10

- i CHAPTER 10. NATIONAL IMPACT ANALYSIS

TABLE OF CO NTENTS

10.1 INTRODUCTION ......................................................................................................... 10-1

10.2 NATIONAL ENERGY SAVINGS ............................................................................... 10-4

10.2.1 Overview ........................................................................................................................ 10-5

10.2.2 Inputs.............................................................................................................................. 10-6

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

10.2.2.2 Mapping Design Line Data to Equipment Classes ...................................... 10-8

10.2.2.3 Mapping Efficiency Level to Trial Standard Level ................................... 10-10

10.2.2.4 Root Mean Square Load ............................................................................ 10-11

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

10.2.2.6 Affected Stock ........................................................................................... 10-13

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

10.2.2.8 Site

- to

- Source Electricity Conversion ....................................................... 10-14

10.3 NET PRESENT VALUE ............................................................................................. 10-15

10.3.1 Overview ...................................................................................................................... 10-16

10.3.2 Inputs............................................................................................................................ 10-17

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

10.3.2.2 O perating Costs .......................................................................................... 10-19

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

10.3.2.4 Initial Peak Load ........................................................................................ 10-20

10.3.2.5 Scalar for Electricity Price Projections ...................................................... 10-21

10.3.2.6 Marginal Electricity Costs ......................................................................... 10-21

10.3.2.7 Discount Rate ............................................................................................. 10-21

10.3.2.8 Projection of Future Product Prices ........................................................... 10-22

10.4 RESULTS .................................................................................................................... 10-22

10.4.1 National Energy Savings and Net Present Value for Trial Standard Levels ............... 10-22

10.4.1.2 Results for Liquid- Immersed Distribution Transformers .......................... 10-23

10.4.1.3 Results for Low- Voltage Dry -Type Distribution Transformers ................ 10-24

10.4.1.4 Results for Medium- Voltage Dry -Type Distribution Transformers .......... 10-24

10.5 ANNUALIZED NATIONAL COSTS AND B ENEFITS ........................................... 10-25

10.5.1 Calculation Method ...................................................................................................... 10-26

10.5.2 Results for the Considered Standards .......................................................................... 10-27

LIST OF TABLES

Table 10.2.1 Mapping of Design Line to Equipment Class .................................................... 10-9

Table 10.2.2 Mapping of Efficiency Levels to Trial Standard Levels for LiquidImmersed Transformers ................................................................................... 10-11

Table 10.2.3 Mapping of Efficiency Levels to Trial Standard Levels for Low- Voltage Dry

- Type Transformers ................................................................................... 10-1110

- ii Table 10.2.4 Mapping of Efficiency Levels to Trial Standard Levels for MediumVoltage Dry

- Type Transformers ...................................................................... 10-11

Table 10.2.5 Average Site

- to -Source Conversion Factors for No-Load Losses and Load

Losses ............................................................................................................... 10-15

Table 10.3.1 First Cost of Distribution Transformers by Trial Standard Level and Equipment Class (2011$/kVA) ........................................................................ 10-19

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

Table 10.3.3 Initial Peak Loading by Equipment Class ........................................................ 10-20

Table 10.3.4 Marginal Energy and Capacity Costs by Equipment Class ............................. 10-21

Table 10.4.1 Results for Cumulative National Energy Savings (2016–2045) and Net Present Value (2016–2104) .............................................................................. 10-23

LIST OF FIGURE S

Figure 10.1.1 Flowchart of National Impact Analysis ............................................................. 10-3 Figure 10.4.1 Liquid-Immersed Distribution Transformers: Impacts of Standards on National Energy Savings and Net Present Value ............................................. 10-23 Figure 10.4.2 Low

- Voltage Dry -Type Distribution Transformers: Impacts of Standards on National Energy Savings and Net Present Value ........................................ 10-24 Figure 10.4.3 Medium- Voltage Dry

- Type Distribution Transformers: Impacts of Standards on National Energy Savings and Net Present Value ....................... 10-2510

- 1 CHAPTER 10. NATIONAL IMPACT ANALYSIS

10.1 INTRODUCTION

The Energy Policy and Conservation Act of 1975, as amended, (EPCA) requires that any

new or amended energy efficiency standard for distribution transformers shall be designed to achieve the maximum improvement in energy efficiency that is both technologically feasible

, economically justified , and would save a significant amount of energy. (42 U.S.C. 6295(o)(2)(A) and (B), and 6317(a)(1). In determining whether a standard is economic ally justifi ed

. the U.S. Department of Energy (DOE) is required to determine whether the benefits of the potential standard outweigh its burdens. Key factors in the de termination are (1) the total projected amount of energy savings likely to result directly from the imposition of the standard, and (2) the savings in operating costs throughout the life of the covered equipment when compared to any

increase in its price, initial charges , such as installation costs, or maintenance −any of which are likely to result from promulgation of the standard.

