DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-i CHAPTER 10: NATIONAL IMPACT ANALYSIS

TABLE OF CONTENTS 10.1 INTRODUCTION

.................................................... 10-1

10.1.1 National Impact Analysis Spreadsheet Flowchart

................ 10-2 10.2 NATIONAL ENERGY SAVINGS

....................................... 10-5

10.2.1 National Energy Savings Overview

........................... 10-5 10.2.2 National Energy Savings Inputs

............................. 10-6 10.2.2.1 Size Scaling of Losses and Costs

......................... 10-8 10.2.2.2 Mapping Life-Cycle Cost Design Line Data to Product Classes

. . 10-9 10.2.2.3 Mapping of Candidate Standard Levels to Trial Standard Levels 10-11 10.2.2.4 Root Mean Square Loading

............................ 10-11 10.2.2.5 Load Growth

........................................ 10-12 10.2.2.6 Affected Stock

....................................... 10-13 10.2.2.7 Unit Energy Consumption

.............................. 10-13 10.2.2.8 Electricity Site-to-Source Conversion

..................... 10-14 10.3 NET PRESENT VALUE CALCULATION

............................... 10-16

10.3.1 Net Present Value Overview

............................... 10-16 10.3.2 Net Present Value Inputs

.................................. 10-18 10.3.2.1 First Cost

........................................... 10-19 10.3.2.2 Operating Cost

....................................... 10-20 10.3.2.3 Peak Responsibility Factor

.............................. 10-21 10.3.2.4 Initial Peak Load

..................................... 10-22 10.3.2.5 Electricity Price Forecast Scalar

......................... 10-22 10.3.2.6 Marginal Electricity Costs

.............................. 10-22 10.3.2.7 Discount Rate

........................................ 10-23 10.4 RESULTS

......................................................... 10-23

10.4.1 National Energy Savings and Net Present Value from Trial Standard Levels

......................................... 10-23 10.4.1.1 Liquid-Immersed Results

............................... 10-24 10.4.1.2 Dry-Type Results

..................................... 10-26

LIST OF TABLES Table 10.2.1 Mapping of Design Line to Product Class

........................... 10-10 Table 10.2.2 Mapping of Candidate Standard Level to Trial Standard Level

.......... 10-11 Table 10.2.3 Average Site-to-Source Conversion Factors for No-Load Losses and

Load Losses

.................................................. 10-15DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-ii Table 10.3.1 First Cost of Distribution Transformers by Trial Standard Levels and Product

Class (2004$/kVA)

............................................ 10-20 Table 10.3.2 Peak Responsibility Factors by Product Class

........................ 10-21 Table 10.3.3 Initial Peak Loading by Product Class

.............................. 10-22 Table 10.3.4 Marginal Energy and Demand Costs by Product Class

................. 10-23 Table 10.4.1 Summary of Cumulative National Energy Savings (2010-2038)

and Net Present Value (2010-2073) Impact

.......................... 10-24 Table 10.4.2 Cumulative Primary Energy Savings During 2010-2038: Liquid-Immersed

Transformers by Product Class

................................... 10-24 Table 10.4.3 Net Present Value During 2010-2073: Liquid-Immersed Transformers

by Product Class

.............................................. 10-25 Table 10.4.4 Cumulative Primary Energy Savings During 2010-2038: Dry-Type

Transformers by Product Class

................................... 10-26 Table 10.4.5 Net Present Value During 2010-2073: Dry-Type Transformers

by Product Class

.............................................. 10-27

LIST OF FIGURES Figure 10.1.1 National Impact Analysis Flowchart

................................ 10-3 Figure 10.4.1 Liquid-Immersed Distribution Transformers: National Energy Savings and

Net Present Values Impacts

...................................... 10-25 Figure 10.4.2 Dry-Type Distribution Transformers: Net Energy Savings and Net Present

Value Impacts

................................................ 10-28DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-1 CHAPTER 10: NATIONAL IMPACT ANALYSIS

10.1 INTRODUCTION The Energy Policy and Conservation Act (EPCA) states that any new or amended standard must be chosen so as to achieve the maximum improvement in energy efficiency that is technologically feasible and economically justified. In determining whether economic justification exists, the Department of Energy (DOE) must determine that the benefits of the trial standard level exceed its burdens to the greatest extent practicable. Key factors in this decision are: the total projected amount of energy savings likely to result directly from the imposition of the standard, and the savings in operating costs throughout the estimated average life of the covered product in the type (or class) compared to any increase in the price of, or in the initial charges for or maintenance expenses of, the covered products which are likely to result from the imposition of the standard. To satisfy this EPCA requirement and to more fully understand the national impact of potential efficiency regulations for distribution transformers, the Department conducted a national impact analysis. This analysis assessed future national energy savings (NES) from trial transformer standards as well as the national economic impact using the net present value (NPV) metric. The NES is the cumulative incremental energy savings from a transformer efficiency standard relative to a base case scenario of no national standard over a forecast period. The Department calculated NES for each trial standard level in units of quadrillion Btus (quads) for standards that it assumed will be implemented in the year 2010. The NPV is the net present value of the incremental economic impact on consumers from a trial standard level. The Department calculated the NPV using a method similar to the NES, except that it estimated incremental costs and benefits instead of energy, and discounted the net benefits rather than calculating them as an un-discounted sum. The Department discounted purchases, expenses, and operating costs for transformers using a national average discount factor. The Department calculated the NPV impact from transformers that were purchased between 2010 through 2038 to calculate the total NPV impact from purchases during the forecast period. The Department developed a Microsoft Excel spreadsheet, the national impact spreadsheet, to implement the calculations described above. The spreadsheet calculates capacity and operating cost savings associated with each of the trial standard levels. The NES analysis considers cumulative energy savings through the year 2038, while the NPV considers capacityDRAFT

a The Department maintains the same time period for NPV as it did in the ANOPR. Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-2 and operating cost savings through the year 2073 afor transformers purchased in the period 2010 to 2038. By taking the annual difference between the base case scenario and trial standard levels and summing the discounted annual results, the spreadsheet calculates an NPV for each trial standard level relative to the base case. 10.1.1 National Impact Analysis Spreadsheet Flowchart Figure 10.1.1 presents a graphical flow diagram of the distribution transformer national impact analysis (NES and NPV) model and spreadsheet. In the diagram, the arrows show the direction of information flow of the calculation. The information begins with inputs that are shown as parallelograms. As information flows from these inputs, it may be integrated into intermediate results (shown as rectangles) or through integrating sums or differences (shown as circles) into major outputs that are shown as boxes with curved bottom edges. Note that the shipments model portion of the flow diagram (shaded) is discussed in Chapter 9.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-3 Total Shipments

Retirement Function

New Capacity Shipments Stock Accounting

Affected Stock

Marginal Energy Prices

Source Energy Savings

NES NPV Total Shipments - Retirements

Marginal Heat Rates from NEMS

Discount Rate Peak Responsibility Factor Initial Peak Loading HVOLT 2001Shipments BEA Quality Index EIA Electricity Market Share

