010 cents/therm) (2010 cents/therm)(1) (2) (3)Upper Medium-Pressure Mains 0.19325 0.00000 0.11458High-Pressure Regulator Stations 0.00978 0.00000 0.00580Reliability Storage (applies to SC1 and 5) 0.02175 0.02175 0.02175Total 0.22478 0.02175 0.14213Total without Reliability Storage 0.20303 0.00000 0.12039Table 25 summarizes the monthly local facilities marginal costs that vary with design demand(lower-medium and low-pressure distribution mains and medium and low-pressure regulatorstations) by service classification, before and after CIAC. Columns (1) and (2) show these costsper-MCF of design-day demand. Table 25 also shows, in columns (4 and (5), these monthlymarginal costs on a per-customer basis, derived by multiplying the unit cost by the typicalcustomer’s design demand in each service classification.27
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 33 of 38SUMMARY TABLES AND EFFICIENT PRICESTable 25. Summary of Monthly Medium & Low-Pressure Mains and Reg. StationMarginal Costs (Local Facilities) by Service ClassificationPer MCF of long-term designday demand per monthPer customer per monthFacilities Total Facilities Average Facilities Total FacilitiesCosts Costs Design Day Costs CostsRate Class (after CIAC) (before CIAC) Demand (after CIAC) (before CIAC)2010 $ (MCF) 2010 $(1)*(3) (2)*(3)(1) (2) (3) (4) (5)(1) SC1RNH SC 1 Residential Non Heat $19.47 $21.27 3.01 $58.60 $64.02(2) SC1RH SC 1 Residential Heat 19.47 21.27 3.01 58.60 64.02(3) SC1C SC 1 Commercial 19.47 21.27 9.08 176.79 193.13(4) SC1IND SC 1 Industrial 19.47 21.27 41.55 808.98 883.77(5) SC1MUN SC 1 Municipal 19.47 21.27 22.76 443.14 484.11(6) SC3C SC 3 Commercial 19.47 21.27 133.91 2,607.23 2,848.27(7) SC3IND SC 3 Industrial 19.47 21.27 239.41 4,661.31 5,092.25(8) SC3MUN SC 3 Municipal 19.47 21.27 151.15 2,942.89 3,214.96(9) SC3 HP SC 3 High-Pressure na na na na na(10) SC5RNH SC 5 Residential Non Heat 19.47 21.27 3.01 58.60 64.02(11) SC5RH SC 5 Residential Heat 19.47 21.27 3.01 58.60 64.02(12) SC5C SC 5 Commercial 19.47 21.27 13.63 265.38 289.91(13) SC5IND SC 5 Industrial 19.47 21.27 39.24 764.00 834.63(14) SC5MUN SC 5 Municipal 19.47 21.27 25.17 490.06 535.37(15) SC7T SC 7 Non-Residential for DG 19.47 21.27 320.00 6,230.40 6,806.40Table 26 summarizes the monthly marginal customer-related cost (in $ per customer per month),by service classification.28
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 34 of 38SUMMARY TABLES AND EFFICIENT PRICESTable 26. Summary of Monthly Marginal Customer-Related Cost by Service ClassificationMonthlyCustomer-RelatedRate Class Cost per Customer(2010 Dollars)(1)(1) SC1RNH SC 1 Residential Non Heat $23.94(2) SC1RH SC 1 Residential Heat 24.38(3) SC1C SC 1 Commercial 43.60(4) SC1IND SC 1 Industrial 102.43(5) SC1MUN SC 1 Municipal 79.57(6) SC3C SC 3 Commercial 274.12(7) SC3IND SC 3 Industrial 403.12(8) SC3MUN SC 3 Municipal 295.26(9) SC3 HP SC 3 High-Pressure 2,296.73(10) SC5RNH SC 5 Residential Non Heat 23.70(11) SC5RH SC 5 Residential Heat 23.94(12) SC5C SC 5 Commercial 52.96(13) SC5IND SC 5 Industrial 109.04(14) SC5MUN SC 5 Municipal 83.72(15) SC7T SC 7 Non-Residential for DG 318.26This study found that RG&E’s marginal gas delivery costs in the foreseeable future consist of thecosts of high-pressure regulator stations, upper medium-pressure mains, reliability storage, localdistribution facilities costs (lower medium- and low-pressure mains and regulator stations) andthe customer-related costs of meters, house regulators, service laterals, and customer-relatedexpenses. Only the first three components are a function of gas consumption. RG&E’s othermarginal gas delivery costs are a function of a customer’s presence on the system (customerrelatedcosts) and the customer’s expected long-term design-day demand (local facilities costs),which can be approximated by meter capacity (with the appropriate adjustment for residentialcustomers). 8Efficient rates would mirror the structure of RG&E’s marginal costs and have charges for eachrate component set equal to marginal cost. Efficient, marginal cost-based delivery rate design forRG&E’s gas service would consist of winter volumetric charges to recover high-pressureregulator station and upper medium-pressure mains costs, a year-round volumetric charge forreliability storage, 9 and two fixed monthly charges – one a customer charge that varies by serviceclassification to cover monthly marginal customer costs and a second local facilities charge8 See the discussion in Section III.9 The reliability storage charge could be combined with the other volumetric charge in the winter season.29
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 35 of 38SUMMARY TABLES AND EFFICIENT PRICESbased on meter capacity. For classes in which all customers have similar meter capacities, thecustomer and local facilities charges could be combined in a single per-customer charge. Ofcourse rates set equal to these marginal costs would not produce RG&E’s revenue requirement.Some adjustment would be necessary.Tables 27 A and B compare current charges to efficient prices equal to marginal cost for eachservice classification, using current rate designs. Again, adjustment would be necessary toproduce the target revenue requirement.30
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 36 of 38SC 1 Residential Non HeatSUMMARY TABLES AND EFFICIENT PRICESTable 27 A. Marginal Costs Compared to Current Rates---------------$/customer/mo.------------------- -------------------------$/therm-------------------------Current MarginalCurrent MarginalRates CostsRates CostsCustomer Monthly FixedVolumetric AllCharge CostsRate ThermsBill issuance charge: $0.62 Facilities Cost: $58.60First 3 therms: $14.38 Customer Cost: $23.94$15.00 $82.54 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 1 Residential HeatSC 1 CommercialSC 1 IndustrialSC 1 MunicipalSC 3 Large T CommercialSC 3 Large T IndustrialSC 3 Large T MunicipalBill issuance charge: $0.62 Facilities Cost: $58.60First 3 therms: $14.38 Customer Cost: $24.38$15.00 $82.98 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $176.79First 3 therms: $14.38 Customer Cost: $43.60$15.00 $220.38 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $808.98First 3 therms: $14.38 Customer Cost: $102.43$15.00 $911.41 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $443.14First 3 therms: $14.38 Customer Cost: $79.57$15.00 $522.70 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $2,607.23First 1000: $409.38 Customer Cost: $274.12$410.00 $2,881.34 Next 29,000: $0.08429 $0.12039Next 70,000: $0.06679Next 900,000: $0.02583Over 1,000,000: $0.01333Bill issuance charge: $0.62 Facilities Cost: $4,661.31First 1000: $409.38 Customer Cost: $403.12$410.00 $5,064.43 Next 29,000: $0.08429 $0.12039Next 70,000: $0.06679Next 900,000: $0.02583Over 1,000,000: $0.01333Bill issuance charge: $0.62 Facilities Cost: $2,942.89First 1000: $409.38 Customer Cost: $295.26$410.00 $3,238.15 Next 29,000: $0.08429 $0.12039Next 70,000: $0.06679Next 900,000: $0.02583Over 1,000,000: $0.0133331
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 37 of 38SUMMARY TABLES AND EFFICIENT PRICESTable 27 B. Marginal Costs Compared to Current Rates-----------------$/customer/mo.--------------------- -------------------------$/therm-------------------------Current MarginalCurrent MarginalRates CostsRates CostsCustomer Monthly FixedVolumetric AllCharge CostsRate ThermsSC 3 Large Transportation High-PressureBill issuance charge: $0.62 Facilities Cost: naFirst 1000: $879.38 Customer Cost: $2,296.73$880.00 $2,296.73 Next 29,000: $0.02717 $0.12039Next 70,000: $0.02717Next 900,000: $0.02717Over 1,000,000: $0.01403SC 5 Small Transportation Residential Non HeatBill issuance charge: $0.62 Facilities Cost: $58.60First 3 therms: $14.38 Customer Cost: $23.70$15.00 $82.30 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 5 Small Transportation Residential HeatBill issuance charge: $0.62 Facilities Cost: $58.60First 3 therms: $14.38 Customer Cost: $23.94$15.00 $82.55 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 5 Small Transport CommercialBill issuance charge: $0.62 Facilities Cost: $265.38First 3 therms: $14.38 Customer Cost: $52.96$15.00 $318.34 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 5 Small Transport IndustrialBill issuance charge: $0.62 Facilities Cost: $764.00First 3 therms: $14.38 Customer Cost: $109.04$15.00 $873.04 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 5 Small Transport MunicipalBill issuance charge: $0.62 Facilities Cost: $490.06First 3 therms: $14.38 Customer Cost: $83.72$15.00 $573.78 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 7 Non-Resid Transportation for DG (Summer)Bill issuance charge: $0.00 Facilities Cost: $6,230.40First 3 therms: $15.00 Customer Cost: $318.26$15.00 $6,548.66 Next 97: $0.05583 $0.12039Min. Fixed Charge: $15.00 Next 400: $0.05206Next 500: $0.04602Over 1000: $0.02692SC 7 Non-Resid Transportation for DG (Winter)Bill issuance charge: $0.00 Facilities Cost: $6,230.40First 3 therms: $0.00 Customer Cost: $318.26$0.00 $6,548.66 Next 97: $0.00000 $0.12039Min. Fixed Charge: $15.00 Next 400: $0.00000Next 500: $0.00000Over 1000: $0.0000032
Exhibit __ (RGEHP-3) <strong>Rebuttal</strong>Page 38 of 38NERA Economic ConsultingSuite 1950Los Angeles, California 90017Tel: +1 213 346 3000Fax: +1 213 346 3030www.nera.com1
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 1 of 41February 8, 2010NYSEGMarginal Cost of Gas Delivery Service StudyPrepared for:New York State Electric and Gas Corporation
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 2 of 41Project Team<strong>Hethie</strong> ParmesanoAmparo NietoWilliam RankinJordan NarducciNicholas AmabileNERA Economic Consulting777 South Figueroa Street, Suite 1950Los Angeles, California 90017Tel: +1 213 346 3000Fax: +1 213 346 3030www.nera.com
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 3 of 41ContentsI. INTRODUCTION........................................................................................................................1II. MARGINAL HIGH-PRESSURE DELIVERY COSTS.............................................................3A. Transmission mains .............................................................................................................3B. High-Pressure Regulator Stations........................................................................................3C. Upper Medium-Pressure Distribution Mains.......................................................................4D. Time-Differentiation............................................................................................................4E. Underground Reliability Storage .........................................................................................5III. Marginal Investment in Local Distribution Facilities................................................................6A. Regulator Stations................................................................................................................7B. Mains Investment.................................................................................................................7IV. Distribution Operation and Maintenance Expenses ..................................................................9V. MARGINAL CUSTOMER-RELATED COSTS .....................................................................13A. Meter, House Regulator and Service Lateral.....................................................................13B. Customer Accounts Expenses............................................................................................18C. Customer Service and Informational Expenses .................................................................19VI. OTHER MARGINAL COSTS................................................................................................21A. Administrative and General Expenses...............................................................................21B. General Plant......................................................................................................................21VII. COMPUTATION OF CARRYING CHARGES ...................................................................23VIII. COMPUTATION OF ANNUAL MARGINAL COSTS......................................................25A. Annual Upper Medium-Pressure Mains and High-Pressure Regulator StationMarginal Costs...................................................................................................................25B. Annual Lower Medium- and Low-Pressure Mains and Regulator Station MarginalCosts...................................................................................................................................26C. Annual Customer-Related Costs........................................................................................27IX. SUMMARY TABLES AND EFFICIENT PRICES ...............................................................31NERA Economic Consultingi