To satisfy th e above EPCA requirement s and more fully understand the overall impact of potential energy efficiency standards for distribution transformers, DOE conducted a national impact analysis (NIA) . Th e NIA assessed future national energy savings (NES) from energy

conservation standards for distribution transform ers and the national economic impact using the net present value (NPV). This chapter describes the method ology DOE used to estimate the national impacts of trial standard levels (TSLs) for medium- voltage liquid

- immersed distribution transformers, and low- and medium- voltage dry

- type distribution transformers

. The analyses that preceded the shipments analysis in chapter 9 of the Technical Support Document (TSD) (e.g., the engineering analysis ( chapter 5 ) and the life- cycle cost analysis ( chapter 8 ) e xamined transformers by design

- line , which accounts for the 1 4 distinct design options found in

transformers. Additionally f or the NIA, DOE is required to examine impacts as they relate to equipment classes, because the final standards will apply to equipment classes, not design-lines. DOE evaluated the following impacts: (1) NES attributable to each potential standard, (2) monetary value of the NES to purchas ers of the considered equipment , (3) increased total

installed cost of the equipment because of standards, and (4) NPV of energy savings (the difference between the operating cost savings and increased total installed cost).

To conduct its NIA, DOE determined both the NES and NPV for each trial standard level being considered for distribution transformers . DOE performed all calculations for each considered equipment class using a Microsoft Excel spreadsheet model. The national impact spreadsheet is available as an Excel file on the DOE website: http://www1.eere.energy.gov/buildings/appliance_standards/product.aspx/productid/66

.

The spreadsheets combine the calculations for determining the NES and NPV for each considered equipment class with input from the appropriate shipments model that DOE used to forecast future purchases of transformers . Chapter 9 provides a detailed description of the shipments model, includ ing custome rs’ sensitivities to total installed cost, operating cost, and income, and how DOE capt ured those sensitivities within the model. The NES and NPV together10

- 2 constitute the NIA model. Additional d etails , along with instructions for using the NIA spreadsheet , are provided in appendix 10A of this TSD

.

Figure 10.1.1 presents a flow diagram of th e model and spreadsheet s used to perform the NIA (NES and NPV) for distribution transformers. In the diagram, arrows show the direction

that information flows when the calculation is performed . The process begins with inputs (shown as parallelograms). As information flows from the inputs, it may be integrated into intermediate results (shown as rectangles) or , via integrating sums or differences (shown as circles) , into major outputs (shown as boxes having wavy bottom edges).

The NIA calculation starts with the shipments model (chapter 9), which is shaded in the flow diagram. For transformers, the model integrated the inputs of estimates of 2001 and 2009 shipments from DOE’s contractor, 1,2 the U.S. Bureau of Ec onomic Analysis (BEA) transformer quantity index, 3 electricity market shares from DOE’s Energy Information Administration (EIA), 4,5 an d equipment price estimates from DOE’s life

- cycle cost (LCC) analysis. The model produced both a backcast and a forecast of total shipments. DOE used the total shipments and a retirement function to produce an accounting of in- service transformers (stocks)

, thereby enabling DOE to estimate the stock that would be affected by trial standard levels and

transformer retirements.

DOE used a scaling factor (described in section 10.2.2.1) t o estimate the national impacts of new standards for all the equipment classes considered in this rulemaking. The scaling factor is applied to the equipment cost and annual energy consumption of each representative transformer size so they can describe all sizes within that equipment class.10

- 3 Figure 10.1.1 Flowchart of National Impact Analysis

Following the calculation of shipments, the calculations of NES and NPV begin. For both

calculations , k ey inputs from the LCC analysis are the average rated no-load and load losses and the cost of transformers, including installation. DOE adjusted the losses and equipment costs for

transformer size an d type to convert the applicability of the data from representative design

- lines

in to average equipment classes . Additional inputs on average and peak losses—including root mean square (RMS) loadi ng, peak loading, and peak responsibility factor— enabled DOE to10

- 4 convert rated losses into actual losses. At this point, the information flow for the NES and NPV calculation split s into two paths.

On one path, the NES calculation sums the kilo watt -hours of energy consumed by the

affected stock

, tak ing the difference between the base

- case and standards scenario to calculate

site -energy savings. DOE converted site- energy savings to energy savings at the source (i.e., at the power plant), using a verage heat rates for base load and peak load generation from DOE’s National Energy M odel ing System (NEMS)

. 6 The average heat rates from NEMS include

transmission and distribution losses. Summing the annual energy savings for the forecast period, which extends from 2016 through 2045, provides the final NES result.