First Cost Elasticity

Retirements First Cost by Design Line

First Cost by Product Class

Rated Losses by Product Class Rated

Losses by Design Line
Design Line to Product Class Conversion

Σ Fractional Load Growth RMS Loading from LCC

Site Energy

Savings

Annual Equipment Costs Actual Electricity Use: Peak & Average
Electricity Price Forecast Scalar

Σ Annual Operating Cost Savings

Figure 10.1.1 National Impact Analysis FlowchartDRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-4 The calculation starts with the shipments model (described in Chapter 9) which integrates the inputs of 2001 shipments estimates from the Department’s contractor, 1 the U.S. Bureau of Economic Analysis (BEA) transformer quantity index, 2electricity market shares from the DOE’s Energy Information Administration (EIA), 3, 4and equipment price estimates from the life-cycle cost analysis (LCC) to produce a backcast and a forecast of total shipments. The total shipments and a retirement function feed an accounting of in-service transformers (stocks) to produce estimates of the stock that is affected by trial standards and transformer retirements. When subtracted from total shipments, the transformer retirements produce new capacity shipments, which are those transformers made to supply new electrical capacity. After the shipments calculation, the NES and NPV calculations begin. Key inputs from the LCC analysis are the average rated losses for both no-load and load losses and the cost of transformers, including installation. The losses and the equipment costs then go through a transformer size and product class adjustment that converts the data from representative design lines to average product class information. Additional inputs regarding average and peak losses —including root mean square (RMS) loading, peak loading, and peak responsibility factor—allow a conversion from rated losses into actual losses. At this point, the information flow for the NES and NPV calculation splits into two paths. On one path, the NES calculation sums the watt-hours of energy consumed by the affected stock, and takes the difference between the base case and standards scenario to calculate site energy savings. Marginal heat rates from the National Energy Modeling System (NEMS) 5 then convert the site energy savings to energy savings at the source (i.e., at the power plant). The marginal heat rates from NEMS includes the transmission and distribution losses. The Department performed a sensitivity analysis to analyze an improvement in the heat rate as a result of the efficiency improvement in the standards scenario; the impact was not significant. The sum of annual energy savings for the forecast period through 2038 then provides the final NES number. On the other path, the NPV calculation brings in marginal price inputs from the LCC analysis for both energy costs and capacity costs and for both load losses and no-load losses. The marginal prices, when combined with the actual peak and average losses, provide the estimate of the operating cost. Meanwhile, the adjusted equipment installed cost times the annual shipments provides the estimate of the total annual equipment costs. The Department took three differences to calculate the net impact of the trial standard. The first difference was between the trial standards scenario equipment costs and the base case equipment costs to obtain the net equipment cost increase from a trial standard. The second difference was between the base case scenario operating cost and the trial standards scenario operating cost to obtain the net operatingDRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-5 cost savings from a trial standard. The third difference was between the net operating cost savings and the net equipment cost increase to get the net expense/savings for each year. The Department then discounted the net expenses/savings to 2004 and summed them over the years 2010-2073 for transformers purchased during or before 2038, to provide the NPV impact of a trial standard. Given this overview, the Department provides detailed technical descriptions of the three models below: the shipments model in Chapter 9, the NES model in section 10.2, and the NPV model in section 10.3. Each technical description begins with a summary of the model. It then provides a descriptive overview of how the Department performs each model’s calculations, and follows with a summary of the inputs. The final subsections of each technical description describe each of the major input and computation steps in detail and with equations, when appropriate. After the technical model descriptions, the Department presents the results of the national impact analysis calculations.

10.2 NATIONAL ENERGY SAVINGS The Department developed the NES model to estimate the total national energy savings using the results from the shipments model, combined with information from the LCC on energy savings. The savings shown in the NES reflect decreased losses from the installation of new, more efficient transformer units nationwide in comparison to a base case with no national standards. The NES predicts the energy savings for each of several trial standard levels. Positive values of NES correspond to net energy savings, i.e., a decrease in energy consumption with standards in comparison to the energy consumption in the base case scenario. 10.2.1 National Energy Savings Overview The Department calculated the cumulative incremental energy savings from a trial transformer efficiency standard relative to a base case scenario of no standard over the forecast period. The Department calculated NES for each trial standard level, in units of quads, for standards that it assumed will be implemented in the year 2010. The NES calculation started with transformer shipments and stocks (in-service transformers), estimates of which are outputs of the shipments model (Chapter 9). The Department then obtained estimates of transformer losses from the LCC analysis (Chapter 8). The Department proceeded to calculate the total energy use by the stock of transformers for each year for both a base case and standards case. Over time, in the standards case, more-efficient transformers gradually replace less-efficient ones. Thus, the energy per unit capacity used by the stock of transformers gradually decreases in the standards case relative to the base case. The Department converted energy used by the transformers into the amount of energy consumed at the source of electricity generation (the source energy) with a site-to-source conversion factor. The site-to-source factor accounts forDRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-6 transmission, distribution, and generation losses. For each year analyzed, the difference in source energy use between the base case and standards scenario is the annual energy savings. The Department summed the annual energy savings from 2010 through 2038 to calculate the total NES for the forecast period.In calculating the NES, the Department did not assume any trends in transformer nameplate efficiency besides the incremental efficiency improvement indicated by the LCC calculation. The Department is aware that some states have adopted efficiency standards for low-voltage, dry-type transformers that are equal to TP 1 and that more states may follow in the future. Countering that trend are uncertainties in purchased efficiencies of distribution transformers driven by the uncertainty of utility deregulation. With these counter trends, the Department felt that future efficiency trends were generally indeterminate and therefore chose to use a fixed baseline efficiency. The Department also assumed that the efficiency of transformers did not degrade over time. This means that the annual energy savings can be written in terms of an affected stock described in section 9.3.10 in the shipments chapter: Eq. 10.1



### AES y UEC Base UEC Std Aff Stock y ( ) ( )

_ ( ) = − ×
where: AES(y) = the annual energy savings in year y , UEC Base = the site unit energy consumption for the base case, UEC Std = the site unit energy consumption for the standards case, and Aff_Stock(y) = stock of transformers of all vintages that are operational in year y . Then, given the annual energy savings, the NES can be calculated as a simple sum:
Eq. 10.2 

### NES SiteToSource y AEC y

y Std year 

### = ×

= 

# ∑ ( ) ( )

_ 2038

where: Std_year = the year standards come into effect, SiteToSource(y) = the site-to-source conversion factor in year y , and AEC = the annual energy consumption. Once the shipments model provides the estimate for the affected stock, the key to the NES calculation is in calculating UEC Baseand UEC