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 4 of 41List of Tables and FiguresFigure 1. Simplified NYSEG Gas Delivery System................................................2Table 1. Marginal Investment in Upper Medium-Pressure Mains and High-Pressure Regulator Stations ..............................................................................4Table 2. Relative Probability of Peak Day...............................................................5Table 3. Marginal Reliability Storage Cost per Therm............................................6Table 4. Derivation of Marginal Investment in Medium- and Low-PressureRegulator Stations.............................................................................................7Table 5. Derivation of Marginal Investment in Lower Medium- and Low-Pressure Mains..................................................................................................8Table 6. Regulator Station O&M Expense per MCF/Day.....................................10Table 7. Upper Medium-Pressure Mains O&M Expense per MCF/Day...............11Table 8. Marginal Lower Medium- and Low-Pressure Mains O&M Expenseper MCF/Day..................................................................................................12Table 9. Installed Cost of Meter & House Regulator by ServiceClassification ..................................................................................................13Table 10. Installed Cost of Service Lateral by Service classification...................14Table 11. Meter and House Regulator O&M Expense per Weighted Meter........15Table 12. Meter and House Regulator O&M Expense by ServiceClassification ..................................................................................................16Table 13. Service Lateral O&M Expense per Service..........................................17Table 14. Service Lateral O&M Expense by Service Classification....................18Table 15. Adjustment Factor for Uncollectibles....................................................19Table 16. Customer Accounts and Uncollectibles Expense by ServiceClassification ..................................................................................................19Table 17. Customer Services and Informational Expenses by ServiceClassification ..................................................................................................20Table 18. Loading Factors for A&G Expenses and General Plant........................22Table 19. Incremental Capital Structure and Cost.................................................23Table 20. Economic Carrying Charges..................................................................24Table 21. Annual Upper Medium-Pressure Mains and High-PressureRegulator Station Marginal Costs...................................................................26Table 22. Annual Lower Medium- and Low-Pressure Main and RegulatorStation Marginal Costs ...................................................................................27Table 23 A. Computation of Annual Customer-Related Marginal Costs..............28Table 23 B. Computation of Annual Customer-Related Marginal Costs ..............29Table 23 C. Computation of Annual Customer-Related Marginal Costs ..............30Table 24. Summary of Marginal Upper Medium-Pressure Mains and High-Pressure Regulator Station Marginal Costs ....................................................31Table 25. Summary of Monthly Medium & Low-Pressure Mains and Reg.Station Marginal Costs (Local Facilities) by Service Classification..............32Table 26. Summary of Monthly Marginal Customer-Related Cost byService Classification .....................................................................................33Table 27 A. Marginal Costs Compared to Current Rates ......................................35Table 27 B. Marginal Costs Compared to Current Rates ......................................36NERA Economic Consultingii
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 5 of 41I. INTRODUCTIONNew York State Electric & Gas Corporation (NYSEG) retained NERA Economic Consulting(NERA) to prepare an estimate of the company’s marginal costs of gas delivery service. Thisreport describes the methods for estimating the transmission, distribution and customer-relatedcosts, and presents summary tables of the results.What are marginal costs? Marginal cost is defined as the change in total cost with respect to asmall change in output. To quantify the marginal costs of gas service one must ask and answerthe question: What are the additional costs that would be incurred with changes gas deliveredand consumed at different times of the year and size and number of customers served.Our method for estimating marginal costs is based on the system planning process. Wedetermine the marginal cost of gas by examining the utility’s planning processes to determinewhat drives new investment and purchase decisions and how changes in consumption affectsystem operations. The method is not a formula, but a series of guidelines outlining what shouldbe measured and how the measurements can be made. The components of gas delivery servicecan be grouped in four main categories:1. transmission mains;2. high-pressure regulator stations, upper medium-pressure distribution mains andreliability storage;3. local distribution facilities consisting of medium-pressure regulator stations, lowermedium-pressure mains and low-pressure regulator stations and mains; and4. customer-related facilities and functions, including:a. Meters, house regulators, relief valves and service laterals;b. Customer-related services (meter-reading, billing, accounting, customerinformation and customer service).Figure 1 is a simplified diagram of the components of NYSEG’s gas delivery system.1
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 6 of 41Figure 1. Simplified NYSEG Gas Delivery SystemTRANSMISSIONTransmissionCustomerMeter &house reg.Service lateralTRANSMISSIONMAIN (>125 psi)UPPER MEDIUM-PRESSUREDISTRIBUTIONHPCustomerMeter &house reg.HIGH-PRESSUREREGULATOR STATION300/250 psi to
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 7 of 41II. MARGINAL HIGH-PRESSURE DELIVERY COSTSNYSEG’s transmission mains, high-pressure regulator stations and upper medium-pressuredistribution mains are planned to meet near-term system design-day requirements, taking intoconsideration the expected peak day demands under severe weather conditions.A. Transmission mainsAs Figure 1 above illustrates, NYSEG’s high-pressure transmission mains move the gas to thehigh-pressure regulator stations that feed the distribution system. Marginal transmission costscan be estimated by dividing the cost of planned transmission investment related to growth bythe demand growth triggering that investment. The annualized investment per MCF/day can thenbe assigned to periods of the year based on the relative likelihood that demand growth in eachperiod will require additional investment (typically the measure used is probability of peak).However, NYSEG has not undertaken a transmission project in the past five years and it is notplanning any transmission investment in the following five years. Demand growth can beaccommodated in the near term without the addition of transmission mains capacity. ThereforeNYSEG’s marginal cost of transmission is zero.B. High-Pressure Regulator StationsAs Figure 1 above illustrates, high-pressure regulator stations connect the high-pressure systemto the upper medium-pressure system. Regulator stations are sized based on downstreamdemand, making an allowance for future load growth potential in the area and adequate reservesto insure system reliability as expressed in cubic feet per hour. NYSEG expects to add one highpressureregulator station in the next few years. 1To estimate the Company’s marginal investment in high-pressure regulator stations, wecomputed the cost of this station per MCF/day of capacity. Because capacity in excess ofexpected load must be installed to provide reliable service, we adjusted upwards the cost perMCF/day of capacity by an estimated reserve margin of 7.5% to convert the investment per unitof capacity to an investment per unit of load. We made a further adjustment to reflect the factthat NYSEG has adequate high-pressure regulator station capacity to handle load growth in asignificant portion of its service territory. The estimated marginal investment in high-pressureregulator stations is thus the previous value multiplied by the percentage of the system in whichnear-term load growth is likely to trigger addition investment in these stations (1%). Thesecalculations are shown on Table 1.1 This is the East Seneca POD project.3NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 8 of 41C. Upper Medium-Pressure Distribution MainsInvestment in upper medium-pressure distribution mains is also driven by increases in the neartermpeak day demand. NYSEG expects that about 2.5 % of its five-year budget for mains willconsist of upper medium-pressure mains investment. Following the same procedure described forhigh-pressure regulator stations, we divided the planned investment in upper medium-pressuremains in these projects by their estimated capacity, and adjusted the quotient for the estimatedreserve margin and the portion of the system in which growth is likely to trigger upper mediumpressuremains investment. These calculations are also shown on Table 1.Table 1. Marginal Investment in Upper Medium-Pressure Mains and High-PressureRegulator StationsUpper MediumPressure MainsHigh-PressureRegulator Stations(1) (2)(1) Typical Investment 2009-2013(Thousands of 2010 Dollars) $165 $259(2) Long-Term Capacity in These Projects(MCF/Day) 165 1,700(3) Marginal Investment in Upper-Medium PressureMains and High-pressure Regulator Stations(2010 Dollars/MCF/Day) (1) x 1000 / (2) $1,001.67 $152.35(4) Adjustment for Typical Reserve Marginin Upper-medium Pressure Mains andHigh-pressure Regulator Stations(3) x 1.075 $1,076.80 $163.78(5) Adjustment for Share of System in WhichLoad Growth Will Trigger Such Investment(4) x 1% $10.77 $1.64D. Time-DifferentiationThe need for investment in both high-pressure regulator stations and upper medium-pressuremains is driven by near-term growth in system peak demand. Growth at times of the year that areunlikely to be the system peak do not trigger such investment. Using a statistical analysis of thedistribution daily system gas flows over the period 2004-2008, we produced estimates of therelative likelihood of each month’s having the peak-day demand. These monthly values areshown on Table 2. Based on these monthly probabilities, we grouped the months of Decemberthrough March as the Winter season and April through November as the Summer Season. Totime-differentiate the high-pressure station and upper medium-pressure mains costs, we4NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 9 of 41multiplied the annualized costs (discussed later) by the seasonal probabilities of peak. The resultsof these calculations are shown on the summary tables later in this report.Table 2. Relative Probability of Peak DayRelativeSeasonal ProbabilitiesProbability Winter SummerMonth of Peak (Dec. - Mar.) (April - Nov.)(1) (2) (3)Jan 85.02% 100.00% 0.00%Feb 12.16%Mar 2.34%April 0.00%May 0.00%June 0.00%July 0.00%Aug 0.00%Sept 0.00%Oct 0.00%Nov 0.00%Dec 0.48%E. Underground Reliability StorageNYSEG has some underground storage that provides reliability benefits to the distributionsystem. For each additional unit of gas delivered, NYSEG plans for an incremental change inreliability needs. Thus there is a marginal reliability storage cost.NYSEG has developed an estimate of the embedded cost per therm of these resources, includingcapacity costs and carrying charges on the stored gas, which is used as the basis for a reliabilitysurcharge. We used as our estimate of the marginal cost of this element of service the surchargecalculated by NYSEG, escalated to 2010 dollars, and adjusted for losses, as shown in Table 3.This element of marginal cost is applicable to all NYSEG firm gas customers except SC 1T andSC 5T.5NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 10 of 41Table 3. Marginal Reliability Storage Cost per Therm(1) Reliability Surcharge per Therm(2008 Dollars per Therm) $0.0039(2) Reliability Surcharge per Therm(1) x 1.019 2 $0.0040(2010 Dollars per Therm)(3) Reliability Storage Marginal Cost per Therm Including Losses(1) x 1.0011 $0.0041III.Marginal Investment in Local Distribution FacilitiesAs illustrated in Figure 1 above, local distribution facilities include medium and low-pressureregulator stations, lower medium-pressure mains, and low-pressure mains. These facilities aretypically designed using engineering standards that take into consideration the expected longtermmaximum demands of customers that will use them, not specifically the number ofcustomers or their near-term design-day demands. The costs of this portion of the system aremarginal when the mains and regulator stations are installed and when they are replaced becauseof age, but typically do not vary with customers’ actual gas usage from month to month or yearto year. The capacity of these facilities would be expanded if there were a major increase in thedesign demands of the customers using them. Ideally these costs should be recovered in a fixedcomponent of the rate design, rather than in charges based on gas consumption. We used thesame basic approach to estimate marginal investment for each element of local distributionfacilities, with the following three assumptions:• The characteristics of local facilities installed for customers of various design demandsare relatively constant over time.• The average replacement cost of such facilities on the entire NYSEG system is typical ofthe marginal cost of these facilities going forward.• Meter capacity is a reasonable basis for estimating long-term design-day demand,provided that residential meter capacity is adjusted to reflect the fact that meter capacityfor these customers is about 1.66 times their connected load.For each component of local distribution facilities, we computed the current replacement cost (in2010 dollars) of all such facilities on NYSEG’s system. Some local distribution facilities costsare recovered up front through a customer contribution in aid of construction (CIAC); theremaining costs are recovered over time through rates. At the Company’s request, we developedestimates of local distribution facilities before and after these customer contributions. In theversion that recognizes customer contributions, we subtracted the share of investment typicallypaid for up front by customers. Finally, we divided the net replacement cost by the aggregate6NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 11 of 41design demand at the customer premises, using meter capacity (with the adjustment forresidential meters) as the measure of long-term design-day demand.A. Regulator StationsFor medium- and low-pressure regulator stations, we used the weighted average of the 2010replacement cost of typical stations and multiplied by the number of these stations on the system.Typically customers do not pay upfront for any portion of these stations, so no adjustment forCIAC was required. We then divided the total net replacement cost of medium- and low-pressureregulator stations by the aggregate design-day demand at the customer premises, using metercapacity as the measure of long-term design-day demand. 2 (See Table 4.)Table 4. Derivation of Marginal Investment in Medium- and Low-Pressure RegulatorStations(1) Weighted Average Replacement Cost of TypicalLower Medium- and Low-pressure Regulator Station(Thousands of 2010 Dollars) $115(2) Total Number of Lower Medium- and Low-pressureRegulator Stations in the System 522(3) Total Replacement Cost of Lower Medium- and LowpressureRegulator Stations [(1) * (2)](Thousands of 2010 Dollars) $60,192(4) Aggregate Design Demand at Customer Premises(MMCF/Day) 1,355(5) Marginal Investment in Lower Medium- andLow-pressure Regulator Station [(3) / (4)](2010 Dollars/MCF/day) $44.44B. Mains Investment1. Lower Medium and Low-Pressure MainsTable 5 shows the derivation of marginal investment in lower medium-pressure and low-pressuredistribution mains. We divided the current cost (2010 dollars) of all existing low and lowermedium-pressure mains by the aggregate design demand at the customer premises (discussed2 Residential meter capacity was adjusted because it overstates long-term design-day demand.7NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 12 of 41above). The investment is shown before and after adjusting for CIAC. The CIAC percentage ofsuch investment (11%) is based on customer contributions as a percent of lower mediumpressuremains investment in 2008. 3Table 5. Derivation of Marginal Investment in Lower Medium- and Low-Pressure Mains(1) Replacement Cost of Existing Lower Mediumand Low-Pressure Distribution Mains (after CIAC)(Thousands of 2010 Dollars) $1,165,516(2) Total Replacement Cost of Existing Lower Mediumand Low-Pressure Distribution Mains (before CIAC)(Thousands of 2010 Dollars) $1,309,569(3) Aggregate Design Demand at Customer Premises(MMCF/Day) 1,355(4) Marginal Investment in Lower Medium and Low-Pressure Distribution Mains (after CIAC)(2010 Dollars/MCF/Day) (1) / (3) $860.44(5) Total Marginal Investment in Lower Medium and Low-Pressure Distribution Mains (before CIAC)(2010 Dollars/MCF/Day) (2) / (3) $966.793 NYSEG indicated that all of the customer contributions were for lower medium-pressure mains, and that the 98%of mains investment was lower medium-pressure. We assumed that the same percentage would apply to lowpressuremains.8NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 13 of 41IV.Distribution Operation and Maintenance ExpensesO&M expenses depend on the amount of plant in service. The addition of distribution facilitiesto meet increments in near-term or long-term design-day demand gives rise to increased O&Mexpenses as well. Distribution O&M expenses on marginal investment are, therefore, marginalcosts. We used NYSEG’s average level of distribution O&M expenses in the past five years as aguide for estimating marginal O&M costs. 4NYSEG’s accounting system does not show separate O&M expenses for equipment of variouspressure levels. We allocated Main and Service Operation Expenses (Account #874) to thevarious distribution pressure mains and to service laterals in proportion to mileage. Distributionoverheads 5 were allocated to each type of main, as well as to services and meter and houseregulators in proportion to their shares of total distribution O&M less these overhead accounts.We allocated O&M expenses related to regulator stations to pressure categories in proportion tothe number of regulator stations at each level and the typical O&M per regulator station(categorized by their outlet pressure). Since NYSEG’s marginal transmission main investmentsare zero, there is no marginal O&M cost associated with this system element in the near term. 6On Table 6 we divided regulator station O&M by total system design-day demand and adjustedthese historical costs to 2010 dollars. After examining the trend in unit costs over the five-yearperiod and consulting with NYSEG, we selected the 2008 value as likely to be representative offuture marginal levels of these costs. NYSEG provided typical O&M expenses for each pressurelevel station, which we used to apportion the marginal regulator station expenses to low/mediumandhigh-pressure stations. One additional adjustment is required for the high-pressure stationO&M. Because load growth is not likely to trigger high-pressure regulatory station additions inall parts of the service territory, using an O&M expense estimate based on average O&M on thecurrent system would overstate marginal O&M. Therefore, we adjusted the high-pressure O&Mestimate by the same percentage of the system likely to require capacity additions as used for thehigh-pressure regulator marginal investment calculation (1%).4 We excluded Account 871 (load dispatching) as non-marginal and Account 881 (rents) because rents aresubstitutes for past investment and are not marginal expenses.5 Distribution overheads include: Operation Supervision and Engineering (870), Other Expenses (880),Maintenance Supervision and Engineering (885), Maintenance of Other Equipment (894) and Maintenance ofStructures and Improvements (886).6 In addition, marginal demand reductions would not reduce the expenses associated with operating and maintainingthe existing transmission mains.9NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 14 of 41Table 6. Regulator Station O&M Expense per MCF/DayEstimated O&M WeightedTotal System Expense Per Labor and Reg. StationReg. Station Design Demand MCF of Design Materials O&M per MCFYear O&M Expenses Demand Demand Cost Index of Design Demand(000 Dollars) (MMCF/day) ($/MCF/day) (2010=1.00) (2010$/MCF/day)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 $1,045 1,354.56 $0.77 0.7737 $1.00(2) 2005 1,494 1,354.56 1.10 0.8353 1.32(3) 2006 1,076 1,354.56 0.79 0.8701 0.91(4) 2007 1,789 1,354.56 1.32 0.8923 1.48(5) 2008 2,386 1,354.56 1.76 0.9517 1.85(6) Estimated Annual Marginal Reg. Station O&M per MCF/day[Value for 2008] $1.85(7) Low and Medium Pressure Share (6) x Share of Total (95.5%) $1.77(8) High-Pressure Share (6) x Share of Total (4.5%) 0.08(9) High-Pressure Station O&M Adjusted for Share of System Requiring AdditionalCapacity in Response to Load Growth (8) x 1% $0.00The process for developing estimates of upper medium-pressure mains O&M followed the sameapproach, except that we included losses in the estimate of design-day demand, and used thesame adjustment for the percent of the system not likely to require upper medium-pressure mainsexpansion in response to marginal load growth. Table 7 shows the computations. Table 8 showsa corresponding calculation for low- and lower medium-pressure mains.10NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 15 of 41Table 7. Upper Medium-Pressure Mains O&M Expense per MCF/DayTotalUpper System O&M Weighted Upper MediumMedium-Pressure Design Expense Per Labor and Pressure MainsMains Demand MCF of Materials O&M per MCF ofYear O&M Expense Incl. Losses Design Demand Cost Index Design Demand(000 Dollars) (MMCF/day) ($/MCF/day) (2010=1.00) (2010$/MCF/day)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 $570.13 1,356.05 $0.42 0.7737 $0.54(2) 2005 483.13 1,356.05 0.36 0.8353 0.43(3) 2006 755.62 1,356.05 0.56 0.8701 0.64(4) 2007 623.50 1,356.05 0.46 0.8923 0.52(5) 2008 608.27 1,356.05 0.45 0.9517 0.47(6) Estimated Annual Upper Medium PressureMains O&M per MCF/day [Value for 2008] $0.47(7) Adjustment for percent of system requiring upper medium-pressuremains investment in response to load growth (6) x 1% $0.0011NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 16 of 41Table 8. Marginal Lower Medium- and Low-Pressure Mains O&M Expense per MCF/DayLower Medium & Total O&M Weighted Lower Medium &Low-pressure System Expense Per Labor and Low-pressure MainsMains Design MCF of Materials O&M per MCF ofYear O&M Expense Demand Design Demand Cost Index Design Demand(000 Dollars) (MMCF/day) ($/MCF/day) (2010=1.00) (2010$/MCF/day)(1) / (2) (3) / (4)(1) (2) (3) (4) (5)(1) 2004 $7,500.30 1,354.56 $5.54 0.7737 $7.16(2) 2005 6,355.76 1,354.56 4.69 0.8353 5.62(3) 2006 9,940.40 1,354.56 7.34 0.8701 8.43(4) 2007 8,202.38 1,354.56 6.06 0.8923 6.79(5) 2008 8,001.99 1,354.56 5.91 0.9517 6.21(6) Estimated Annual Lower Medium and Low-pressureMains O&M per MCF/day [Value for 2008] $6.2112NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 17 of 41V. MARGINAL CUSTOMER-RELATED COSTSA. Meter, House Regulator and Service Lateral1. Marginal Investment of Meter, House Regulator and ServiceLateralNYSEG supplied the current weighted-average installed costs of meters, including houseregulators and relief valves, for each customer category. NYSEG also supplied the typical percustomercosts of service lateral by class. These customer-related marginal investments,converted to 2010 dollars, are shown on Tables 9 and 10.Table 9. Installed Cost of Meter & House Regulator by Service ClassificationCustomerAverage CostClass Description Per Customer(2010$)(1) SC1S SC 1 Residential Heat $311.12(2) SC1S SC 1 Residential Non Heat 311.12(3) SC1S SC 1 Residential Low Income 311.12(4) SC2S SC 2 General Service 819.67(5) SC3S SC 3 Interruptible Sales 7,641.60(6) SC5S SC 5 Gas Cooling n/a(7) SC9S SC 9 Industrial Manufacturing 2,349.62(8) SC13T SC 13T Residential Heat Aggregation Service 311.12(9) SC13T SC 13T Residential Non-Heat Aggregation Service 311.12(10) SC14T SC 14T Non-Residential Aggregation Service 1,235.57(11) SC1T SC 1T Large Firm Transportation 7,641.60(12) SC2T SC 2T Interruptible Transportation 7,641.60(13) SC5T SC 5T Small Firm Transportation 2,349.62(14) SC7T SC 7T Firm or Limited Firm Negotiated Transportation 8,211.8613NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 18 of 41Table 10. Installed Cost of Service Lateral by Service classificationCustomerAverage CostClass Description Per Customer(2010$)(1) SC1S SC 1 Residential Heat $1,294.91(2) SC1S SC 1 Residential Non Heat $1,294.91(3) SC1S SC 1 Residential Low Income $1,294.91(4) SC2S SC 2 General Service $1,908.76(5) SC3S SC 3 Interruptible Sales $6,625.79(6) SC5S SC 5 Gas Cooling n/a(7) SC9S SC 9 Industrial Manufacturing 3,042.58(8) SC13T SC 13T Residential Heat Aggregation Service $1,294.91(9) SC13T SC 13T Residential Non-Heat Aggregation Service $1,294.91(10) SC14T SC 14T Non-Residential Aggregation Service $1,908.76(11) SC1T SC 1T Large Firm Transportation $6,625.79(12) SC2T SC 2T Interruptible Transportation $6,625.79(13) SC5T SC 5T Small Firm Transportation $3,042.58(14) SC7T SC 7T Firm Or Limited Firm Negotiated Transportation $9,360.402. Meter, House Regulator and Service Lateral O&M ExpenseMeter and House Regulator O&M expenses vary by service classification. We divided theseexpenses, along with their associated overheads (as explained in Section IV), by weightednumber of customers, where the weights reflect an allocation of 10% of the expenses toresidential customers and 90% to non-residential customers, with the non-residential componentfurther segmented based on meter cost. (See Table 11.) After converting the historical costs perweighted customer to 2010 dollars, we reviewed the trend and, in consultation with NYSEG,chose the 2008 value as best representing the future levels of these expenses. Table 12 shows theMeter and House Regulator O&M for each service classification. These values are the cost perweighted customer multiplied by each service classification’s meter O&M weight.14NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 19 of 41Table 11. Meter and House Regulator O&M Expense per Weighted Meter2004 2005 2006 2007 2008(1) (2) (3) (4) (5)(1) Meter Operation and MaintenanceExpenses (Thousand Dollars) $11,740 $11,825 $8,821 $6,947 $6,186(2) Number of Customers 252,360 252,824 254,148 255,007 255,997(3) Weighted Customers(2) x 8.83 2,229,330 2,233,432 2,245,125 2,252,714 2,261,456(4) Expense Per WeightedCustomer (Dollars)[(1) / (3)] x 1000 $5.27 $5.29 $3.93 $3.08 $2.74(5) Labor Cost Index (2010 = 1.00) 0.8375 0.8626 0.8885 0.9151 0.9426(6) Expense Per WeightedCustomer in 2010 Dollars(4) / (5) $6.29 $6.14 $4.42 $3.37 $2.90(7) Estimated Annual MarginalExpense per Weighted Customer(Value for 2008)(2010 Dollars) $2.9015NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 20 of 41Table 12. Meter and House Regulator O&M Expense by Service ClassificationMeter AnnualO&M Meter O&MWeighting ExpenseRate Class Factor per Customer(2010 Dollars)(1) x $2.90(1) (2)(1) SC1S SC 1 Residential Heat 1.00 $2.90(2) SC1S SC 1 Residential Non Heat 1.00 2.90(3) SC1S SC 1 Residential Low Income 1.00 2.90(4) SC2S SC 2 General Service 53.57 155.44(5) SC3S SC 3 Interruptible Sales 492.50 1,429.13(6) SC5S SC 5 Gas Cooling 0.00 0.00(7) SC9S SC 9 Industrial Manufacturing 432.60 1,255.32(8) SC13T SC 13T Residential Heat Aggregation Service 1.00 2.90(9) SC13T SC 13T Residential Non-Heat Aggregation Service 1.00 2.90(10) SC14T SC 14T Non-Residential Aggregation Service 80.78 234.40(11) SC1T SC 1T Large Firm Transportation 520.59 1,510.63(12) SC2T SC 2T Interruptible Transportation 502.61 1,458.47(13) SC5T SC 5T Small Firm Transportation 407.87 1,183.56(14) SC7T SC 7T Firm Or Limited Firm Negotiated Trans. 536.67 1,557.30Service O&M expenses are the same for service laterals of all sizes. However, on average,residential customers have less than one service line per customer. We divided Service O&Mexpenses, along with their associated overheads, by the average number of services to computemarginal service-related O&M costs per service (see Table 13). After converting the historicalcosts to 2010 dollars, we reviewed the trend and, in consultation with NYSEG, chose the 2008value as best representing the future levels of these expenses. Table 14 shows the service O&Mfor each service classification. These values are the cost per service multiplied by services percustomer.16NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 21 of 41Table 13. Service Lateral O&M Expense per ServiceAnnualService Lateral Service Lateral Weighted Service LateralOperation & Average Expense Labor and ExpenseMaintenance Number of Per Materials PerYear Expenses Services Service Cost Index Service(000 Dollars) (Dollars) (2010=1.00) (2010 Dollars)[(1) x 1000]/(2) (3)/(4)(1) (2) (3) (4) (5)(1) 2004 $6,677 218,687 $30.53 0.7737 $39.46(2) 2005 $6,816 219,148 31.10 0.8353 37.23(3) 2006 $4,016 220,331 18.23 0.8701 20.95(4) 2007 $4,966 221,028 22.47 0.8923 25.18(5) 2008 $4,894 221,864 22.06 0.9517 23.18(6) Estimated Annual Marginal Service Lateral O&M Expense[Value for 2008] $23.1817NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 22 of 41Table 14. Service Lateral O&M Expense by Service ClassificationAnnualService LateralCustomer Services per O&M ExpenseClass Description Customer Per Customer(2010 Dollars)(1) * 23.18(1) (2)(1) SC1S SC 1 Residential Heat 0.85 19.68(2) SC1S SC 1 Residential Non Heat 0.85 19.68(3) SC1S SC 1 Residential Low Income 0.85 19.68(4) SC2S SC 2 General Service 1.00 23.18(5) SC3S SC 3 Interruptible Sales 1.00 23.18(6) SC5S SC 5 Gas Cooling 1.00 23.18(7) SC9S SC 9 Industrial Manufacturing 1.00 23.18(8) SC13T SC 13T Residential Heat Aggregation Service 0.85 19.68(9) SC13T SC 13T Residential Non-Heat Aggregation Service 0.85 19.68(10) SC14T SC 14T Non-Residential Aggregation Service 1.00 23.18(11) SC1T SC 1T Large Firm Transportation 1.00 23.18(12) SC2T SC 2T Interruptible