Std , given the input from the LCC and including the site-to-source conversion factor that translates site energy into energy consumed atDRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-7 the power plant. In the next section, the inputs necessary for the NES calculation are summarized and then presented individually with complete technical detail. 10.2.2 National Energy Savings Inputs The NES model inputs fall into three broad categories: (1) some inputs help convert the data from the LCC into data for the product classes and transformer size distributions used in the NES; (2) some inputs help calculate the unit energy consumption; and (3) the site-to-source factor then enable the calculation of source energy consumption from site energy use. The specific list of NES model inputs is as follows:
1. Size Scaling of Losses and Costs 2. Mapping of LCC Design Line Data to Product Classes 3. Mapping of Candidate Standard Levels to Trial Standard Levels 4. Root Mean Square Loading 5. Load Growth 6. Affected Stock 7. Effective Date of Standard 8. Unit Energy Consumption 9. Electricity Site-to-Source Conversion The size scaling of losses and costs adjusts LCC representative design line data so it can represent the size distribution of transformers that are in a particular product class. The mapping of LCC design line data to product classes provides the proper inter-design line averaging or adjustments for representation of the product classes (i.e., the design line-to-product class relationship is a many-to-many relationship so the mapping needs to be carefully specified). The mapping of candidate standard levels to trial standard levels aggregates standard levels from design line to product class. The root mean square (RMS) loading is a key factor in estimating actual load losses given the load losses at rated load for a transformer. Load growth over the lifetime of the transformer can modify the average RMS loading that is seen by an affected stock of transformers. The effective date of the standard affects the definition of the affected stock. The unit energy consumption is the energy per unit capacity of an affected stock of transformers and depends on all of the first four inputs. Finally, the electricity site-to-source conversion provides the estimate of energy consumption at the power plant given the site energy use of the transformer. The next section begins the detailed discussion of NES inputs with a description of the size-scaling method that adjusts transformer losses and costs from a representative LCC design line to the distribution of sizes in a transformer product class.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-8 10.2.2.1 Size Scaling of Losses and Costs The size scaling of losses and costs is the scaling relationship or equation that the Department used to project the economic results from one transformer design line to similar transformers of different sizes. It is a key element in adjusting losses and costs from a representative transformer in the LCC to a distribution of transformer sizes represented in the NES calculation. To be consistent across trial standard levels, the Department used the same scaling for the TP1 level as it did for the other levels. As a result, for transformers other than the representative unit, there is a slight difference in efficiency level between the National Electrical Manufacturers Association's TP 1 and the Department's TP 1, as used to calculate national impacts. As described in the engineering analysis, the Department applied the 0.75 power scaling rule (the “0.75 scaling rule”) for projecting losses and costs from one design line to transformers of other sizes. In the NES calculation, shipments are calculated in terms of installed capacity. The losses associated with a stock of transformers, and the costs associated with a capacity shipped, are estimated by multiplying the relevant capacity times the average losses, or costs per unit capacity. Before applying the 0.75 scaling rule, the Department calculated the losses and costs per unit of installed capacity within a given engineering design line. Then the Department calculated an adjustment factor using the 0.75 rule to account for the fact that the representative design line unit used in the engineering analysis is not exactly the “average” transformer size for the set of transformers that design line represents. This adjustment factor is given by the following equation: Eq. 10.3



# [ ] AdjFactor Ship Cap Cap Ship i i i DL i i 

### = × ×

   

  

# ∑ ∑ 0 75 0 75

. . 

### /

where: AdjFactor = adjustment factor that gives the shipments-weighted losses or costs per transformer when multiplied by the design line losses or costs, Ship i = shipments in the i -th size category, Cap i = the rated capacity for the transformers in the i -th size category, and Cap DL = the rated capacity of representative unit of the design line. The Department also used the shipment-weighted average size of transformers represented by a particular design line to calculate the average loss per capacity ( AvgLossPerCap DL), as described in the following equation: Eq. 10.4

AvgLossPerCap DL LossPerCap DL AdjFactor Cap DL Cap avg

= × × /DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-9 where: LossPerCap DL = the loss, or cost per unit capacity, for the design line unit from the LCC analysis, and Cap avg = the shipment-weighted average size of transformers represented by

a particular design line. Once the losses and costs from the LCC represent the correct size distribution, they need a further adjustment so that they represent the appropriate product classes, as described in the next section. 10.2.2.2 Mapping Life-Cycle Cost Design Line Data to Product Classes The NES and NPV calculations use the LCC calculations as the source of most input data. The LCC calculations are performed by design line, whereas any eventual standard would be promulgated by product class. As a first step, therefore, the NES calculation aggregates the LCC design line data to product classes. Design line-to-product class aggregation is the process by which the Department took the results from an economic analysis of engineering design lines and combined them to provide estimates of economic impact by product class. To represent the variety of designs in some product classes, the Department analyzed up to three different design lines per product class. Specifically, product class 1 (single-phase, medium-voltage, liquid-immersed transformers) is represented by three design lines and product class 2 (three-phase, medium-voltage, liquid-immersed transformers) is represented by two design lines. The Department did not specifically examine single-phase, dry-type design lines. For single-phase product classes 5, 7, and 9, the Department used the appropriate three-phase design lines divided by 3. Table 10.2.1 presents the mapping of design line (DL) to product class (PC). Table 10.2.1 Mapping of Design Line to Product Class Product Class BIL* kV** Capacity

kVA *** Mapping
PC 1, Liquid-Immersed, MV, † Single-Phase Any 10-833 DL 1 + DL 2 + DL 3 PC 2, Liquid-Immersed, MV, Three-Phase Any 15-2500 DL 4 + DL 5 PC 3, Dry-Type, LV, ‡ Single-Phase # 10 15-333 DL 6 PC 4, Dry-Type, LV, Three-Phase # 10 15-1000 DL 7 + D L8 PC 5, Dry-Type, MV, Single-Phase 20-45 15-833 (DL 9 ÷ 3) + (DL 10 ÷ 3) PC 6, Dry-Type, MV, Three-Phase 20-45 15-2500 DL 9 + DL 10DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-10 PC 7, Dry-Type, MV, Single-Phase 46-95 15-833 (DL 11 ÷ 3) + (DL 12 ÷ 3) PC 8, Dry-Type, MV, Three-Phase 46-95 15-2500 DL 11 + DL 12 PC 9, Dry-Type, MV, Single-Phase $ 95 75-833 DL 13 ÷ 3 PC 10, Dry-Type, MV, Three-Phase $ 95 225-2500 DL 13 * BIL = Basic Impulse insulation Level ** kV = kilovolt *** kVA = kilovolt-ampere † MV = medium-voltage ‡ LV = low-voltage To aggregate losses from more than one design line, the Department took a shipments-capacity-weighted average of the per kVA transformer characteristics from the economic analysis of the design lines and applied the average per-capacity values to the estimated capacity shipped for each product class. The Department’s contractor 1 provided the capacity shipped for each design line (and each product class), the LCC analysis provided the economic results for each design, and the 0.75 rule provided the re-scaled cost and loss estimates for each size category represented by each design line. The following equation provides the average loss per unit capacity of product class ( AvgLossPerCap PC), as derived from the average loss per unit capacity for a design line: Eq. 10.5



# [ ] AvgLossPer Cap AvgLossPer Cap MS MS PC DL DL DL DL DL = × 

# ∑ ∑ /

where: AvgLossPerCap DL = the average loss per unit capacity for the design line, and MS DL = the capacity market share of the design line. The summation in Eq. 10.5 is over those design lines that constitute a product class. The AvgLossPerCap PC

represents the average loss per unit capacity of the transformer load. For no-load losses no more adjustment is needed, but for load losses, the losses at rated load need to be converted to losses at actual loading. The RMS loading is a key factor in estimating load losses at actual loading. The next section describes the RMS loading input. 10.2.2.3 Mapping of Candidate Standard Level to Trial Standard Level The Department conducted the LCC analysis for six alternate efficiency levels, i.e., candidate standard levels (CSLs), for each representative unit in the 13 design lines. The Department selected the CSL efficiency levels for each design line by applying a set of common economic criteria to intermediate LCC analyses as discussed in Chapter 8, resulting in unique sets of CSL efficiencies for each design line. DOE mapped these LCC analysis results to trialDRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-11 standard levels (TSLs) for the 10 product classes. All CSLs directly map to their corresponding TSLs with the exception of design lines 1 and 4. Due to the close size proximity between design lines 1 and 2 representative units and constraints on material selection combinations within product classes, the Department mapped CSL results for design line 1 and design line 4 to TSLs as shown in Table 10.2.2. Table 10.2.2 Mapping of Candidate Standard Levels to Trial Standard Levels

DL1 DL2 DL3 DL4 DL5 DL6 DL7 DL8 DL9 DL10 DL11 DL12 DL13 TSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 CSL1 TSL2 CSL1 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 CSL2 TSL3 CSL1 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 CSL3 TSL4 CSL2 CSL4 CSL4 CSL3 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4 CSL4 TSL5 CSL3 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 CSL5 TSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6 CSL6

10.2.2.4 Root Mean Square Loading The RMS loading is the root mean square of the hourly transformer loading relative to the transformer capacity. Energy losses in transformers follow the RMS load, not the arithmetic average load. The Department calculated the RMS loading as the root mean square of the transformer load, divided by the transformer rated capacity, times the power factor. (As explained in Chapter 6, while the Department’s method for analysis can derive results for varying power factors, for the analysis presented here the Department set the power factor to the value of one.) The Department used the average national RMS loading for each design line as calculated in the LCC analysis. These values range between 30.5 percent and 59.1 percent for the different design lines. 10.2.2.5 Load Growth The fractional load growth is the fraction by which the load has increased since a transformer was installed. Load growth occurs when new equipment, new appliances, or additional activities occur on the circuits served by distribution transformers. Load growth has the impact of increasing the load losses relative to the losses that the Department estimated during the first year of installation. The Department calculated the fractional load growth from an estimated load growth rate that it used as an input to the LCC analysis. There is a maximum load growth, LGRMax, which is set by the Department at 50 percent for liquid-immersed transformers. The 50 percent valueDRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-12 represents the approximate amount of growth in load that can occur without overloading the transformer beyond a reasonable point, at which time the transformer is assumed to be relocated and reinstalled with the initial peak loading. 6See Institute of Electrical and Electronics Engineers, Inc. (IEEE) Std C57.91-1995 7for details on permissible overloading of mineral-oil immersed transformers. Since IEEE does not report data on permissible overloading of dry-type units, the Department used the same values for both liquid-immersed and dry-type transformers. The age of the transformer at which this point is reached is given by: Eq. 10.6 

### ( ) ( ) age ln 1 LGRMax

ln 1 LGR Max = + + where: age Max = the maximum age of transformer after which time the load switches to

initial peak load (years), and LGR = the annual load growth rate (%). Thus, the equation for the load growth as a function of the age of the transformer is as follows: Eq. 10.7 LGrwth age LGR age ( ) ( ) ( ) = − − 1 1
for age < age Max , and Eq. 10.8 

### LGrwth age LGR age age Max 

### ( ) ( ) ( ) 

### = − − − 

### 1 1
for age >= age Max where: LGrwth(age) = the fractional load growth, and age = the age of the transformer (years). The load growth is then used to adjust the RMS loading estimate for the affected stock. The mathematical equation for this adjustment is as follows:
Eq. 10.9



# [ ] LAdjust y Stock y age LGrwth age Aff Stock y age y Std year ( ) ( , ) ( ( )) /

_ ( )

_ = × +

= − 

## ∑ 1 2 1 where LAdjust(y) is the load adjustment factor in year yand all other variables have been defined previously.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-13 The Department used a load adjustment factor to calculate an adjusted RMS loading that incorporates load growth into the unit energy consumption as described in the next section. 10.2.2.6 Affected Stock The affected stock is an output of the shipments model (Chapter 9) and a key input for the NES and NPV calculations. The affected stock consists of that portion of the transformer stock that is potentially impacted by a trial standard. It therefore consists of those transformers in the stock that are purchased in or after the year the trial standard has taken effect, as described by the following equation:
Eq. 10.10 Aff Stock y Ship y Stock age age y Std year

_ ( ) ( ) ( ) _ = +

=

− 

## ∑
1 where Aff_Stock(y) is the stock of transformers of all vintages that are operational in year y . 10.2.2.7 Unit Energy Consumption One of the final quantities that the Department calculated for the NES estimate is the unit energy consumption for affected stock. The unit energy consumption times the capacity shipped and the site-to-source conversion factor equals the annual energy consumption from which the total national energy savings is derived. Annual unit energy consumption ( UEC(y) ) for affected stock, or energy per unit capacity, is the annual energy consumption per unit capacity for transformers shipped after the effective date of a standard. This energy consumption is a function of load losses and no-load losses. The Department calculated the losses per transformer as the sum of no-load losses plus the load losses. The Department calculated the load losses as the rated load loss times the square of RMS loading adjusted for load growth. Average energy consumed per unit capacity for affected stock varies from year to year due to load growth effects. The annual unit energy consumption for distribution transformers for affected stock is given by the following equation: Eq. 10.11



### UEC y E E RMS LAdjust y

NL LL 

### ( ) [ ( )] = + × × 2
where:
E

NL = rated no-load losses per kVA capacity, E LL = rated load losses per kVA capacity,DRAFT

a For more information on NEMS, refer to the Department’s EIA documentation. A useful summary is N ational Energy Modeling System: An Overview 2003