Transportation 1.00 23.18(13) SC5T SC 5T Small Firm Transportation 1.00 23.18(14) SC7T SC 7T Firm Or Limited Firm Negotiated Transportation 1.00 23.18B. Customer Accounts ExpensesCustomer accounts expenses, composed mainly of meter-reading and billing expenses anduncollectibles, 7 are costs directly attributable to the existence of customers on the system. Weexcluded expenses associated with the merchant function from the marginal delivery costestimates. For customer accounts expenses, other than uncollectibles we determined, inconsultation with NYSEG, that the 2008 expenses are a reasonable proxy for the marginal cost infuture years. We used the results from the 2008 embedded study to identify the cost per customerfor each class.In the case of uncollectibles, which had a two-fold increase from 2007 to 2008, we adjusted theannual cost per customer from the 2008 embedded study by the ratio of the two-year average tothe 2008 level to reduce the effect of the recession. Table 15 shows the calculation of thisuncollectibles ratio and Table 16 shows the estimated marginal costs by service classification.7 We dealt with uncollectibles separately because this component of customer accounts expense is not subject to thecash working capital adjustment, discussed later.18NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 23 of 41Table 15. Adjustment Factor for UncollectiblesYearUncollectibles2007 $7,679,7542008 $9,040,796Average $8,360,275Ratio Average to 2008 92.47%Table 16. Customer Accounts and Uncollectibles Expense by Service ClassificationCustomer CustomerAccounts Accounts EstimatedExpense (excl. Expense (excl. 2008 Marginaluncollectibles) Uncollectibles uncollectibles) Uncollectibles UncollectiblesRate Class per Customer per Customer per Customer per Customer per Customer(2008 Dollars) (2008 Dollars) (2010 Dollars) (2010 Dollars) (2010 Dollars)(1) / 0.9426 (2) / 0.9426 (4) / 0.9247(1) (2) (3) (4) (5)(1) SC1S SC 1 Residential Heat $18.55 $15.82 $19.68 $16.79 $15.52(2) SC1S SC 1 Residential Non Heat 17.78 8.41 18.86 8.92 8.25(3) SC1S SC 1 Residential Low Income 17.81 8.32 18.90 8.82 8.16(4) SC2S SC 2 General Service 25.51 8.91 27.07 9.45 8.74(5) SC3S SC 3 Interruptible Sales 90.57 129.31 96.09 137.18 126.86(6) SC5S SC 5 Gas Cooling 95.72 79.81 101.55 84.67 78.30(7) SC9S SC 9 Industrial Manufacturing 92.20 105.16 97.82 111.57 103.17(8) SC13T SC 13T Residential Heat Aggregation Service 9.04 0.93 9.59 0.98 0.91(9) SC13T SC 13T Residential Non-Heat Aggregation Service 9.04 0.93 9.59 0.98 0.91(10) SC14T SC 14T Non-Residential Aggregation Service 13.15 3.72 13.95 3.95 3.65(11) SC1T SC 1T Large Firm Transportation 90.57 129.31 96.09 137.18 126.86(12) SC2T SC 2T Interruptible Transportation 90.57 129.31 96.09 137.18 126.86(13) SC5T SC 5T Small Firm Transportation 25.13 26.82 26.66 28.45 26.31(14) SC7T SC 7T Firm Or Limited Firm Negotiated Transportation 90.57 129.31 96.09 137.18 126.86C. Customer Service and Informational ExpensesCustomer service and informational expenses also vary with the number of customers on thesystem and are, therefore, marginal. 8 In consultation with NYSEG we used the 2008 embeddedcost values per customer for each classification as our estimate of marginal customer service andinformational expenses. Table 17 shows the expense by service classification. .8 Customer service expenses recovered in the Gas System Benefits Charge (beginning in 2008) are excluded fromthe costs in these calculations.19NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 24 of 41Table 17. Customer Services and Informational Expenses by Service ClassificationCustomer CustomerService ServiceRate Class Expense Expense(2008 Dollars) (2010 Dollars)(1) / 0.9426(1) (2)(1) SC1S SC 1 Residential Heat $1.01 $1.07(2) SC1S SC 1 Residential Non Heat $0.50 $0.53(3) SC1S SC 1 Residential Low Income $0.53 $0.56(4) SC2S SC 2 General Service $1.06 $1.13(5) SC3S SC 3 Interruptible Sales $61.29 $65.02(6) SC5S SC 5 Gas Cooling $1.74 $1.85(7) SC9S SC 9 Industrial Manufacturing $8.52 $9.04(8) SC13T SC 13T Residential Heat Aggregation Service $1.05 $1.11(9) SC13T SC 13T Residential Non-Heat Aggregation Service $1.05 $1.11(10) SC14T SC 14T Non-Residential Aggregation Service $1.76 $1.86(11) SC1T SC 1T Large Firm Transportation $61.29 $65.02(12) SC2T SC 2T Interruptible Transportation $61.29 $65.02(13) SC5T SC 5T Small Firm Transportation $13.44 $14.26(14) SC7T SC 7T Firm Or Limited Firm Negotiated Transportation $61.29 $65.0220NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 25 of 41VI.OTHER MARGINAL COSTSA. Administrative and General ExpensesCertain general corporate administrative and general (A&G) expenses tend to vary withoperating and maintenance expenses. Based on our understanding of NYSEG’s classification ofcosts in the various FERC accounts for A&G expenses (including social security andunemployment taxes), we divided these expenses into two categories: (1) those associated withother types of expenses and (2) those associated with plant. We normally use regression analysison about 20 years of historical data to identify marginal A&G expenses and general plant.However, changes at NYSEG over this period make this approach inappropriate for A&Gloaders.After reviewing recent levels of potentially marginal non-plant related A&G expenses, we foundthat only social security and unemployment taxes are strongly linked to O&M. We developed thenon-plant related A&G loader by computing 2008 social security and unemployment taxes as apercent of non-fuel O&M. The loader is shown in Table 18 belowFor plant-related A&G expenses, we found that the only A&G account directly related to theamount of plant on the system is property insurance. NYSEG provided an estimate of the 2009property insurance rate per $100 of replacement cost of affected plant. Property insurance appliesto stock/inventory items, buildings and equipment and metering and regulator stations valuedover $100,000. We applied this loader only to regulator stations. The plant-related A&G loaderis shown on Table 18 below.B. General PlantGeneral plant consists of items such as office buildings, warehouses, cars, trucks and otherequipment. When a utility adds transmission and distribution plant, its need for general plantincreases as well. Our estimate of NYSEG’s general plant loader, shown on Table 18, is basedon a regression of cumulative additions general plant net of retirements plus the gas portion ofcommon plant on cumulative additions to total gas plant new of retirements (less general andcommon plant), all stated in constant dollars, using data from 1992 – 2008. The coefficient of theexplanatory variable is the loader.21NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 26 of 41Table 18. Loading Factors for A&G Expenses and General PlantEstimate ofLoadingFactor(1) Non-Plant Related A&G Loader 4.19%(2) Plant Related A&G Loader 0.04%(3) General Plant Loader 10.41%22NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 27 of 41VII.COMPUTATION OF CARRYING CHARGESThe sections above describe the development of estimates of marginal investment in severalcategories of plant. To be useful in ratemaking and other marginal cost applications, theinvestment must be converted into annual costs using an economic carrying charge. The annualcharge reflects the elements of NYSEG’s revenue requirement associated with incremental plant:return to stockholders and bondholders, depreciation, and taxes. For use in a marginal cost study,the appropriate stream of annual charges is a stream that rises at the rate of inflation net oftechnical progress and yields the total present value of all costs over the life of the investment.In such a stream, the first year's charge represents the cost in today's dollars of owning the plantor equipment for a year. It also represents the rental rate for such an investment in a competitivemarket.Key inputs for the economic carrying charge calculation include: (1) the utility’s incrementalcost of capital (mix of debt and equity and their respective long-term market costs), (2) theexpected inflation rate for that type of plant, net of technical progress, and (3) the average servicelife and patterns of failure (“Iowa curve”) for that type of plant.NYSEG foresees financing of near-term incremental investment through additional equity(retained earnings and/or infusion of equity capital from the parent company) and long-term debtwith the capital structure and costs shown in Table 19.Table 19. Incremental Capital Structure and CostShare Cost(%) (%)Debt 51.50 7.00Common Stock 48.50 11.43Another integral part of the economic carrying charge calculation is the estimation of the rate ofinflation net of technical progress applicable over the life of the investment. We used 1.9percent 9 as an approximation of the rate of future inflation net of technical progress, based onNYSEG’s recommendation.Finally, an adjustment is required for the fact that not all plant and equipment will last itsestimated service life. Some components will require early replacement, causing added costs,9 This percentage is NYSEG’s expectation for long-term inflation. We assumed that the rate of technologicalprogress in gas delivery plant is subsumed in the inflation estimate.23NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 28 of 41while some will last longer than expected and produce savings. The pattern of expected requiredreplacement for each type of plant is defined by an Iowa Curve. An adjustment for this dispersedpattern of replacements using Iowa Curves was included in the derivation of the economiccarrying charges. The results of these economic carrying charge calculations are presentedbelow. The adjustments for dispersed retirements are shown on line (2) of this table.Table 20. Economic Carrying ChargesHouse Meters,RegulatorRegulatorsMains Stations Services and Install.(1) (2) (3) (4)(1) Present Value of Revenue RequirementsRelated to Incremental $1,000 Investment $1,852.13 $1,831.55 $1,802.40 $1,745.97(2) Present Value Cost of ReplacingDispersed Retirements Related toIncremental $1,000 Investment $51.23 $46.12 $98.93 $107.13(3) Total Present Value Cost Related toIncremental $1,000 Investment (1)+(2) $1,903.36 $1,877.67 $1,901.33 $1,853.10(4) First-Year Annual Economic ChargeRelated to Incremental $1,000 Investment $113.85 $116.53 $119.73 $127.33(5) First-Year Annual Economic Charge Related toIncremental Investment [(4)/$1,000] 11.39% 11.65% 11.97% 12.73%24NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 29 of 41VIII. COMPUTATION OF ANNUAL MARGINAL COSTSThe next step of the study was to apply the economic carrying charges to the marginalinvestment and add the associated expenses.A. Annual Upper Medium-Pressure Mains and High-PressureRegulator Station Marginal CostsThe marginal investments per MCF-day in upper medium-pressure mains and high-pressureregulator stations were adjusted upwards by the general-plant loading factor. We multiplied theresulting figures by the annual economic carrying charge percentage plus the plant-related A&Gloading factor, where appropriate, to yield the annualized plant costs. To these costs we addedthe associated O&M and non-plant related A&G expenses and the revenue requirements forworking capital. The computation of working capital includes cash working capital, materials,supplies and prepayments. Table 21 shows the total annual unit marginal cost calculations forupper medium-pressure mains and high-pressure regulator stations. These annualized costs wereadjusted for losses through the system, and converted to cents per therm, using system loadfactor. The last section of the table computes the costs on a seasonal basis.25NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 30 of 41Table 21. Annual Upper Medium-Pressure Mains and High-Pressure Regulator StationMarginal CostsUpper-Medium High-PressurePressure Mains Regulator Stations(2010 Dollars per MCF of Near-Term DesignDay Demand)(1) Marginal Investment $10.77 $1.64(2) With General Plant Loading (1) x 1.1041 11.89 1.81(3) Annual Economic Carrying Charge Related toCapital Investment 11.39% 11.65%(4) A&G Loading (plant related) 0.00% 0.04%(5) Total Annual Carrying Charge (3) + (4) 11.39% 11.69%(6) Annualized Costs (2) x (5) $1.35 $0.21(7) O&M Expenses 0.00 0.00(8) O&M exp. with A&G Loading (Non-plant Related)(7) x 1.0419 0.00 0.00(9) Annual Cost (6) + (8) $1.36 $0.21Working Capital(10) Material and Supplies (2) x 0.00% $0.00 $0.00(11) Prepayments (2) x 0.00% 0.00 0.00(12) Cash Working Capital Allowance (8) x 12.50% 0.00 0.00(13) Total Working Capital (10) + (11) + (12) 0.00 0.00(14) Revenue Requirement for WorkingCapital (13) x 13.29% $0.00 $0.00(15) Annual Marginal Unit Costs (9) + (14) $1.36 $0.21(16) Annual Marginal Unit Costs (with losses)(15) * 1.0011 $1.36 $0.21(17) Winter Season (Dec. - Mar.) Marginal Unit Costs(with losses) - (16) x Winter Probability of Peak $1.36 $0.21(18) Summer Season (Apr. - Nov.) Marginal Unit Costs(with losses) - (16) x Summer Probability of Peak $0.00 $0.00(2010 cents/therm) (2010 cents/therm)(19) Annual Unit Costs100 x (16) / [(Days in Year * Annual Load Factor ) / (1.03 * 10)] 0.090 0.014(20) Winter Season Unit Costs100 x (17) / [100 x (Days in Winter * Winter Load Factor ) / (1.03 * 10)] 0.161 0.025(21) Summer Season Unit Costs100 x (18) / [Days in Summer * Summer Load Factor ) / (1.03 * 10)] 0.000 0.000B. Annual Lower Medium- and Low-Pressure Mains and RegulatorStation Marginal CostsThe annualization of marginal investments in lower medium- and low-pressure mains andregulator stations followed the same process as in the previous table. Table 22 shows the totalannual unit marginal cost calculations for mains and regulator stations operating at all pressurelevels. The plant-related A&G loading factor (based on property insurance costs) does not applyto the mains. The annualized costs are expressed in $/MCF of long-term design-day demand. The26NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 31 of 41lower medium-pressure and low-pressure mains costs are shown before and after customercontributions.Table 22. Annual Lower Medium- and Low-Pressure Main and Regulator StationMarginal CostsLower Medium andLow-pressure Reg.StationsLower Medium andLow- PressureMains (after CIAC)Total Lower Mediumand Low- PressureMains (before CIAC)(2010 Dollars per MCF of Long-Term Design Day Demand)(1) (2) (3)(1) Marginal Investment $44.44 $860.44 $966.79(2) With General Plant Loading (1) x 1.1041 49.06 961.08 * 1067.43(3) Annual Economic Carrying Charge Related toCapital Investment 11.65% 