. 5 DOE/EIA approves use of the name NEMS to describe only an official version of the model without any modification to code or data. Because the analysis entails some minor code modifications and the model is run under policy scenarios that are variations on DOE/EIA assumptions, the name NEMS-BT refers to the model as used here (BT is DOE’s Building Technologies Program, under whose aegis this work was performed). Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-14 RMS = root mean square, and Ladjust(y) = loading adjustment factor for year y . Once the unit energy consumption for affected stock is defined, only one more input is necessary to complete the NES calculation: the site-to-source conversion factor. 10.2.2.8 Electricity Site-to-Source Conversion The source conversion factor for electricity is the factor by which site energy (in kWh) is multiplied to obtain primary (source) energy (in Btu). Since the NES estimates the change in energy use of the resource (e.g., the power plant), the source conversion factor is necessary to account for losses in generation, transmission, and distribution. After calculating energy consumption at the site, the Department multiplied it by the conversion factor to obtain primary energy consumption, expressed in quads. This conversion permits comparison across (source) fuels by taking into account the heat content of different fuels and the efficiency of different energy conversion processes. The annual values are the U.S. average conversion factors for electricity generation for both peak and base load reduction. The Department used marginal heat rates corresponding to base load for no-load losses (or core losses) and marginal heat rates corresponding to peak load for load losses (or coil losses). It used these different rates because load losses are higher during transformer peak loads while no-load losses occur at all times. The Department obtained these conversion factors using a variant of the NEMS, called NEMS-BT. a Table 10.2.3 presents the average annual conversion factors used by the Department. Table 10.2.3 Average Site-to-Source Conversion Factors for No-Load Losses and Load

Losses Year For No-Load Losses For Load Losses 2010 2.699 2.931 2011 2.699 2.931 2012 2.699 2.931 2013 2.568 2.809 2014 2.390 2.578 2015 2.390 2.458DRAFT Year For No-Load Losses For Load Losses

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-15 2016 2.390 2.345 2017 2.390 2.283 2018 2.390 2.222 2019–38 2.390 2.180 The Department used a time-series projection of conversion factors, changing from year to year, which it calculated as follows:
1. Start with an integrated projection of electricity supply and demand (e.g., the Annual Energy Outlook ’s (

AEO2005) reference case) 4and extract the source energy consumption. 2. Estimate projected energy savings due to possible standards for each year (e.g., using the NES spreadsheet model). 3. Feed these energy savings back to the NEMS-BT model as a new scenario, specifically a deviation from the reference case, to obtain the corresponding source energy consumption. 4. Obtain the difference in source energy consumption between this trial standard level scenario and the reference case. 5. Divide the source energy savings, in Btu, adjusted for load-specific transmission and distribution losses, by the site energy savings, in kWh, to provide the time series of conversion factors in Btu per kWh. The conversion factors change over time and account for the displacement of generating sources. Furthermore, the NES spreadsheet model includes conversion factors for each year of the projection. The Department and stakeholders can examine the effects of alternative assumptions by revising this column of numbers. The conversion of site energy savings to source energy savings and the summation of energy savings over the forecast period complete the NES calculations. The results section (section 10.4) presents the output from the NES model. The next section describes the technical details of the NPV calculation.

10.3 NET PRESENT VALUE CALCULATION The Department estimated the national financial impact on consumers from the imposition of new energy-efficiency standards with a national NPV accounting component in the national impact spreadsheet. The Department combined output of the shipments model with energy savings and financial data from the LCC to calculate an annual stream of costs andDRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-16 benefits resulting from trial distribution transformer energy efficiency standards. The Department discounted this time series to the year 2004 and summed the result, yielding the national NPV. 10.3.1 Net Present Value Overview The NPV is the present value of the incremental economic impact of a trial standard level. Like the NES, the NPV calculation started with transformer shipments and transformer stocks, estimates of which are outputs from the shipments model. The Department then obtained estimates of transformer first costs, losses, and average marginal electricity costs from the LCC analysis. The Department proceeded to calculate the amount spent on transformer purchases and installation. It then calculated the corresponding operating costs by applying the marginal prices to the energy (both energy and electricity system capacity) used by the stock of transformers foreach year, for both a base case and standards case. Over time in the standards case, moreexpensive, but more-efficient transformers gradually replace less-efficient transformers. Thus, the operating cost per unit capacity used by the stock of transformers gradually decreases in the standards case relative to the base case while the equipment costs increase. The Department discounted purchases and expenses and operating costs for transformers using a simple national average discount factor. The discount factor converts a future expense or benefit to a present value for that expense or benefit. The difference in present value of all expenses and benefits between the base case and standards scenario is the national NPV impact. The Department calculated the NPV impact from transformers that were purchased between the effective date of standards and 2038, inclusive, to calculate the total NPV impact from purchases during the forecast period. Mathematically, NPV is the value in the present time of a time series of costs and savings, described by the equation: Eq. 10.12 

### NPV PVS PVC = − where: PVS = the present value of electricity savings, and PVC = the present value of equipment costs including installation.
PVS and PVC are determined according to the following expressions:
Eq. 10.13 PVS OC

Cap y OC

Cap y Aff Stock y Discount Factor y Base Std
y Std year = −    

  × ×

= 

## ∑ ( ) ( )

_ ( ) ( )

_ 2073

where:DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-17 OC Base /Cap(y) = operating cost per unit capacity of transformer for the base

case in year y , Aff_Stock(y) = stock of transformers of all vintages that are operational in year y , y = the year (from effective date of the trial standard to the year when units purchased in 2038 retire), and Discount Factor(y) = discount factor for the year y is defined in Eq. 10-14. Eq. 10.14 

### Discount Factor y Discount Rate y reference year



### ( ) ( ) ( ) 

### = + −



### 1 1
where: reference year = year 2004, and discount rate = the rate of discount as described in section 10.3.2.7.

Eq. 10.15 

### PVC FC

Cap y FC

Cap y Ship y Discount Factor y Std Base
y Std year 

### = −

   

  × ×

= 

# ∑ ( ) ( ) ( ) ( )

_ 2073

where: FC

Std /Cap (y) = first cost of the transformer per unit of capacity for a trial standard level S td