11.39% 11.39%(4) A&G Loading (plant related) 0.04% 0.00% 0.00%(5) Total Annual Carrying Charge (3) + (4) 11.69% 11.39% 11.39%(6) Annualized Costs (2) x (5) $5.74 $109.42 $121.53(7) O&M Expenses 1.77 6.21 6.21(8) O&M exp. with A&G Loading (Non-plant Related)(7) x 1.0419 1.84 6.47 6.47(9) Annual Cost (6) + (8) $7.58 $115.89 $128.00Working Capital(10) Material and Supplies (2) x 0.00% $0.00 $0.00 * $0.00(11) Prepayments (2) x 0.00% 0.00 0.00 * 0.00(12) Cash Working Capital Allowance (8) x 12.50% 0.23 0.81 0.81(13) Total Working Capital (10) + (11) + (12) 0.23 0.81 0.81(14) Revenue Requirement for WorkingCapital (13) x 13.29% $0.03 $0.11 $0.11(15) Annual Marginal Unit Costs (9) + (14) $7.61 $116.00 $128.11* Adjustments to investment are applied to the total cost, including the CIAC portion.C. Annual Customer-Related CostsThe annual customer-related marginal costs were developed using a procedure similar to that forthe other types of plant. This component includes the cost of the meter and house regulator,service lateral, and customer-related expenses. The resulting costs (in $ per customer) are shownby customer category in Tables 23. The cash working capital component does not apply touncollectibles.27NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 32 of 41Table 23 A. Computation of Annual Customer-Related Marginal CostsInvestment - Meter, House Regulators & ServicesSC1S SC1S SC1S SC2S SC3SResidentialHeatResidentialNon HeatResidentialLow IncomeGeneralServiceInterruptibleSales------------------------------- (2010 Dollars per Customer) -------------------------------(1) (2) (3) (4) (5)(1) Meter & H. Regulator Investment (cost per unit) $311.12 311.12 311.12 819.67 7,641.60(2) With General Plant Loading (1) x 1.104 $343.51 $343.51 $343.51 $905.00 $8,437.09(3) Annual Economic Charge Related toCapital Investment 12.73% 12.73% 12.73% 12.73% 12.73%(4) Service Investment (cost per service) $1,294.91 1,294.91 1,294.91 1,908.76 6,625.79(5) With General Plant Loading (4) x 1.104 $1,429.71 $1,429.71 $1,429.71 $2,107.46 $7,315.53(6) Annual Economic Charge Related toCapital Investment 11.97% 11.97% 11.97% 11.97% 11.97%(7) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00%(8) Total Carrying Charge Meters & H. Reg. (3) + (7) 12.73% 12.73% 12.73% 12.73% 12.73%(9) Total Carrying Charge Services (6)+(7) 11.97% 11.97% 11.97% 11.97% 11.97%(10) Annualized Meter & H. Regulator Costs (2) x (8) $43.74 $43.74 $43.74 $115.23 $1,074.25(11) Annualized Service Costs (5) x (9) $171.17 $171.17 $171.17 $252.32 $875.86(12) Total Annualized Meter, H. Reg. & Service Costs (10)+(11) $214.91 $214.91 $214.91 $367.55 $1,950.12O&M - Meter, House Regulators & Services(13) Meter & H. Reg. O&M Expense $2.90 $2.90 $2.90 $155.44 $1,429.13(14) Service Lateral O&M Expense $19.68 $19.68 $19.68 $23.18 $23.18(15) Customer Accounts Expense (excluding uncollectables) $19.68 $18.86 $18.90 $27.07 $96.09(16) Uncollectibles Customer Accounts Expense $15.52 $8.25 $8.16 $8.74 $126.86(17) Customer Service and Informational Expense $1.07 $0.53 $0.56 $1.13 $65.02(18) A&G Loading [(13)+(14)+(15)+(17)] x 0.0419(Non-plant Related) $1.81 $1.76 $1.76 $8.66 $67.54Working Capital(19) Materials and Supplies [(2)+(5)] x 1.49% $26.42 $26.42 $26.42 $44.89 $234.71(20) Prepayments [(2)+(5)] x 0.940% $16.67 $16.67 $16.67 $28.32 $148.07(21) Cash Working Capital Allowance[(13)+(14)+(15)+(17)+(18)] x 12.50% $5.64 $5.47 $5.48 $26.93 $210.12(22) Revenue Requirement for Working Capital[(19)+(20)+(21)] x 13.29% $6.48 $6.45 $6.45 $13.31 $78.80(23) Total Customer-Related Costs[(12)+(13)+(14)+(15)+(16)+(17)+(18)+(22)] $282.05 $273.34 $273.33 $605.07 $3,836.7328NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 33 of 41Table 23 B. Computation of Annual Customer-Related Marginal CostsInvestment - Meter, House Regulators & ServicesSC5S SC9S SC13T SC13T SC14TGas CoolingIndustrialManufacturingRes. HeatAggregationServiceRes. Non-HeatAggregationServiceNon-Res.AggregationService------------------------------- (2010 Dollars per Customer) -------------------------------(1) (2) (3) (4) (5)(1) Meter & H. Regulator Investment (cost per unit) n/a 2,349.62 311.12 311.12 1,235.57(2) With General Plant Loading (1) x 1.254 $0.00 $2,594.22 $343.51 $343.51 $1,364.19(3) Annual Economic Charge Related toCapital Investment 12.73% 12.73% 12.73% 12.73% 12.73%(4) Service Investment (cost per service) n/a 3,042.58 1,294.91 1,294.91 1,908.76(5) With General Plant Loading (4) x 1.104 $0.00 $3,359.31 $1,429.71 $1,429.71 $2,107.46(6) Annual Economic Charge Related toCapital Investment 11.97% 11.97% 11.97% 11.97% 11.97%(7) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00% 0.00%(8) Total Carrying Charge Meters & H. Reg. (3) + (7) 12.73% 12.73% 12.73% 12.73% 12.73%(9) Total Carrying Charge Services (6)+(7) 11.97% 11.97% 11.97% 11.97% 11.97%(10) Annualized Meter & H. Regulator Costs (2) x (8) $0.00 $330.31 $43.74 $43.74 $173.70(11) Annualized Service Costs (5) x (9) $0.00 $402.20 $171.17 $171.17 $252.32(12) Total Annualized Meter, H. Reg. & Service Costs (10)+(11) $0.00 $732.51 $214.91 $214.91 $426.01O&M - Meter, House Regulators & Services(13) Meter & H. Reg. O&M Expense $0.00 $1,255.32 $2.90 $2.90 $234.40(14) Service Lateral O&M Expense $23.18 $23.18 $19.68 $19.68 $23.18(15) Customer Accounts Expense (excluding uncollectables) $101.55 $97.82 $9.59 $9.59 $13.95(16) Uncollectibles Customer Accounts Expense $78.30 $103.17 $0.91 $0.91 $3.65(17) Customer Service and Informational Expense $1.85 $9.04 $1.11 $1.11 $1.86(18) A&G Loading [(13)+(14)+(15)+(17)] x 0.0419(Non-plant Related) $5.30 $58.00 $1.39 $1.39 $11.45Working Capital(19) Materials and Supplies [(2)+(5)] x 1.49% $0.00 $88.71 $26.42 $26.42 $51.73(20) Prepayments [(2)+(5)] x 0.940% $0.00 $55.96 $16.67 $16.67 $32.63(21) Cash Working Capital Allowance[(13)+(14)+(15)+(17)+(18)] x 12.50% $16.48 $180.42 $4.33 $4.33 $35.61(22) Revenue Requirement for Working Capital[(19)+(20)+(21)] x 13.29% $2.19 $43.20 $6.30 $6.30 $15.94(23) Total Customer-Related Costs[(12)+(13)+(14)+(15)+(16)+(17)+(18)+(22)] $212.36 $2,322.23 $256.80 $256.80 $730.4529NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 34 of 41Table 23 C. Computation of Annual Customer-Related Marginal CostsInvestment - Meter, House Regulators & ServicesSC1T SC2T SC5T SC7TLarge FirmTransportationInterruptibleTransportationSmall FirmTransportationFirm or LimitedFirm NegotiatedTransportation------------------------------- (2010 Dollars per Customer) -------------------------------(1) (2) (3) (4)(1) Meter & H. Regulator Investment (cost per unit) $7,641.60 7,641.60 2,349.62 8,211.86(2) With General Plant Loading (1) x 1.104 $8,437.09 $8,437.09 $2,594.22 $9,066.72(3) Annual Economic Charge Related toCapital Investment 12.73% 12.73% 12.73% 12.73%(4) Service Investment (cost per service) 6,625.79 6,625.79 3,042.58 9,360.40(5) With General Plant Loading (4) x 1.104 $7,315.53 $7,315.53 $3,359.31 $10,334.82(6) Annual Economic Charge Related toCapital Investment 11.97% 11.97% 11.97% 11.97%(7) A&G Loading (Plant Related) 0.00% 0.00% 0.00% 0.00%(8) Total Carrying Charge Meters & H. Reg. (3) + (7) 12.73% 12.73% 12.73% 12.73%(9) Total Carrying Charge Services (6)+(7) 11.97% 11.97% 11.97% 11.97%(10) Annualized Meter & H. Regulator Costs (2) x (8) $1,074.25 $1,074.25 $330.31 $1,154.42(11) Annualized Service Costs (5) x (9) $875.86 $875.86 $402.20 $1,237.35(12) Total Annualized Meter, H. Reg. & Service Costs (10)+(11) $1,950.12 $1,950.12 $732.51 $2,391.77O&M - Meter, House Regulators & Services(13) Meter & H. Reg. O&M Expense $1,510.63 $1,458.47 $1,183.56 $1,557.30(14) Service Lateral O&M Expense $23.18 $23.18 $23.18 $23.18(15) Customer Accounts Expense (excluding uncollectables) $96.09 $96.09 $26.66 $96.09(16) Uncollectibles Customer Accounts Expense $126.86 $126.86 $26.31 $126.86(17) Customer Service and Informational Expense $65.02 $65.02 $14.26 $65.02(18) A&G Loading [(13)+(14)+(15)+(17)] x 0.0419(Non-plant Related) $70.96 $68.77 $52.23 $72.91Working Capital(19) Materials and Supplies [(2)+(5)] x 1.49% $234.71 $234.71 $88.71 $289.08(20) Prepayments [(2)+(5)] x 0.940% $148.07 $148.07 $55.96 $182.37(21) Cash Working Capital Allowance[(13)+(14)+(15)+(17)+(18)] x 12.50% $220.73 $213.94 $162.49 $226.81(22) Revenue Requirement for Working Capital[(19)+(20)+(21)] x 13.29% $80.21 $79.31 $40.82 $92.80(23) Total Customer-Related Costs[(12)+(13)+(14)+(15)+(16)+(17)+(18)+(22)] $3,923.05 $3,867.81 $2,099.52 $4,425.9230NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 35 of 41IX.SUMMARY TABLES AND EFFICIENT PRICESTable 24 summarizes the seasonal per-therm costs of upper medium-pressure mains and highpressureregulator stations developed on Table 21 above, as well as the marginal reliabilitystorage cost from Table 3.Table 24. Summary of Marginal Upper Medium-Pressure Mains and High-PressureRegulator Station Marginal CostsSeasonal CostsWinter Summer(Dec. - Mar.) (April - Nov.) Annual Cost(2010 cents/therm) (2010 cents/therm)(1) (2) (3)Upper Medium-Pressure Mains 0.1610 0.0000 0.0896High-Pressure Regulator Stations 0.0252 0.0000 0.0140Reliability Storage 0.0041 0.0041 0.0041Total 0.1903 0.0041 0.1077Total without Reliability Storage 0.1862 0.0000 0.1036Table 25 summarizes the monthly local facilities marginal costs that vary with design demand(lower medium- and low-pressure distribution mains and medium and low-pressure regulatorstations) by service classification, before and after CIAC. Columns (1) and (2) show these costsper-MCF of design-day demand. Table 25 also shows, in columns (4) and (5), these monthlymarginal costs on a per-customer basis, derived by multiplying the unit cost by the typicalcustomer’s design demand in each service classification.31NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 36 of 41Table 25. Summary of Monthly Medium & Low-Pressure Mains and Reg. StationMarginal Costs (Local Facilities) by Service ClassificationPer MCF of long-term design daydemand per monthPer customer per monthFacilities Total Facilities Average Facilities Total FacilitiesCosts Costs Design Day Costs CostsRate Classification (after CIAC) (before CIAC) Demand (after CIAC) (before CIAC)2010 $ (MCF) 2010 $(1)*(3) (2)*(3)(1) (2) (3) (4) (5)(1) SC1S SC 1 Residential Heat $10.30 $11.31 3.10 $31.93 $35.06(2) SC1S SC 1 Residential Non Heat 10.30 11.31 3.02 31.11 34.15(3) SC1S SC 1 Residential Low Income 10.30 11.31 3.10 31.93 35.06(4) SC2S SC 2 General Service 10.30 11.31 15.92 163.98 180.05(5) SC3S SC 3 Interruptible Sales 10.30 11.31 242.50 2,497.88 2,742.56(6) SC5S SC 5 Gas Cooling na na na na na(7) SC9S SC 9 Industrial Manufacturing 10.30 11.31 140.00 1,442.08 1,583.34(8) SC13T SC 13T Residential Heat Aggregation Service 10.30 11.31 3.46 35.64 39.13(9) SC13T SC 13T Residential Non-Heat Aggreg. Service 10.30 11.31 3.01 31.00 34.04(10) SC14T SC 14T Non-Residential Aggregation Service 10.30 11.31 24.62 253.60 278.44(11) SC1T SC 1T Large Firm Transportation 10.30 11.31 270.00 2,781.15 3,053.58(12) SC2T SC 2T Interruptible Transportation 10.30 11.31 250.00 2,575.14 2,827.39(13) SC5T SC 5T Small Firm Transportation 10.30 11.31 166.00 1,709.89 1,877.38(14) SC7T SC 7T Firm Or Limited Firm Negotiated Trans. 10.30 11.31 320.00 3,296.18 3,619.05Table 26 summarizes the monthly marginal customer-related cost (in dollars per customer permonth), by service classification.32NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 37 of 41Table 26. Summary of Monthly Marginal Customer-Related Cost by Service ClassificationMonthlyCustomer-Customerrelated CostClassification Description per Customer(2010 Dollars)(1) SC1S SC 1 Residential Heat $23.50(2) SC1S SC 1 Residential Non Heat 22.78(3) SC1S SC 1 Residential Low Income 22.78(4) SC2S SC 2 General Service 50.42(5) SC3S SC 3 Interruptible Sales 319.73(6) SC5S SC 5 Gas Cooling 17.70(7) SC9S SC 9 Industrial Manufacturing 193.52(8) SC13T SC 13T Residential Heat Aggregation Service 21.40(9) SC13T SC 13T Residential Non-Heat Aggreg. Service 21.40(10) SC14T SC 14T Non-Residential Aggregation Service 60.87(11) SC1T SC 1T Large Firm Transportation 326.92(12) SC2T SC 2T Interruptible Transportation 322.32(13) SC5T SC 5T Small Firm Transportation 174.96(14) SC7T SC 7T Firm Or Limited Firm Negotiated Trans. 368.83This study found that NYSEG’s marginal gas delivery costs in the foreseeable future consist ofthe costs of high-pressure regulator stations, upper medium-pressure mains, reliability storage,local distribution facilities costs (lower medium- and low-pressure mains and regulator stations)and the customer-related costs of meters, house regulators, service laterals, and customer-relatedexpenses. Only the first three components are a function of gas consumption. NYSEG’s othermarginal gas delivery costs are a function of a customer’s presence on the system (customerrelatedcosts) and the customer’s expected long-term design-day demand (local facilities costs),which can be approximated by meter capacity (with the appropriate adjustment for residentialcustomers). 