in year y. First cost is defined in Eq. 10.16 and described in section 10.3.2.1. Std_year = the year standards come into effect, and Ship (y) = shipments of transformers in year yfor the standards case. The Department calculated NPV from the projections of national expenditures for distribution transformers, including purchase price (equipment and installation price) and operating costs (electricity and maintenance costs). The Department calculated costs and savings as the difference between a trial standards case and a base case scenario without national standards. It discounted future costs and savings to the present. The Department calculated a discount factor from the discount rate and the number of years between the year to which the sum is being discounted (2004) and the year in which the costs and savings occur. The NPV is the sum over time (2010-2073) of the discounted net financial savings. The following sections describe the inputs specific to the NPV calculation in detail.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-18 10.3.2 Net Present Value Inputs The NPV model inputs include cost inputs, selected inputs that are important for detailing electricity capacity costs, and several of the inputs used by the NES calculation. This section details those inputs that have not yet been described as part of the NES and shipments models. The specific list of inputs for the NPV is as follows:
1. First Cost 2. Operating Cost 3. Peak Responsibility Factor 4. Initial Peak Load 5. Electricity Price Forecast Scalar 6. Marginal Electricity Costs 7. Discount Rate The first cost includes all of the initial costs that are incurred with the installation of a transformer. Generally, first cost increases with the increased efficiency that may be required by a trial standard level. Operating cost includes the annual costs of operating a transformer. In this analysis, operating cost includes both energy and capacity costs for supplying both no-load and load losses. The peak responsibility factor is a necessary input for estimating the capacity costs incurred from load losses at the initial peak load. The electricity price forecast scalar provides the forecasted increase or decrease in electricity prices over the cost accounting period that ranges from 2004 to the year 2073. Marginal electricity costs convert physical transformer loss estimates into financial economic impacts. The discount rate represents the time value of money and allows the Department to estimate the present value of a future monetary cost or benefit. The next section begins the detailed discussion of NPV inputs with a description of the transformer first cost that the Department used. 10.3.2.1 First Cost The Department expresses first cost in terms of cost per unit capacity. Specifically, the Department defines the first cost of acquiring a transformer with the following equation: FC/Cap = (P + Install)/Cap Eq. 10.16 where: FC = the first cost, Cap = the rated capacity of the transformer, P = the price of the transformer including shipping and taxes, and Install = the installation cost of the transformer.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-19 In the NPV calculation, these values are obtained from the LCC calculation as the averages for specific design lines. The Department applied an adjustment factor to convert the first cost of a representative design to an estimated average cost for a distribution of sizes withina particular product class. The adjustment incorporates the 0.75 scaling rule and the design lineto-product class mapping. This adjustment factor is explained in detail in sections 10.2.2.1 and 10.2.2.2. The costs are expressed in units of 2004 dollars per kVA of rated transformer capacity. Table 10.3.1 shows the resulting mean first costs per kVA for distribution transformers by product class and trial standard level. Table 10.3.1 First Cost of Distribution Transformers by Trial Standard Levels and

Product Class (2004$/kVA) Product Class Base TSL 1* (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 PC 1, Liquid-Immersed, MV, Single-Phase 61.85 62.46 62.67 62.85 63.79 69.43 106.66 PC 2, Liquid-Immersed, MV, Three-Phase 20.48 21.04 22.12 24.37 24.99 35.82 37.87 PC 3, Dry-Type, LV , Single-Phase 47.41 52.94 54.22 58.69 63.56 77.84 77.85 PC 4, Dry-Type, LV, Three-Phase 31.74 33.30 35.17 37.75 42.98 53.42 53.42 PC 5, Dry-Type, MV, Single-Phase 27.58 28.24 28.82 30.15 33.70 44.65 44.64 PC 6, Dry-Type, MV, Three-Phase 22.36 23.18 23.72 24.79 26.79 35.37 35.36 PC 7, Dry-Type, MV, Single-Phase 32.61 33.36 33.97 35.31 38.12 47.16 47.17 PC 8, Dry-Type, MV, Three-Phase 23.43 23.80 24.05 24.65 26.41 36.30 36.31 PC 9, Dry-Type, MV, Single-Phase 28.90 29.10 29.50 30.37 34.92 47.60 47.61 PC 10, Dry-Type, MV, Three-Phase 22.46 22.62 22.92 23.60 27.14 36.99 36.99 *TSL = Trial Standard Level The next section presents the operating costs, which are substantially more complex than the transformer first costs. 10.3.2.2 Operating Cost Operating costs are an essential, yet complex, part of calculating the national economic impact of a trial distribution transformer standard. The Department used eleven distinct inputs to calculate operating costs. This large number of inputs is necessary because transformers have both no-load and load losses, and because electricity has both energy and capacity costs. The combination of distinct losses and distinct capacity and energy costs creates the necessity for four price and two loss coefficients. Potential load growth requires a load growth adjustment factor. Peak loading, peak load coincidence, and average loading require three additional factors toDRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-20 characterize load losses. Finally, the Department used an electricity price forecast scalar to characterize future trends in electricity prices consistent with the AEO2005forecast. Transformer operating cost is the annual cost of transformer losses. The Department assumed zero maintenance cost in calculating the transformer operating cost. The Department calculated annual operating cost using the following formula to capture the diversity of potential factors that can affect transformer operating costs: OC/Cap = EPFS(y) × (E NL × (NLLMCC + 8760 × NLLMEC) + E LL × (LAdjust(y)) 2 × (PRF × PL2× LLMCC + 8760 × RMS 2× LLMEC))/Cap Eq. 10.17 where:
OC = the operating cost, Cap = the rated capacity of the transformer, EPFS(y) = the electricity price forecast scalar for year y , E NL = the no-load losses at rated load, NLLMCC = the no-load loss marginal cost of capacity, NLLMEC = the no-load loss marginal energy cost, E LL = the load losses at rated load, LAdjust(y) = the load growth adjustment factor in year y , PRF = the peak responsibility factor, PL = the initial peak load, LLMCC = the load loss marginal cost of capacity, RMS = the root mean square loading of the transformer, and LLMEC = the load loss marginal energy cost. The Department expressed the costs in units of 2004 dollars per kVA of rated capacity. One additional complexity in the operating cost equation that is shared with the NES calculation is that the Department applied an adjustment factor to incorporate the 0.75 scaling rule to E NL and E LL , as explained in sections 10.2.2.1 and 10.2.2.2, to convert from design line data to product class estimates. The following four sections explain the inputs of the operating cost equation that are not explained in the NES section.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-21 10.3.2.3 Peak Responsibility Factor The peak responsibility factor (PRF), in combination with the initial peak loading, is necessary for estimating the capacity cost impacts of transformer load losses. The transformer PRF is the square of the ratio of the transformer load at the time of the customer peak load to the transformer peak load. The Department used the average PRF from the hourly and monthly load analysis for the liquid-immersed and dry-type transformers, respectively, as reported in the LCC analysis. Table 10.3.2 presents the PRFs used in the analysis for the ten product classes. Table 10.3.2 Peak Responsibility Factors by Product Class

PC 1 PC 2 PC 3 PC 4 PC 5 PC 6 PC 7 PC 8 PC 9 PC 10 PRF 0.35 0.61 0.46 0.49 0.52 0.53 0.53 0.54 0.54 0.54
10.3.2.4 Initial Peak Load The initial peak loading, in combination with the PRF, is necessary for calculatingcapacity cost impacts from transformer load losses. The initial peak loading is the annual perunit peak load on the transformer during the first year of operation. The initial peak load is estimated as a percentage of the rated peak load of the transformer. The IEEE’s Draft Guide for Distribution Transformer Loss Evaluation 6defines a similar but different measure of peak transformer loading called an “Equivalent Annual Peak Load” that accounts for changes in peak load over the life of the transformer. Rather than use the equivalent annual peak load method, the Department characterized a range of possible initial peak loads by defining a distribution of initial peak loads. Chapter 6, section 6.3.4, provides further description. Table 10.3.3 presents the initial peak loadings used in the analysis for the ten product classes. Table 10.3.3 Initial Peak Loading by Product Class PC 1 PC 2 PC 3 PC 4 PC 5 PC 6 PC 7 PC 8 PC 9 PC 10 Initial Peak Loading 0.87 0.86 0.75 0.75 0.75 0.75 0.75 0.75 0.75 0.75
10.3.2.5 Electricity Price Forecast Scalar The electricity price forecast scalar converts current electricity costs for forecasted costs for the period 2004 to 2073. The electricity price forecast scalar is the ratio of the unit cost of electricity in real dollars in a given year to the real cost of electricity in the year 2004. The Department used AEO20054forecasts to obtain the electricity price forecast scalar. For the period beyond 2025, the Department used the real price trend from 2015 to 2025 to extrapolate the electricity price scalar.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-22 10.3.2.6 Marginal Electricity Costs The characterization of four distinct marginal electricity costs is necessary to calculate the operating costs of transformers and the financial impact of transformer efficiency standards. In an electricity system, there are both energy costs and capacity costs. Depending on the load shape of a particular load, the average value of capacity costs and energy costs are different. Since no-load losses and load losses have distinct load shapes compared to each other and since different customers have different load shapes, such costs vary by loss type and by the product class of the transformer. The Department therefore used distinct marginal energy and capacity costs for no-load losses and load losses for each transformer product class. No transformer size scaling is necessary for the marginal costs, although the design line-to-product class mapping described in section 10.2.2.2 needs to be applied to convert the design line output from the LCC to product class information for the NPV calculation. The Department calculated capacity costs in units of 2004$/kW/year, while energy costs are in units of 2004$/kWh. The names for the four types of marginal cost are: no-load loss marginal capacity cost (NLLMCC), load loss marginal capacity cost (LLMCC), no-load loss marginal energy cost (NLLMEC), and load loss marginal energy cost (LLMEC). Table 10.3.4 summarizes the four marginal costs for the ten product classes. Table 10.3.4 Marginal Energy and Demand Costs by Product Class Marginal Energy Cost by Product Class ($/kWh) PC 1 PC 2 PC 3 PC 4 PC 5 PC 6 PC 7 PC 8 PC 9 PC 10 NLL 0.027 0.026 0.057 0.054 0.051 0.051 0.051 0.051 0.050 0.050 LL 0.037 0.034 0.059 0.056 0.054 0.053 0.054 0.053 0.053 0.053 Marginal Demand Cost by Product Class ($/kW/year) PC 1 PC 2 PC 3 PC 4 PC 5 PC 6 PC 7 PC 8 PC 9 PC 10 NLL 103.05 106.42 77.45 85.45 92.19 93.50 92.06 93.32 93.99 93.99 LL 55.72 56.80 54.10 61.82 70.62 72.44 70.66 72.47 74.10 74.10
10.3.2.7 Discount Rate The discount rate expresses the time value of money and is the final input to the NPV calculation. The Department used real discount rates of 3.0 and 7.0 percent as established by the Office of Management and Budget (OMB) in Circular A-94, Regulatory Analysis. 8The discount rates that the Department used in the LCC are distinct from those it used in the NPV calculations, in that the NPV discount rate is the societal rate of return on capital whereas LCC discount rates reflect the owner cost of capital and the financial environment of electric utilities and commercial and industrial entities.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-23 10.4 RESULTS 10.4.1 National Energy Savings and Net Present Value from Trial Standard Levels The NES and NPV results from the NES spreadsheet model for TSL 1 through TSL 6 are shown in Table 10.4.1. It should be reiterated that currently the NES spreadsheet model uses discrete point-values rather than a distribution of values for all inputs. Savings for the dry-type units are significantly higher than what was estimated in the ANOPR analysis. 9The increase in savings originate predominantly from engineering design changes in DL 6, DL 7, and DL 8, which results in a significant increase in load losses in the base case.

Table 10.4.1 Summary of Cumulative National Energy Savings (2010-2038) and Net

Present Value (2010-2073) Impact
Distribution Transformers Analysis Discount Rate % Trial Standard Level

TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6

Liquid-Immersed NES

quads 1.70 2.28 2.99 3.38 6.51 9.38
NPV billion 2004$ 3 7.02 8.78 9.20 9.83 9.94 -10.31

7 2.02 2.31 2.01 1.92 -1.14 -14.10

Dry-Type NES

quads 6.83 7.82 9.02 10.28 11.17 11.17
NPV billion 2004$ 3 45.64 51.42 58.87 65.30 65.06 65.06

7 14.82 16.53 18.70 20.24 18.87 18.87

10.4.1.1 Liquid-Immersed Results Tables 10.4.2 and 10.4.3 present NES and NPV results for liquid-immersed transformers by product class. Figures 10.4.1 and 10.4.2 illustrate the typical pattern of primary energy savings and costs resulting from standards for liquid-immersed transformers over time. The figures show the nature of net savings for all six trial standard levels relative to the base case.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-24 Table 10.4.2 Cumulative Primary Energy Savings During 2010-2038: Liquid-Immersed

Transformers by Product Class

Product Class Cumulative Primary Energy Savings quads TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 1. Liquid-Immersed, MV, Single-Phase 0.81 0.86 0.90 1.06 1.77 4.49 2. Liquid-Immersed, MV, Three-Phase 0.90 1.42 2.10 2.32 4.74 4.88 Total 1.70 2.28 2.99 3.38 6.51 9.38

Table 10.4.3 Net Present Value During 2010-2073: Liquid-Immersed Transformers by

Product Class

Product Class Net Present Value $billion Discount Rate: 3% Discount Rate: 7% TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 1. LiquidImmersed, MV, Single-Phase 2.95 3.03 3.13 3.31 2.14 -16.91 0.87 0.86 0.85 0.75 -0.59 -12.76

2. LiquidImmersed, MV, Three-Phase 4.07 5.76 6.08 6.52 7.80 6.60 1.16 1.46 1.16 1.18 -0.55 -1.34

Total 7.02 8.78 9.20 9.83 9.94 -10.31 2.02 2.31 2.01 1.92 -1.14 -14.10DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-25 0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00

One Two Three Four Fi ve Six Trial Standard LevelsCumulative Source Savings(quads)

-20.00 -15.00 -10.00 -5 .00 0.00 5.00 10.00 15.00NPV (billion US$)

National Energy Sa v

ings NPV at 7% discount rate NPV at 3% discount rate Figure 10.4.1 Liquid-Immersed Distribution Transformers: National

Energy Savings and Net Present Values Impacts

10.4.1.2 Dry-Type Results Tables 10.4.4 and 10.4.5 present NES and NPV results for dry-type transformers by product class. Figures 10.4.3 and 10.4.4 show the typical pattern of national savings and costs resulting from standards for dry-type transformers over time. Again, the figures show the nature of net savings for all six trial standard levels relative to the base case. Table 10.4.4 Cumulative Primary Energy Savings During 2010-2038: Dry-Type