10Efficient rates would mirror the structure of NYSEG’s marginal costs and have charges for eachrate component set equal to marginal cost. Efficient, marginal cost-based delivery rate design forNYSEG’s gas service would consist of winter volumetric charges to recover high-pressureregulator station and upper medium-pressure mains costs, a year-round volumetric charge to10 See the discussion in Section III.33NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 38 of 41recover reliability storage costs, 11 and two fixed monthly charges – one a customer charge thatvaries by class to cover monthly marginal customer costs and a second local facilities chargebased on meter capacity. For classes in which all customers have similar meter capacities, thecustomer and local facilities charges could be combined in a single per-customer charge. Ofcourse rates set equal to these marginal costs would not produce match NYSEG’s revenuerequirement. Some adjustment would be necessary.Tables 27 A and B compare current charges to efficient prices equal to marginal cost for eachservice classification, using current rate designs. Again, adjustment would be necessary toproduce the target revenue requirement.11 This reliability charge could be combined with the other volumetric charge in winter months.34NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 39 of 41SC1STable 27 A. Marginal Costs Compared to Current RatesCurrent MarginalCurrent MarginalRates CostsRates CostsCustomer Monthly FixedPer All ThermsCharge Costs (2010 $)Therm (2010$)Basic Service Charge$14.30 Customer Cost $23.50Bill Issuance Charge$0.70 Facilities Cost $31.930 3 $15.00 $55.43 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220SC1S NON-HEATBasic Service ChargeBill Issuance Charge$10.30 Customer Cost $22.78$0.70 Facilities Cost $31.110 3 $11.00 $53.89 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220SC1S LOW INCOMEBasic Service ChargeBill Issuance ChargeSC2S$7.70 Customer Cost $22.78$0.70 Facilities Cost $31.930 3 $8.40 $54.71 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220Basic Service Charge$19.30 Customer Cost $50.42Bill Issuance Charge$0.70 Facilities Cost $163.980 3 $20.00 $214.41 $0.0000 $0.10774 500 $0.2900501 15,000 $0.1672Over 15,000 $0.1197SC3S Interruptible SalesSC5S Seasonal Gas CoolingBasic Service ChargeBill Issuance ChargeCustomer Cost $319.73 $0.1077Facilities Cost $2,497.88$2,817.61$19.30 Customer Cost $17.70$0.70 Facilities Cost na0 3 $20.00 $17.70 $0.0000 $0.1077Over 3 $0.0188SC9S Industrial (Binghamton Only)Basic Service ChargeBill Issuance Charge$199.30 Customer Cost $193.52$0.70 Facilities Cost $1,442.080 500 $200.00 $1,635.60 $0.0000 $0.1077501 15,000 $0.1429Over 15,000 $0.1200SC13T (Res Agg-Heat)Basic Service ChargeBill Issuance Charge$14.30 Customer Cost $21.40$0.70 Facilities Cost $35.640 3 $15.00 $57.04 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220SC13T (Res Agg Non-Heat)Basic Service ChargeBill Issuance Charge$14.30 Customer Cost $21.40$0.70 Facilities Cost $31.000 3 $15.00 $52.40 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220SC14T (Non-Res Agg)Basic Service ChargeBill Issuance Charge$19.30 Customer Cost $60.87$0.70 Facilities Cost $253.600 3 $20.00 $314.47 $0.0000 $0.10774 500 $0.2900501 15,000 $0.1672Over 15,000 $0.119735NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 40 of 41Table 27 B. Marginal Costs Compared to Current RatesCurrent RatesMarginal CostsCurrent RatesMarginal CostsCustomer Charge per MonthWithout With SalesSales StatusReservedStatusReservedMonthly Fixed Costs (2010 $)Charge per ThermWithoutSales Status With SalesReserved Status ReservedAll Therms(2010 $)SC1T (Owego, Goshen, Lockport, Combined,Champlain)Basic Service Charge$599.30 $654.85 Customer Cost 326.92Bill Issuance Charge$0.70 $0.70 Facilities Cost 2,781.150 500 $600.00 $655.55 $3,108.07 $0.0000 $0.0000 $0.1036501 15,000 $0.1254 $0.236515,001 50,000 $0.0614 $0.1725Over 50,000 $0.0556 $0.1667SC1T (Elmira)Basic Service Charge$599.30 $654.85 Customer Cost 326.92Bill Issuance Charge$0.70 $0.70 Facilities Cost 2,781.150 500 $600.00 $655.55 $3,108.07 $0.0000 $0.0000 $0.1036501 15,000 $0.1003 $0.211415,001 50,000 $0.0491 $0.1602Over 50,000 $0.0446 $0.1557SC1T (Binghamton)Basic Service Charge$599.30 $654.85 Customer Cost 326.92Bill Issuance Charge$0.70 $0.70 Facilities Cost 2,781.150 500 $600.00 $655.55 $3,108.07 $0.0000 $0.0000 $0.1036501 15,000 $0.1061 $0.217215,001 50,000 $0.0400 $0.1511Over 50,000 $0.0350 $0.1461SC 2T Interruptible Transportation Customer Cost 322.32 $0.1077Facilities Cost 2,575.14$2,897.45SC5TBasic Service Charge$199.30 $254.85 Customer Cost 174.96Bill Issuance Charge$0.70 $0.70 Facilities Cost 1,709.890 500 $200.00 $255.55 $1,884.85 $0.0000 $0.0000 $0.1036501 15,000 $0.1429 $0.2540Over 15,000 $0.1200 $0.2311SC 7T Firm Or Limited Firm NegotiatedTransportationCustomer Cost 368.83 $0.1077Facilities Cost 3,296.18$3,665.0036NERA Economic Consulting
Exhibit __ (NYSEGHP-3) <strong>Rebuttal</strong>Page 41 of 41NERA Economic ConsultingSuite 1950Los Angeles, California 90017Tel: +1 213 346 3000Fax: +1 213 346 3030www.nera.com37NERA Economic Consulting
Exhibit __ (HP-5)Page 1 of 2Simplified Example of TSC as Marginal Transmission Cost - Extended for 3 MonthsInitial TSC Charge(1) NYSEG's monthly transmission revenue requirement $1,000(2) Expected Billing determinants (monthly kWh) 100,000NYSEGOthers90,000 kWh10,000 kWhScenario 1Scenario 2 - NYSEG Load GrowthActual Billing TSC Revenue Actual Billing TSC RevenueDeterminants (a) x (b) Determinants (d) x (e)(a) (b) (c) (d) (e) (f)(3) January TSC (1) / (2) $0.01000 $0.01000(4) NYSEG 95,000 $950.00 96,000 $960.00(5) Others 10,000 $100.00 10,000 $100.00(6) $1,050.00 $1,060.00(7) Overrecovery (6) - (1) $50.00 $60.00(8) February TSC [(1) - (7)]/(2) $0.00950 $0.00940(9) NYSEG 90,000 $855.00 91,000 $855.40(10) Others 10,000 $95.00 10,000 $94.00(11) $950.00 $949.40(12) Overrecovery (11)-(1) -$50.00 -$50.60(13) March TSC [(1)-(12)]/(2) $0.01050 $0.01051(14) NYSEG 85,000 $892.50 86,000 $903.52(15) Others 10,000 $105.00 10,000 $105.06(16) $997.50 $1,008.58(17) Overrecovery (11)-(1) -$2.50 $8.58(18) April TSC [(1)-(17)] / (2) $0.01003 $0.00991(19) NYSEG 90,000 $902.25 90,000 $892.28(20) Others 10,000 $100.25 10,000 $99.14(21) $1,002.50 $991.42(22) Overrecovery (6) - (1) $2.50 -$8.58(23) May TSC [(1)-(22)] / (2) $0.00998 $0.01009(24) NYSEG 90,000 $897.75 90,000 $907.72
Exhibit __ (HP-5)Page 2 of 2(25) Others 10,000 $99.75 10,000 $100.86(26) $997.50 $1,008.58(27) Overrecovery (6) - (1) -$2.50 $8.58(28) June TSC [(1)-(27)] / (2) $0.01003 $0.00991(29) NYSEG 90,000 $902.25 90,000 $892.28(30) Others 10,000 $100.25 10,000 $99.14(31) $1,002.50 $991.42(32) Overrecovery (6) - (1) $2.50 -$8.58In these six months,NYSEG's Delivery Customers Pay:total kWh x TSC assumed in delivery rate ($0.01)(33) January 95,000 $950.00 96,000 $960.00(34) February 90,000 $900.00 91,000 $910.00(35) March 85,000 $850.00 86,000 $860.00(36) April 90,000 $900.00 90,000 $900.00(37) May 90,000 $900.00 90,000 $900.00(38) June 90,000 $900.00 90,000 $900.00(39) 540,000 $5,400.00 543,000 $5,430.00less rebates equal to revenues from other users at monthly TSC rates(40) January 10,000 $100.00 10,000 $100.00(41) February 10,000 $95.00 10,000 $94.00(42) March 10,000 $105.00 10,000 $105.06(43) April 10,000 $100.25 10,000 $99.14(44) May 10,000 $99.75 10,000 $100.86(45) June 10,000 $100.25 10,000 $99.14(46) $600.25 60,000 $598.20(47) Total cost to NYSEG delivery customers (39) - (46) $4,799.75 $4,831.80(48) Cost per kWh (47) / (39b) or (39e) $0.00889 $0.00890(49) Change in cost to NYSEG delivery customers per added kWh $0.01068(47f - 47c) / (39e - 39b)
Exhibit __ (HP-6)Page 1 of 19Replacement Tables for Parmesano’s NYSEG and RG&E Direct TestimonyReplace in Parmesano’s NYSEG Direct Testimony:Table 1. Monthly Efficient Customer and Distribution Facilities Charges(After CIAC)MonthlyMonthlyDistributionDistribution Facilities Monthly TotalFacilities or Charge per Customer MonthlyCustomer Class Charge per kW Customer Charge Charges(2010 $/kW/Month) (2010 $/Month) (2010 $/Month) (2010 $/Month)(2) + (3)(1) (2) (3) (4)(1) SC 1 Residential Service $9.20 $36.80 $11.77 $48.57(2) SC 8 Residential Service Day Night Service $9.20 $36.80 $14.25 $51.05(3) SC 12 Residential Service with Time-of-Use Metering $9.20 $92.00 $18.07 $110.07(4) SC 2 General Service with Demand Metering $6.11 $146.64 $39.41 $186.05(5) SC 3 Primary Service - 25 kW or more - Primary $3.18 $324.36 $167.97 $492.33(6) SC5 Outdoor Lighting Service NA NA $1.42 $1.42(7) SC 6 General Service $8.78 $43.90 $7.05 $50.95(8) SC 7-1 LGS with TOU Metering - Secondary $2.29 $190.07 $93.41 $283.48(9) SC 7-2 LGS with TOU - Primary $3.18 $2,330.94 $230.74 $2,561.68(10) SC 7-4 LGS with TOU Metering - Transmission NA NA $2,062.64 $2,062.64(11) SC 9 General Service - Day Night Service $8.78 $43.90 $7.88 $51.78(12) SL 1 Street Lighting - Contributory Provisions NA NA $4.36 $4.36(13) SL 2 Street Lighting - Energy and Limited Maintenance NA NA $4.36 $4.36(14) SL 3 Standard Street Lighting Service NA NA $4.36 $4.361
Exhibit __ (HP-6)Page 2 of 19Table 2. Monthly Efficient Distribution Demand Charges for Customers with DemandMetersSummer Season Winter Season Off SeasonAnnualOn-Peak Shoulder On-Peak Shoulder On-Peak Mid-Peak On-Peak Mid-Peak------------------------------------------------- (2010 Dollars per kW per month) ------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8)Residential TOU PeriodsSecondary Service(1) TOD Upstream Dist. $4.86 $0.54 $0.00 $0.00 $0.00 $0.00 $2.47 $0.11(2) Dist. Substation $5.94 $0.66 $0.00 $0.00 $0.00 $0.00 $3.02 $0.13$10.80 $1.20 $0.00 $0.00 $0.00 $0.00 $5.49 $0.24(3) Seasonal Upstream Dist. $5.41 $0.00 $0.00(4) Dist. Substation $6.60 $0.00 $0.00$12.00 $0.00 $0.00(5) Annual Upstream Dist. $1.35(6) Dist. Substation $1.65$3.00LGS TOU Periods On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-Peak On-Peak Off-PeakTransmission Service(7) TOD $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00(8) Seasonal $0.00 $0.00 $0.00(9) Annual $0.00Primary Service(10) TOD Upstream Dist. $5.11 $0.05 $0.00 $0.00 $0.00 $0.00 $1.13 $0.01(11) Dist. Substation $6.23 $0.06 $0.00 $0.00 $0.00 $0.00 $1.38 $0.02$11.34 $0.11 $0.00 $0.00 $0.00 $0.00 $2.51 $0.03(12) Seasonal Upstream Dist. $5.16 $0.00 $0.00(13) Dist. Substation $6.29 $0.00 $0.00$11.45 $0.00 $0.00(14) Annual Upstream Dist. $1.29(15) Dist. Substation $1.57$2.86Secondary Service(16) TOD Upstream Dist. $5.35 $0.05 $0.00 $0.00 $0.00 $0.00 $1.18 $0.01(17) Dist. Substation $6.54 $0.06 $0.00 $0.00 $0.00 $0.00 $1.44 $0.02$11.89 $0.11 $0.00 $0.00 $0.00 $0.00 $2.63 $0.03(18) Seasonal Upstream Dist. $5.41 $0.00 $0.00(19) Dist. Substation $6.60 $0.00 $0.00$12.00 $0.00 $0.00(20) Annual Upstream Dist. $1.35(21) Dist. Substation $1.65$3.00Day Night PeriodsSecondary Service(22) TOD Upstream Dist. $5.41 $0.00 $0.00 $0.00 $0.00 $0.00 $1.36 $0.00(23) Dist. Substation $6.60 $0.00 $0.00 $0.00 $0.00 $0.00 $1.66 $0.00$12.00 $0.00 $0.00 $0.00 $0.00 $0.00 $3.03 $0.00(24) Seasonal Upstream Dist. $5.41 $0.00 $0.00(25) Dist. Substation $6.60 $0.00 $0.00$12.00 $0.00 $0.00(26) Annual Upstream Dist. $1.35(27) Dist. Substation $1.65$3.002
Exhibit __ (HP-6)Page 3 of 19Table 4. Monthly Efficient Transmission and Distribution Charges per kWh(if there are no demand charges)Summer Season Winter Season Off SeasonAnnualOn-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak On-Peak Mid-Peak Off-Peak----------------------------------------------------------------------------------------- (2010 Dollars per kWh) -----------------------------------------------------------------------------------------(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12)Residential TOU PeriodsSecondary Service(1) TOD Transmission $0.00382 $0.00378 $0.00372 $0.00382 $0.00379 $0.00375 $0.00377 $0.00371 $0.00382 $0.00378 $0.00372(2) Upstream Dist. $0.02806 $0.00163 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.01426 $0.00033 $0.00000(3) Dist. Substation $0.03425 $0.00199 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.01741 $0.00040 $0.00000$0.06612 $0.00740 $0.00372 $0.00382 $0.00379 $0.00375 $0.00377 $0.00371 $0.03549 $0.00450 $0.00372(4) Seasonal Transmission $0.00377 $0.00379 $0.00375(5) Upstream Dist. $0.00734 $0.00000 $0.00000(6) Dist. Substation $0.00896 $0.00000 $0.00000$0.02008 $0.00379 $0.00375(7) Annual Transmission $0.00376(8) Upstream Dist. $0.00185(9) Dist. Substation $0.00226$0.00788LGS TOU PeriodsTransmission Service(10) TOD Transmission $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352 $0.00352(11) Seasonal Transmission $0.00352 $0.00352 $0.00352(12) Annual Transmission $0.00352Primary Service(13) TOD Transmission $0.00376 $0.00370 $0.00376 $0.00372 $0.00373 $0.00369 $0.00375 $0.00370(14) Upstream Dist. $0.01572 $0.00012 $0.00000 $0.00000 $0.00000 $0.00000 $0.00347 $0.00003(15) Dist. Substation $0.01918 $0.00014 $0.00000 $0.00000 $0.00000 $0.00000 $0.00424 $0.00004$0.03865 $0.00397 $0.00376 $0.00372 $0.00373 $0.00369 $0.01146 $0.00377(16) Seasonal Transmission $0.00373 $0.00375 $0.00371(17) Upstream Dist. $0.00701 $0.00000 $0.00000(18) Dist. Substation $0.00855 $0.00000 $0.00000$0.01928 $0.00375 $0.00371(19) Annual Transmission $0.00372(20) Upstream Dist. $0.00177(21) Dist. Substation $0.00216$0.00764Secondary Service(22) TOD Transmission $0.00381 $0.00374 $0.00381 $0.00376 $0.00378 $0.00373 $0.00379 $0.00374(23) Upstream Dist. $0.01648 $0.00012 $0.00000 $0.00000 $0.00000 $0.00000 $0.00364 $0.00004(24) Dist. Substation $0.02011 $0.00015 $0.00000 $0.00000 $0.00000 $0.00000 $0.00444 $0.00004$0.04039 $0.00402 $0.00381 $0.00376 $0.00378 $0.00373 $0.01188 $0.00381(25) Seasonal Transmission $0.00377 $0.00380 $0.00375(26) Upstream Dist. $0.00734 $0.00000 $0.00000(27) Dist. Substation $0.00896 $0.00000 $0.00000$0.02008 $0.00380 $0.00375(28) Annual Transmission $0.00377(29) Upstream Dist. $0.00185(30) Dist. Substation $0.00226$0.00788Day Night PeriodsSecondary Service(31) TOD Transmission $0.00380 $0.00372 $0.00380 $0.00375 $0.00377 $0.00371 $0.00378 $0.00372(32) Upstream Dist. $0.01068 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00269 $0.00000(33) Dist. Substation $0.01304 $0.00000 $0.00000 $0.00000 $0.00000 $0.00000 $0.00329 $0.00000$0.02752 $0.00372 $0.00380 $0.00375 $0.00377 $0.00371 $0.00976 $0.00372(34) Seasonal Transmission $0.00377 $0.00379 $0.00375(35) Upstream Dist. $0.00734 $0.00000 $0.00000(36) Dist. Substation $0.00896 $0.00000 $0.00000$0.02008 $0.00379 $0.00375(37) Annual Transmission $0.00377Upstream Dist. $0.00185Dist. Substation $0.00226$0.007883
Exhibit __ (HP-6)Page 4 of 19Table 5. Monthly Efficient Outdoor Lighting Charges (Excluding Relamping)ComponentMonthly MarginalCost Per Unit(2010 Dollars per Unit)Safeguard Luminaires(1) 14,500 Nominal Lumen 150 Watt H.P.S. (replacing 7,000 L. 175 Watt M.V.) $7.35(2) 43,000 Nominal Lumen 400 Watt H.P.S. (replacing 17,200 L. 400 Watt M.V.) $8.19(3) 123,000 Nominal Lumen 940 Watt H.P.S. (replacing 48,000 L. 1,000 Watt M.V.) $11.56Area Lights(4) 8,500 Nominal Lumen (100 Watt) H.P.S.* $0.42(5) 8,500 Nominal Lumen (100 Watt) H.P.S. Power Bracket $7.98(6) 14,400 Nominal Lumen (150 Watt) H.P.S. $7.35(7) 24,700 Nominal Lumen (250 Watt) H.P.S. $7.74(8) 45,000 Nominal Lumen (400 Watt) H.P.S. $8.19(9) 126,000 Nominal Lumen (1,000 Watt) H.P.S. $11.56(10) 10,500 Nominal Lumen (175 Watt) Metal Halide Power Bracket $9.18(11) 16,000 Nominal Lumen (250 Watt) Metal Halide $7.83(12) 28,000 Nominal Lumen (400 Watt) Metal Halide $8.18Flood Lights(13) 14,400 Nominal Lumen (150 Watt) H.P.S. $8.49(14) 24,700 Nominal Lumen (250 Watt) H.P.S $8.66(15) 45,000 Nominal Lumen (400 Watt) H.P.S. $8.66(16) 126,000 Nominal Lumen (1,000 Watt) H.P.S. $10.06(17) 16,000 Nominal Lumen (250 Watt) Metal Halide $8.62(18) 28,000 Nominal Lumen (400 Watt) Metal Halide $8.62(19) 88,000 Nominal Lumen (1,000 Watt) Metal Halide $9.86"Shoebox" Luminaire(20) 14,400 Nominal Lumen (150 Watt) H.P.S. $9.88(21) 24,700 Nominal Lumen (250 Watt) H.P.S. $9.91(22) 45,000 Nominal Lumen (400 Watt) H.P.S. $10.67(23) 16,000 Nominal Lumen (250 Watt) Metal Halide $10.50(24) 28,000 Nominal Lumen (400 Watt) Metal Halide $10.34(25) 88,000 Nominal Lumen (1,000 Watt) Metal Halide $11.84Post Tops(26) 5,200 Nominal Lumen (70 Watt) H.P.S. $7.20(27) 8,500 Nominal Lumen (100 Watt) H.P.S. $7.28(28) Brackets 16' and over $2.83(29) Additional Wood Pole Installed for Lamp $11.83(30) Wire Service (Overhead) (Per circuit foot of extension) $0.02(31) 18' Fiberglass Pole - Direct Embedded $7.30(32) 20' Fiberglass Pole - Pedestal Mount $7.30(33) 20' Metal Pole - Pedestal Mount $12.68(34) 30' Metal Pole - Pedestal Mount $14.39(35) 30' Fiberglass Pole - Pedestal Mount $18.22(36) 30' Fiberglass Pole - Direct Embedded $18.22(37) Screw Base for Pedestal Mounted Pole - Light Duty $8.58(38) Screw Base for Pedestal Mounted Pole - Heavy Duty $8.684
Exhibit __ (HP-6)Page 5 of 19Table 6. Monthly Efficient Street Lighting Charges (Excluding Relamping)ComponentMonthly MarginalCost Per Unit(2010 Dollars per Unit)High Pressure Sodium Cobra(1) 70 Watts - 5,200 Lumen $7.44(2) 150 Watts - 14,400 Lumen $7.56(3) 250 Watts - 24,700 Lumen $7.95(4) 400 Watts - 45,000 Lumen $8.40(5) 1000 Watts - 126,000 Lumen $12.12High Pressure Sodium Post Top(6) 50 Watts - 3,300 Lumen $8.41(7) 70 Watts - 5,200 Lumen $8.30(8) 150 Watts - 14,400 Lumen $8.48High Pressure Sodium Cut Off ("Shoebox")(9) 250 Watts - 24,700 Lumen $10.12(10) 400 Watts - 45,000 Lumen $11.30Metal Halide Cobra(11) 100 Watts – 5,800 Lumen $8.31(12) 175 Watts – 12,000 Lumen $7.99(13) 250 Watts - 16,000 Lumen $7.95(14) 400 Watts - 28,000 Lumen $9.02Metal Halide Cut Off (“Shoebox”)(15) 175 Watts – 12,000 Lumen $9.20(16) 250 Watts - 16,000 Lumen $9.77(17) 400 Watts - 28, 000 Lumen $10.56Metal Halide Post Top(18) 70 Watts – 4,000 Lumen $8.86(19) 100 Watts- 5,800 Lumen $9.12(20) 175 Watts - 12,000 Lumen $8.76High Pressure Sodium Special Luminaires(21) 250 Watts - 24,700 - Hiway Liter $21.83(22) 400 Watts - 45,000 - Hiway Liter $18.70(23) 150 Watts - 14,400 - Turnpike $12.93(24) 250 Watts - 24,700 - Turnpike $13.11(25) 400 Watts - 45,000 - Turnpike $13.96(26) 150 Watts - 14,400 - Floodlight $8.69(27) 250 Watts - 24,700 - Floodlight $8.86(28) 400 Watts - 45,000 - Floodlight $8.87Metal Halide - Floodlights(29) 250 Watts - 16,000 Lumen $9.18(30) 400 Watts - 28,000 Lumen $8.84Pole Installed by the Corporation(31) Standard Wood Pole $9.23(32) Wood Pole - high mount use (45' or greater) $11.25(33) Aluminum Pole 16' and under $4.55(34) Alum. Pole over 16' installed prior to August 1, 1987 $7.25(35) Alum. Pole over 16' direct embedded installed after July 31, 1987 $7.25(36) Alum. Pole over 16' pedestal mounted $8.63(37) Fiberglass Pole 18' and under $4.77(38) Fiberglass Pole 18' to 22' $4.77Screw-in steel base for pedestal mounted poles:(39) Light Duty $3.03(40) Heavy Duty $3.11Special Brackets(41) Standard Bracket - 16' and over $4.34Circuit Control(42) Group Controllers $7.32Circuits (Per Trench Foot**)(43) Cable and Conduit $0.03(44) Direct Burial Cable $0.02(45) Cable Only (Conduit Supplied by Customer) $0.02(46) Underground Circuits $0.035
Exhibit __ (HP-6)Page 6 of 19Table 8. Comparison of Current Rates and Efficient (Marginal Cost) Charges (Non-Lighting Classes)Current RatesMarginal CostsService Classification"Total"CustomerChargeDemandDelivery withoutSBCRKVAHCustomerand FacilitiesCost afterCIAC Demand DeliveryDeliveryCosts byTOD($/month) ($/kw /mo) ($/kwh) ($/rkvah)(2010$/month)(2010$/kw/mo) ----- (2010$/kWh) ---------SC 1 All $14.00 $0.0347 $48.57 $0.00788SC 8 Day $0.0359 $0.00976$16.29$51.05Night $0.0171 $0.00372SC 12 On $0.0716 $0.03549Mid $23.00$0.0328 $110.07$0.00450Off $0.0171 $0.00372SC 6 All $15.49 $0.0378 $50.95 $0.00788SC 9 Day $0.0398 $0.00976$18.14$51.78Night $0.0191 $0.00372SC 2 All Blocks $14.00 $8.00 $0.00416 $0.00095 $186.05 $3.00 $0.00376SC 2, 6 and 9 Space Heating All Blocks $0.01361See marginal costs under SC 2, 6 and 9SC 2 I/HLF All Blocks $14.00 $2.30 $0.00102 $0.00095 $186.05 $3.00 $0.00376SC 7-1 On$30.00$8.60 $0.00153 $0.00095$283.48$3.00 $0.00379Off $0.00153 $0.00374SC 7-1 I/HLF On$30.00$3.67 $0.00137 $0.00095$283.48$3.00 $0.00379Off $0.00137 $0.00374SC 3P All Blocks $60.00 $4.60 $0.00409 $0.00095 $492.33 $2.86 $0.00372SC 3P I/HLF All Blocks $60.00 $1.84 $0.00151 $0.00095 $492.33 $2.86 $0.00372SC 7-2 On$210.00$7.50 $0.00262 $0.00095$2,561.68$2.86 $0.00375Off $0.00262 $0.00370SC 7-2 I/HLF On$210.00$2.97 $0.00236 $0.00095$2,561.68$2.86 $0.00375Off $0.00236 $0.00370SC 3S All Blocks $200.00 $3.75 $0.00265 $0.00095 NA NA NASC 3S I/HLF All Blocks $200.00 $1.74 $0.00149 $0.00095 NA NA NASC 7-3 I/HLF On$320.00$0.25 $0.00192 $0.00095 NA NA NAOff $0.00192 NASC 7-4 On $1.73 $0.00212 $0.00095 $0.00 $0.00352$850.00$2,062.64Off $0.00212 $0.00352SC 7-4 I/HLF On $0.00 $0.00157 $0.00095 $0.00 $0.00352$850.00$2,062.64Off $0.00157 $0.003526
Exhibit __ (HP-6)Page 7 of 19Table 9. Comparison of Current Rates and Efficient (Marginal Cost) Charges (LightingDelivery and Fixed Charges)Current RatesMarginal CostsService ClassificationDelivery withoutSBC (per kWh)Bill IsuanceChargeDelivery(2010$ perkWh)Customer Charge(2010 $ per month)SC 5 (Outdoor) $0.02500 $0.0079 $1.42SC 1 (Street Lighting) 0.02500 0.89 $0.0079 $4.36SC 2 (Street Lighting) 0.02500 0.89 $0.0079 $4.36SC 3 (Street Lighting) 0.02500 0.89 $0.0079 $4.367
Exhibit __ (HP-6)Page 8 of 19Table 12. Comparison of Current Rates and Efficient (Marginal Cost) Charges (LightingSC3 Circuit Charges)Current Rates Marginal CostStreet Lighting SC-3Monthly FacilityChargeMonthly FacilitiesCost($ per unit) (2010 $ per unit)Pole Installed by the CorporationStandard Wood Pole $9.92 $9.23Wood Pole - high mount use (45' or greater) 27.15 11.25Steel Pole 4.39 8.63Square Steel Pole 30' 15.95 8.63Aluminum Pole 16' and under 5.98 4.55Alum. Pole over 16' installed prior to August 1, 1987 15.87 7.25Alum. Pole over 16' direct embedded installed after July 31, 1987 15.87 7.25Alum. Pole over 16' pedestal mounted 23.7 8.63Concrete Pole 4.99 4.77Laminated Wood Pole 3.99 4.77Fiberglass Pole 18' and under 5.57 4.77Fiberglass Pole 18' to 22' 7.58 4.77Concrete Base for pedestal mounted poles 21.05 3.11Screw-in steel base for pedestal mounted poles:Light Duty 13.05 3.03Heavy Duty 16.61 3.11Special BracketsStandard Bracket - 16' and over $2.34 4.34Bracket allowance (0.62) naBracket for post-top use on wood poles 0.4 4.34Circuit ControlGroup Controllers $2.99 7.323000 Watt Photo Cell 1.99 7.32Circuits (Per Trench Foot**)Cable and Conduit $0.08 0.03Direct Burial Cable 0.0666 0.02Cable Only (Conduit Supplied by Customer) 0.0355 0.02Underground Circuits 0.0473 0.038
Exhibit __ (HP-6)Page 9 of 19Table 13. Comparison of Current Rates and Efficient (Marginal Cost) Charges (LightingSC5 Luminaire Charges)Marginal Monthly CostNYSEG Street Lighting SC-5Current Rates(Monthly)(excluding Lamp andPhoto Eye)($ per unit) ($ per unit)Safeguard Luminaires14,500 Nominal Lumen 150 Watt H.P.S. (replacing 7,000 L. 175 Watt M.V.) $5.89 $7.3543,000 Nominal Lumen 400 Watt H.P.S. (replacing 17,200 L. 400 Watt M.V.) 8.65 8.19123,000 Nominal Lumen 940 Watt H.P.S. (replacing 48,000 L. 1,000 Watt M.V.) 7.17 11.56Area Lights3,300 Nominal Lumen (50 Watt) H.P.S.* (PACKLITE) 3.20 7.985,200 Nominal Lumen (70 Watt) H.P.S.* (PACKLITE) 3.15 7.988,500 Nominal Lumen (100 Watt) H.P.S.* 3.12 5.083,200 Nominal Lumen (100 Watt) Mercury (PACKLITE)* 3.03 9.188,500 Nominal Lumen (100 Watt) H.P.S. Power Bracket 6.57 7.9814,400 Nominal Lumen (150 Watt) H.P.S. 10.83 7.3524,700 Nominal Lumen (250 Watt) H.P.S. 10.62 7.7445,000 Nominal Lumen (400 Watt) H.P.S. 10.38 8.19126,000 Nominal Lumen (1,000 Watt) H.P.S. 9.68 11.5610,500 Nominal Lumen (175 Watt) Metal Halide Power Bracket 4.47 9.1816,000 Nominal Lumen (250 Watt) Metal Halide 11.51 7.8328,000 Nominal Lumen (400 Watt) Metal Halide 11.36 8.18Flood Lights14,400 Nominal Lumen (150 Watt) H.P.S. 11.55 8.4924,700 Nominal Lumen (250 Watt) H.P.S 11.35 8.6645,000 Nominal Lumen (400 Watt) H.P.S. 11.15 8.66126,000 Nominal Lumen (1,000 Watt) H.P.S. 12.42 10.0616,000 Nominal Lumen (250 Watt) Metal Halide 10.76 8.6228,000 Nominal Lumen (400 Watt) Metal Halide 11.86 8.6288,000 Nominal Lumen (1,000 Watt) Metal Halide 12.37 9.86"Shoebox" Luminaire14,400 Nominal Lumen (150 Watt) H.P.S. 12.20 9.8824,700 Nominal Lumen (250 Watt) H.P.S. 14.39 9.9145,000 Nominal Lumen (400 Watt) H.P.S. 15.26 10.6716,000 Nominal Lumen (250 Watt) Metal Halide 11.53 10.5028,000 Nominal Lumen (400 Watt) Metal Halide 11.37 10.3488,000 Nominal Lumen (1,000 Watt) Metal Halide 16.37 11.84Post Tops3,300 Nominal Lumen (50 Watt) H.P.S. 8.87 7.205,200 Nominal Lumen (70 Watt) H.P.S. 8.87 7.208,500 Nominal Lumen (100 Watt) H.P.S. 8.85 7.28Brackets 16' and over 2.17 2.83Additional Wood Pole Installed for Lamp 11.08 11.83Wire Service (Overhead) (Per circuit foot of extension) 0.031 0.0218' Fiberglass Pole - Direct Embedded 11.44 7.3020' Fiberglass Pole - Pedestal Mount 39.73 7.3020' Metal Pole - Pedestal Mount 39.73 12.6830' Metal Pole - Pedestal Mount 39.73 14.3930' Fiberglass Pole - Pedestal Mount 39.73 18.2230' Fiberglass Pole - Direct Embedded 17.40 18.22Screw Base for Pedestal Mounted Pole - Light Duty 12.1 8.58Screw Base for Pedestal Mounted Pole - Heavy Duty 15.44 8.689
Exhibit __ (HP-6)Page 10 of 19Table 14. Efficient Seasonal or Annual Gas Delivery Charges per ThermSeasonal ChargesWinter Summer(Dec. - Mar.) (April - Nov.) or Annual Charges(2010 cents/therm) (2010 cents/therm)(1) (2) (3)Upper Medium-Pressure Mains 0.1610 0.0000 0.0896High-Pressure Regulator Stations 0.0252 0.0000 0.0140Reliability Storage 0.0041 0.0041 0.0041Total 0.1903 0.0041 0.1077Total without Reliability Storage 0.1862 0.0000 0.103610
Exhibit __ (HP-6)Page 11 of 19Table 15. Efficient Monthly Gas Local Facilities Charges per MCF of Design Demand (orPer Customer)Per MCF of long-termdesign day demand permonthorPer customerper monthFacilitiesFacilitiesRate Classification Charges Charges2010 $ 2010 $(1) (2)(1) SC1S SC 1 Residential Heat $10.30 $31.93(2) SC1S SC 1 Residential Non Heat $10.30 $31.11(3) SC1S SC 1 Residential Low Income $10.30 $31.93(4) SC2S SC 2 General Service $10.30 $163.98(5) SC3S SC 3 Interruptible Sales $10.30 $2,497.88(6) SC5S SC 5 Gas Cooling na na(7) SC9S SC 9 Industrial Manufacturing $10.30 $1,442.08(8) SC13T SC 13T Residential Heat Aggregation Service $10.30 $35.64(9) SC13T SC 13T Residential Non-Heat Aggreg. Service $10.30 $31.00(10) SC14T SC 14T Non-Residential Aggregation Service $10.30 $253.60(11) SC1T SC 1T Large Firm Transportation $10.30 $2,781.15(12) SC2T SC 2T Interruptible Transportation $10.30 $2,575.14(13) SC5T SC 5T Small Firm Transportation $10.30 $1,709.89(14) SC7T SC 7T Firm Or Limited Firm Negotiated Trans. $10.30 $3,296.1811
Exhibit __ (HP-6)Page 12 of 19Table 16. Efficient Gas Customer ChargesMonthlyCustomerCustomerClassification Description Charge(2010 Dollars)(1) SC1S SC 1 Residential Heat $23.50(2) SC1S SC 1 Residential Non Heat $22.78(3) SC1S SC 1 Residential Low Income $22.78(4) SC2S SC 2 General Service $50.42(5) SC3S SC 3 Interruptible Sales $319.73(6) SC5S SC 5 Gas Cooling $17.70(7) SC9S SC 9 Industrial Manufacturing $193.52(8) SC13T SC 13T Residential Heat Aggregation Service $21.40(9) SC13T SC 13T Residential Non-Heat Aggreg. Service $21.40(10) SC14T SC 14T Non-Residential Aggregation Service $60.87(11) SC1T SC 1T Large Firm Transportation $326.92(12) SC2T SC 2T Interruptible Transportation $322.32(13) SC5T SC 5T Small Firm Transportation $174.96(14) SC7T SC 7T Firm Or Limited Firm Negotiated Trans. $368.8312
Exhibit __ (HP-6)Page 13 of 19SC1STable 17 A. Comparison of Current Rates and Marginal CostsCurrent MarginalCurrent MarginalRates CostsRates CostsCustomer Monthly FixedPer All ThermsCharge Costs (2010 $)Therm (2010$)Basic Service Charge$14.30 Customer Cost $23.50Bill Issuance Charge$0.70 Facilities Cost $31.930 3 $15.00 $55.43 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220SC1S NON-HEATBasic Service ChargeBill Issuance Charge$10.30 Customer Cost $22.78$0.70 Facilities Cost $31.110 3 $11.00 $53.89 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220SC1S LOW INCOMEBasic Service ChargeBill Issuance ChargeSC2S$7.70 Customer Cost $22.78$0.70 Facilities Cost $31.930 3 $8.40 $54.71 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220Basic Service Charge$19.30 Customer Cost $50.42Bill Issuance Charge$0.70 Facilities Cost $163.980 3 $20.00 $214.41 $0.0000 $0.10774 500 $0.2900501 15,000 $0.1672Over 15,000 $0.1197SC3S Interruptible SalesSC5S Seasonal Gas CoolingBasic Service ChargeBill Issuance ChargeCustomer Cost $319.73 $0.1077Facilities Cost $2,497.88$2,817.61$19.30 Customer Cost $17.70$0.70 Facilities Cost na0 3 $20.00 $17.70 $0.0000 $0.1077Over 3 $0.0188SC9S Industrial (Binghamton Only)Basic Service ChargeBill Issuance Charge$199.30 Customer Cost $193.52$0.70 Facilities Cost $1,442.080 500 $200.00 $1,635.60 $0.0000 $0.1077501 15,000 $0.1429Over 15,000 $0.1200SC13T (Res Agg-Heat)Basic Service ChargeBill Issuance Charge$14.30 Customer Cost $21.40$0.70 Facilities Cost $35.640 3 $15.00 $57.04 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220SC13T (Res Agg Non-Heat)Basic Service ChargeBill Issuance Charge$14.30 Customer Cost $21.40$0.70 Facilities Cost $31.000 3 $15.00 $52.40 $0.0000 $0.10774 50 $0.3780Over 50 $0.1220SC14T (Non-Res Agg)Basic Service ChargeBill Issuance Charge$19.30 Customer Cost $60.87$0.70 Facilities Cost $253.600 3 $20.00 $314.47 $0.0000 $0.10774 500 $0.2900501 15,000 $0.1672Over 15,000 $0.119713
Exhibit __ (HP-6)Page 14 of 19Table 17 B. Comparison of Current Rates and Marginal Costs (Continued)Current RatesMarginal CostsCurrent RatesMarginal CostsCustomer Charge per MonthWithout With SalesSales StatusReservedStatusReservedMonthly Fixed Costs (2010 $)Charge per ThermWithoutSales Status With SalesReserved Status ReservedAll Therms(2010 $)SC1T (Owego, Goshen, Lockport,Combined, Champlain)Basic Service Charge$599.30 $654.85 Customer Cost 326.92Bill Issuance Charge$0.70 $0.70 Facilities Cost 2,781.150 500 $600.00 $655.55 $3,108.07 $0.0000 $0.0000 $0.1036501 15,000 $0.1254 $0.236515,001 50,000 $0.0614 $0.1725Over 50,000 $0.0556 $0.1667SC1T (Elmira)Basic Service Charge$599.30 $654.85 Customer Cost 326.92Bill Issuance Charge$0.70 $0.70 Facilities Cost 2,781.150 500 $600.00 $655.55 $3,108.07 $0.0000 $0.0000 $0.1036501 15,000 $0.1003 $0.211415,001 50,000 $0.0491 $0.1602Over 50,000 $0.0446 $0.1557SC1T (Binghamton)Basic Service Charge$599.30 $654.85 Customer Cost 326.92Bill Issuance Charge$0.70 $0.70 Facilities Cost 2,781.150 500 $600.00 $655.55 $3,108.07 $0.0000 $0.0000 $0.1036501 15,000 $0.1061 $0.217215,001 50,000 $0.0400 $0.1511Over 50,000 $0.0350 $0.1461SC 2T Interruptible Transportation Customer Cost 322.32 $0.1077Facilities Cost 2,575.14$2,897.45SC5TBasic Service Charge$199.30 $254.85 Customer Cost 174.96Bill Issuance Charge$0.70 $0.70 Facilities Cost 1,709.890 500 $200.00 $255.55 $1,884.85 $0.0000 $0.0000 $0.1036501 15,000 $0.1429 $0.2540Over 15,000 $0.1200 $0.2311SC 7T Firm Or Limited Firm NegotiatedTransportationCustomer Cost 368.83 $0.1077Facilities Cost 3,296.18$3,665.0014