Transformers by Product Class

Product Class Cumulative Primary Energy Savings quads TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6
3. Dry-Type, LV, Single-Phase 0.411 0.458 0.498 0.529 0.565 0.565 4. Dry-Type, LV, Three-Phase 6.352 7.252 8.364 9.506 10.214 10.214DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-26 5. Dry-Type, MV, Single-Phase, 20-45 kV BIL 0.000 0.000 0.001 0.001 0.001 0.001 6. Dry-Type, MV, Three-Phase, 20-45 kV BIL 0.016 0.024 0.035 0.047 0.065 0.065 7. Dry-Type, MV, Single-Phase, 46-95 kV BIL 0.000 0.001 0.001 0.001 0.002 0.002 8. Dry-Type, MV, Three-Phase, 46-95 kV BIL 0.053 0.082 0.117 0.179 0.298 0.298 9. Dry-Type, MV, Single-Phase, > 96 kV BIL 0.000 0.000 0.000 0.000 0.000 0.000 10. Dry-Type, MV, Three-Phase, > 96 kV BIL 0.001 0.005 0.009 0.018 0.026 0.026

Total 6.83 7.82 9.02 10.28 11.17 11.17DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-27 Table 10.4.5 Net Present Value During 2010-2073: Dry-Type Transformers by Product

Class

Product Class Net Present Value $billion Discount Rate: 3% Discount Rate: 7% TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 1 (TP 1) TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 3. Dry-Type, LV, Single-Phase 2.82 3.18 3.40 3.53 3.45 3.44 0.90 1.01 1.07 1.09 0.99 0.99

4. Dry-Type, LV, Three-Phase 42.39 47.56 54.51 60.47 60.56 60.56 13.79 15.31 17.35 18.81 17.84 17.84

5. Dry-Type, MV, Single-Phase, 20-45 kV BIL 0.00 0.00 0.00 0.01 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

6. Dry-Type, MV, Three-Phase, 20-45 kV BIL 0.10 0.14 0.19 0.24 0.20 0.20 0.03 0.04 0.06 0.06 0.02 0.02

7. Dry-Type, MV, Single-Phase, 46-95 kV BIL 0.00 0.00 0.01 0.01 0.01 0.01 0.00 0.00 0.00 0.00 0.00 0.00

8. Dry-Type, MV, Three-Phase, 46-95 kV BIL 0.33 0.51 0.69 0.96 0.80 0.80 0.10 0.16 0.20 0.26 0.03 0.03

9. Dry-Type, MV, Single-Phase, > 96 kV BIL 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

10. Dry-Type, MV, Three-Phase, > 96 kV BIL 0.01 0.03 0.05 0.08 0.04 0.04 0.00 0.01 0.02 0.02 -0.01 -0.01

Total 45.64 51.42 58.87 65.30 65.06 65.06 14.82 16.53 18.70 20.24 18.87 18.87DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-28 0.00 2.00 4.00 6.00 8.00 10.00 12.00 14.00

One Two Three Four Fi ve Six Trial Standard LevelsCumulative Source Savings(quads)

0.00 10.00 20.00 30.00 40.00 50.00 60.00 70.00NPV (billion US$)

National Energy Sa v

ings NPV at 7% discount rate NPV at 3% discount rate Figure 10.4.2 Dry-Type Distribution Transformers: Net Energy Savings and

Net Present Value Impacts

The national impact spreadsheet is available as a Excel file on the DOE website: http://www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers. html. Instructions for using the spreadsheet are in Appendix 10A of this TSD.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-29 REFERENCES

1. HVOLT Consultants Inc., P. Hopkinson, and J. Puri. Distribution Transformer Market Shipment Estimates for 2001. February 17, 2003. 3704 High Ridge Road, Charlotte, NC, 28270, tel: (704) 846-3290, e-mail: P.Hopkinson@hotmail.com. Prepared for Navigant Consulting, Inc., Washington DC.
2. U.S. Department of Commerce - Bureau of Economic Analysis. Industry Economic Accounts Information Guide. Annual Industry Accounts. Gross Domestic Product (GDP) by Industry. 2005. (Last accessed May 11, 2005.) This material is available in Docket #83. Contact Ms. Brenda Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue, SW, Washington, DC, 20585-0121, telephone (202) 586-2945 for more information. <For download page, see http://www.bea.gov/bea/dn2/iedguide.htm#gpo . For 1977-1997 data, go to http://bea.gov/bea/pn/GDPbyInd_SHIP_SIC.xls . For 1998-2003 data, go to http://bea.gov/bea/pn/GDPbyInd_SHIP_NAICS.xls .>>
3. U.S. Department of Energy-Energy Information Administration. Annual Energy Review 2003, Chapter 8: Electricity, Table 8.9 Electricity End Use, 1949-2003. 2004. (Last accessed May 9, 2005.) This material is available in Docket #83. Contact Ms. Brenda Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue, SW, Washington, DC, 20585-0121, telephone (202) 586-2945 for more information. <http://www.eia.doe.gov/emeu/aer/txt/stb0809.xls>
4. U.S. Department of Energy - Energy Information Administration. Annual Energy Outlook 2005: With Projections Through 2025. January, 2005. Washington, DC. Report No. DOE/EIA-0383(2005). <http://www.eia.doe.gov/oiaf/aeo/index.html> 5. U.S. Department of Energy-Energy Information Administration. National Energy Modeling System: An Overview 2003. 2003. Report No. DOE/EIA-0581(2003). <http://www.eia.doe.gov/oiaf/aeo/overview/index.html>
6. Institute of Electrical and Electronics Engineers Inc. Draft Guide for Distribution Transformer Loss Evaluation. October, 2001. 345 East 47th Street, New York, NY. Report No. IEEE PC57.12.33/D8.
7. Institute of Electrical and Electronics Engineers Inc. Guide For Loading Mineral OilImmersed Transformers. 1995. 345 East 47th Street, New York, NY. Report No. IEEE Std C57.91-1995. Transformer Committee of the IEEE Power Engineering Society.DRAFT

Transformer_DRAFT_TSD_Chapter10_version8-3-05_DOE_8/3/05 10-30 8. U.S. Office of Management and Budget. Circular No. A-94. Appendix C. 2002. (Last accessed November, 2002.) This material is available in Docket #83. Contact Ms. Brenda Edwards-Jones, U.S. Department of Energy, Building Technologies Program, Mailstop EE-2J, 1000 Independence Avenue, SW, Washington, DC, 20585-0121, telephone (202) 586-2945 for more information. <http://www.whitehouse.gov/omb/circulars/a094/a94_appx-c.html>
9. U.S. Department of Energy-Office of Building Technologies. Technical Support Document: Energy Conservation Program for Commercial and Industrial Equipment: Electrical Distribution Transformers - ANOPR Version. 2004. U.S. Department of Energy. Washington, DC. Report No. LBNL-53985. <http://www.eere.energy.gov/buildings/appliance_standards/commercial/dist_trans_tsd_0 61404.html>