Exhibit __ (HP-6)Page 15 of 19Replace in Parmesano’s RG&E Direct Testimony:Table 1. Monthly Efficient Customer and Distribution Facilities Charges (After CIAC)Monthly Monthly MonthlyDistribution Typical Distribution MarginalFacilities Charge Design Facilities Customer Totalper kW of Demand or Charge per Charge per MonthlyCustomer Class Design Demand (kW) Customer Customer Charges(2010 $/kW/Month) (kW) (2010 $/Month) (2010 $/Month) (2010 $/Month)(1) x (2) (3) + (4)(1) (2) (3) (4) (5)(1) SC 1 Residential $4.39 2.87 $12.59 $18.09 $30.68(2) SC 4 Residential TOU 4.47 7.17 32.06 27.39 59.45(3) SC 2 General Service - Small Use 5.24 24.83 130.12 19.81 149.93(4) SC 3 General Service - 100 kW Min. 3.03 154.09 466.90 108.46 575.36(5) SC 6 Area Lighting na na na 1.06 1.06(6) SC 7 General Service - 12 kW Minimum 3.93 82.64 324.77 24.49 349.26(7) SC 8 LGS TOU - Secondary 3.16 452.43 1,429.69 102.78 1,532.47(8) New Dedicated Substation Service 2.81 2,000.00 5,620.00 80.33 5,700.33(9) SC 8 LGS TOU - Primary 2.31 1,067.34 2,465.56 224.50 2,690.06(10) SC 8 LGS TOU Transmission na na na 1,599.27 1,599.27(11) SC 9 General Service TOU 5.00 35.40 177.00 47.71 224.71(12) SL 1 Street Lighting Service na na na 7.01 7.01(13) SL 2Street Lighting Customer-OwnedEquipment na na na 7.01 7.01(14) SL 3 Traffic Signal na na na 7.01 7.0115
Exhibit __ (HP-6)Page 16 of 19Table 7. Comparison of Current Rates and Marginal Costs (non-lighting classes)CustomerChargeAll kWh1st 200 hrsof demandCurrent Rates Marginal Costs (2010$)AllOtherkWhDeliveryPeakChargeDeliveryOff-PeakCharge($/month) ------------------------------------- ($/kWh) -------------------------------------DemandChargeCustomerCost (afterCIAC)All kWhYear-roundDeliveryPeak CostYear-roundDeliveryOff-Peak CostYear-roundMonthlyMarginalDemand Cost($/kw permo.) ($/month) ---------------------- ($/kWh) ---------------------- ($/kw/mo.)SC No. 1 Residential Service $20.00 $0.0227 $30.68 $0.00965SC4 Residential Service - TOUSchedule I $23.98 $0.02783 $0.02252 $59.45 $0.01706 $0.00434SC4 Residential Service - TOUSchedule II $23.98 $0.04249 $0.02723 $59.45 $0.01706 $0.00434SC2 General Service - SmallUse Secondary $20.00 $0.0145 $149.93 $0.00965SC3 100kW MinimumSecondary $160.00 $10.59 $575.36 $0.00391 $4.19SC7 General Service 12 kWMinimum secondary $50.00 $0.00102 $0.00074 $13.38 $349.26 $0.00391 $4.19SC8 Large Time of Use -Secondary $500.00 $7.93 $1,532.47 $0.00391 $4.19SC8 Large Time of Use - SubTransmission-Secondary $800.00 $4.68 $5,700.33 $0.00376 $2.75SC8 Large Time of Use -Primary $450.00 $7.30 $2,690.06 $0.00385 $4.09SC8 Large Time of Use - SubTransmission - Industrial $700.00 $3.31SC8 Large Time of Use - SubTransmission - Commercial $700.00 $3.39SC8 Large Time of Use -Transmission $950.00 $3.38 $1,599.27 $0.00368 $0.00SC9 Time of Use - Secondary $50.00 $0.00663 $0.00389 $9.01 $224.71 $0.00393 $0.00388 $4.19Table 8. Comparison of Current Rates and Marginal Costs – Lighting Service Customerand Network Delivery ChargesCurrent Rates Marginal Costs (2010$)CustomerDelivery Bill IsuanceDelivery (per Chargewithout SBC Charge (perkWh) (per(per kWh) kWh)Lighting Service Classificationmonth)SC 1 Standard lighting $0.620 $0.0096 $7.01SC 2 Customer-Owned24-hour Burning service $0.0126 $0.620 $0.0096 $7.01Dusk-to-Dawn service $0.0352 $0.620 $0.0096 $7.01Dusk-to-l:00 a.m. service $0.1014 $0.620 $0.0096 $7.01SC 3 Traffic SignalEnergy Delivery per Billing Face: $0.9692 $0.620 $0.0096 $7.01SC 6 Area Lighting $0.620 $0.0096 $1.0616
Exhibit __ (HP-6)Page 17 of 19Table 15. Efficient Gas Customer ChargesMonthlyCustomerCustomerClassification Description Charge(2010 Dollars)(1)(1) SC1RNH SC 1 Residential Non Heat $23.94(2) SC1RH SC 1 Residential Heat 24.38(3) SC1C SC 1 Commercial 43.60(4) SC1IND SC 1 Industrial 102.43(5) SC1MUN SC 1 Municipal 79.57(6) SC3C SC 3 Commercial 274.12(7) SC3IND SC 3 Industrial 403.12(8) SC3MUN SC 3 Municipal 295.26(9) SC3 HP SC 3 High-Pressure 2,296.73(10) SC5RNH SC 5 Residential Non Heat 23.70(11) SC5RH SC 5 Residential Heat 23.94(12) SC5C SC 5 Commercial 52.96(13) SC5IND SC 5 Industrial 109.04(14) SC5MUN SC 5 Municipal 83.72(15) SC7T SC 7 Non-Residential for DG 318.2617
Exhibit __ (HP-6)Page 18 of 19Table 16 A. Comparison of Current and Efficient ChargesSC 1 Residential Non HeatSC 1 Residential HeatSC 1 CommercialSC 1 IndustrialSC 1 MunicipalSC 3 Large T CommercialSC 3 Large T IndustrialSC 3 Large T Municipal---------------$/customer/mo.------------------ ------------------------$/therm------------------------Current MarginalCurrent MarginalRates CostsRates CostsCustomer Monthly FixedVolumetric AllCharge CostsRate ThermsBill issuance charge: $0.62 Facilities Cost: $58.60First 3 therms: $14.38 Customer Cost: $23.94$15.00 $82.54 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $58.60First 3 therms: $14.38 Customer Cost: $24.38$15.00 $82.98 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $176.79First 3 therms: $14.38 Customer Cost: $43.60$15.00 $220.38 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $808.98First 3 therms: $14.38 Customer Cost: $102.43$15.00 $911.41 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $443.14First 3 therms: $14.38 Customer Cost: $79.57$15.00 $522.70 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398Bill issuance charge: $0.62 Facilities Cost: $2,607.23First 1000: $409.38 Customer Cost: $274.12$410.00 $2,881.34 Next 29,000: $0.08429 $0.12039Next 70,000: $0.06679Next 900,000: $0.02583Over 1,000,000: $0.01333Bill issuance charge: $0.62 Facilities Cost: $4,661.31First 1000: $409.38 Customer Cost: $403.12$410.00 $5,064.43 Next 29,000: $0.08429 $0.12039Next 70,000: $0.06679Next 900,000: $0.02583Over 1,000,000: $0.01333Bill issuance charge: $0.62 Facilities Cost: $2,942.89First 1000: $409.38 Customer Cost: $295.26$410.00 $3,238.15 Next 29,000: $0.08429 $0.12039Next 70,000: $0.06679Next 900,000: $0.02583Over 1,000,000: $0.0133318
Exhibit __ (HP-6)Page 19 of 19Table 16B. Comparison of Current and Efficient Charges (Continued)----------------$/customer/mo.-------------------- ------------------------$/therm------------------------Current MarginalCurrent MarginalRates CostsRates CostsCustomer Monthly FixedVolumetric AllCharge CostsRate ThermsSC 3 Large Transportation High-PressureBill issuance charge: $0.62 Facilities Cost: naFirst 1000: $879.38 Customer Cost: $2,296.73$880.00 $2,296.73 Next 29,000: $0.02717 $0.12039Next 70,000: $0.02717Next 900,000: $0.02717Over 1,000,000: $0.01403SC 5 Small Transportation Residential Non HeatBill issuance charge: $0.62 Facilities Cost: $58.60First 3 therms: $14.38 Customer Cost: $23.70$15.00 $82.30 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 5 Small Transportation Residential HeatBill issuance charge: $0.62 Facilities Cost: $58.60First 3 therms: $14.38 Customer Cost: $23.94$15.00 $82.55 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 5 Small Transport CommercialBill issuance charge: $0.62 Facilities Cost: $265.38First 3 therms: $14.38 Customer Cost: $52.96$15.00 $318.34 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 5 Small Transport IndustrialBill issuance charge: $0.62 Facilities Cost: $764.00First 3 therms: $14.38 Customer Cost: $109.04$15.00 $873.04 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 5 Small Transport MunicipalBill issuance charge: $0.62 Facilities Cost: $490.06First 3 therms: $14.38 Customer Cost: $83.72$15.00 $573.78 Next 97: $0.17417 $0.14213Next 400: $0.16241Next 500: $0.14358Over 1000: $0.08398SC 7 Non-Resid Transportation for DG (Summer)Bill issuance charge: $0.00 Facilities Cost: $6,230.40First 3 therms: $15.00 Customer Cost: $318.26$15.00 $6,548.66 Next 97: $0.05583 $0.12039Min. Fixed Charge: $15.00 Next 400: $0.05206Next 500: $0.04602Over 1000: $0.02692SC 7 Non-Resid Transportation for DG (Winter)Bill issuance charge: $0.00 Facilities Cost: $6,230.40First 3 therms: $0.00 Customer Cost: $318.26$0.00 $6,548.66 Next 97: $0.00000 $0.12039Min. Fixed Charge: $15.00 Next 400: $0.00000Next 500: $0.00000Over 1000: $0.0000019
Exhibit __ (HP-7)Page 1 of 6List of Information Request ResponsesSubmitted for the RecordResponse # Question # Subject MatterNYRC-0729 MI-178 TSC ReconciliationNYRC-0733 MI-182 Proxy for MarginalTransmission Costs
Exhibit __ (HP-7)Page 2 of 6New York State Electric & Gas CorporationRochester Gas and Electric CorporationPSC Case No. 09-E-0715PSC Case No. 09-G-0716PSC Case No. 09-E-0717PSC Case No. 09-G-0718Information RequestRequesting Party and No.: Multiple Intervenors (MI-178)NYRC Response No.: NYRC-0729 (MI-178)Request Date: December 11, 2009Information Requested of: NYSEG Marginal Cost of ServiceReply Date: December 24, 2009Responsible Witness: NYSEG Marginal Cost of ServiceQUESTION:178. On page 10 of Exhibit __ (NYSEGHP-2), it states that “if NYSEG’s delivery servicecustomers use more electricity, NYSEG is responsible for additional TSC charges.”a. Reconcile that statement with the seemingly contradictory statement in theprevious sentence that NYSEG does not make explicit TSC payments. (Emphasisadded)b. Why does Dr. Parmesano use the term “additional”? Additional to what?RESPONSE:a. The example below is a simplified illustration of the effect of an increase in NYSEG load onthe additional TSC cost per kWh to NYSEG’s delivery customers. The initial TSC charge($0.01/kWh) is adjusted each month for over- or under-recovery of the revenue requirement.The actual revenue recovered from NYSEG customers consists of the total kWH times theTSC rate included in delivery charges, less revenues from other TSC payers. As NYSEGloads are increased in Scenario 2, the TSC charge is reduced, and the credits for other TSCpayers are reduced, increasing the costs assessed to NYSEG’s customers. In the example, the
Exhibit __ (HP-7)Page 3 of 6additional cost to NYSEG customers per kWh of additional load is equal to the initial TSCcharge.Simplified Example of TSC as Marginal Transmission CostInitial TSC Charge(1) NYSEG's monthly transmission revenue requirement $1,000(2) Expected Billing total determinants (monthly kWh) 100,000NYSEGOthers90,000 kWh10,000 kWhScenario 1Scenario 2 - NYSEG Load GrowthActual Billing TSC Revenue Actual Billing TSC RevenueDeterminants (a) x (b) Determinants (a) x (b)(a) (b) (c) (d) (e) (f)(3) January TSC (1) / (2) $0.01000 $0.01000(4) NYSEG 95,000 $950.00 96,000 $960.00(5) Others 10,000 $100.00 10,000 $100.00(6) $1,050.00 $1,060.00(7) Overrecovery (6) - (1) $50.00 $60.00(8) February TSC [(1) - (7)]/(2) $0.00950 $0.00940(9) 90,000 $855.00 91,000 $855.40(10) 10,000 $95.00 10,000 $94.00(11) $950.00 $949.40(12) Overrecovery (11)-(1) -$50.00 -$50.60(13) March TSC [(1)-(12)]/(2) $0.01050 $0.01051(14) 85,000 $892.50 86,000 $903.52(15) 10,000 $105.00 10,000 $105.06(16) $997.50 $1,008.58(17) Overrecovery (11)-(1) -$2.50 $8.58In these three months,NYSEG's Delivery Customers Pay:total kWh x TSC assumed in delivery rate ($0.01)(18) January 95,000 $950.00 96,000 $960.00(19) February 90,000 $900.00 91000 $910.00(20) March 85,000 $850.00 86000 $860.00(21) 270,000 $2,700.00 273,000 $2,730.00less rebates equal to revenues from other users at monthly TSC rates(22) January 10,000 $100.00 10,000 $100.00(23) February 10,000 $95.00 10,000 $95.00(24) March 10,000 $105.00 10,000 $105.00(25) $300.00 $300.00(26) Total cost to NYSEG delivery customers (21) - (25) $2,400.00 $2,430.00(27) Cost per kWh (26) / (21b) or (21e) $0.00889 $0.00890(28) Change in cost to NYSEG delivery customers per added kWh $0.01000(26f - 26c) / (21e - 21b)b. Additional to what they would have used before the hypothetical increase in electricity use.
Exhibit __ (HP-7)Page 4 of 6New York State Electric & Gas CorporationRochester Gas and Electric CorporationPSC Case No. 09-E-0715PSC Case No. 09-G-0716PSC Case No. 09-E-0717PSC Case No. 09-G-0718Information RequestRequesting Party and No.: Multiple Intervenors (MI-182)NYRC Response No.: NYRC-0733 (MI-182)Request Date: December 11, 2009Information Requested of: NYSEG Marginal Cost of ServiceReply Date: December 22, 2009Responsible Witness: NYSEG Marginal Cost of ServiceQUESTION:182. On page 10 of Exhibit __ (NYSEGHP-2), it states that NERA used the average of themonthly NTAC charges in August – December of 2007 and January – July of 2009 as aproxy for marginal transmission costs.a. Is that a correct interpretation of Dr. Parmesano’s testimony? If not, correct thepreamble of this information request.b. Why did Dr. Parmesano use the NTAC charges instead of the TSC charges?c. Provide NYSEG-specific TSC charges per MWh for each month from July 2007through the most recent month for which the data is available.d. Provide NYSEG-specific NTAC charges per MWh for each month from July2007 through the most recent month for which the data is available.e. Explain why Dr. Parmesano believes that the charges were atypical in 2008.
Exhibit __ (HP-7)Page 5 of 6RESPONSE:a. No. The reference to “NTAC charges” on this page is a typo. It should read “TSC charges.”b. See response to a.c. See table below.NYSEG TSC RatesJuly 2007 - January 2010($ PER MWH)Month RateJul-07 0.97Aug-07 3.53Sep-07 4.53Oct-07 4.17Nov-07 4.91Dec-07 2.13Jan-08 4.96Feb-08 3.12Mar-08 0.00Apr-08 2.29May-08 4.19Jun-08 1.49Jul-08 0.00Aug-08 0.00Sep-08 0.00Oct-08 0.00Nov-08 0.00Dec-08 1.24Jan-09 4.01Feb-09 3.19Mar-09 2.97Apr-09 3.56May-09 2.76Jun-09 2.93Jul-09 3.57Aug-09 3.23Sep-09 2.45Oct-09 2.29Nov-09 3.65Dec-09 3.50Jan-10 4.39Source: NYISO website:http://mis.nyiso.com/public/P-62list.htmd. See response to a. This information was not used in the Marginal Cost Study.
Exhibit __ (HP-7)Page 6 of 6e. The TSC charges were atypical in August – December of 2008 because they were muchlower than normal. This was caused by very large credits of other transmission revenue itemsthat are part of the TSC calculation (mainly TCC revenue) that were so large that the rateactually went negative in some of these months. NYSEG received FERC’s approval to keepthe rate at zero for those months and roll the revenue that would have caused the rate to gonegative over to the following month(s) until the rate actually went back positive.
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