On the other path, the NPV calculation starts with marginal price inputs from the LCC analysis for both energy and capacity costs and for both load and no-load losses. The marginal prices, combined with the actual peak and average losses, provide estimates of operating costs. Meanwhile, the adjusted cost of installed equipment times the annual shipments provides the estimate of the total annual equipment costs. DOE calculated three differences to assess the net impact of each TSL . The first difference was between equipment costs in each TSL scenario and

the base case to obtain the net increase in equipment cost attributable to the TSL . The second difference was between operating costs under the base

- case scenario and each TSL to obtain the net operating cost savings from the TSL . The third difference was between the net operating cost savings and the net increase in equipment cost, which provides the net expense or savings for each year. To obtain the NPV impact of a TSL , DOE discounted the net expenses or savings to 2011$ and summed them for 2016–2105 a (t he year the last unit shipped in 2045 retires from service) for transformers purchased during 2016–2045.

T he t wo model s that comprise the NIA are described below— the NES model in section 10.2, and the NPV model in section 10.3. Each description begins with a summary of the model, followed by an overview of how DOE performed that model ’s calculations . Then model inputs

are summarized . The final subsections of the two sections describe each of the major inputs and computation al steps in detail and with equations when appropriate. After the technical descriptions of the models, this chapter presents the results of the NIA calculations.

10.2 NATIONAL ENERGY SAVI NGS

DOE developed the NES model to estimate the total NES us ing results from the shipments model combined with information from the LCC on energy savings. The savings shown in the NES reflect decreased energy losses resulting from the installation of new, more efficient transformer units nationwide, in comparison t o a base case in which there are no national standards. Positive values of NES correspond to net energy savings, specifically a decrease in energy consumption after implementation of a standard , in comparison to the energy consumption in the base

- case scenario.

a The analysis period for NPV is based on the cumulative operating cost savings of the last unit shipped ( 2045 +
maximum transformer life

- 1).10

- 5 10.2.1 Overview

DOE calculated the cumulative incremental energy savings from each potential transformer efficiency standard relative to a base

- case scenario of the current efficiency standard

. It calculated NES , in units of quads, throughout the forecast period for standards that it assumed

will be effective in 2016 . The NES calculation started with estimates of transformer shipments and stocks (in-service transformers), which are outputs of the shipments model ( chapter 9). DOE

then obtained estimates of transformer energy losses from the LCC analysis (chapter 8), and calculated the total energy use by the stock of transformers for each year for both a base case and

a standards case. I n each standards case, as more efficient transfor mers replace less efficient ones

that retire from service , the energy per unit capacity used by the stock of transformers gradually

decreases relative to the base case. DOE used a site

- to -source conversion factor to convert the amount of energy used by the transformers into the amount of energy consumed at the source of electricity generation (the source energy). The site

- to -source conversion factor accounts for transmission, distribution, and generation losses. For each year analyzed, the difference in sou rce energy use between the base case and the standards scenario is the annual energy savings. DOE summed the annual energy savings from 2016 through 2045 to calculate the total NES for the forecast period.

In calculating the NES, DOE did not assume any trends in transformer nameplate efficiency besides the incremental improvement indicated by the LCC calculation. In examining proprietary shipments data provided by the transformer industry , DOE found that the data

revealed no conclusive trends in improv ed efficiency. Deciding that future efficiency trends generally are indeterminate , DOE chose to use fixed baseline efficiency. DOE also assumed that the efficiency of transformers does not degrade over time. Th erefore the annual energy savings

can be describ ed in terms of an affected stock, as described in section 9.3.11 of the shipments chapter . Annual energy savings therefore are described by the following equation.

AES(y) = (UECBase − UECStd) × Aff_ Stock(y)

Where :

AES(y) = the annual energy savings in year y , UECBase = the site unit energy consumption for the base case,

UECStd = the site unit energy consumption for the standards case, and Aff_Stock(y) = the stock of transformers of all vintages that are operational in year y

.

Given the annual energy savings, the cumulative NES can then be calculated as a simple

sum.

NES = � SiteToSource (

y

) × AEC (

y

) 2045

y= St

d year10

- 6 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.

After the shipments model provides the estimate of affected stock, the NES calculates

UECBase and UECStd using the output from the LCC analysis and including the site- to

- source conversion factor. The following section summarizes the inputs necessary for the NES

calculation and then describes each input individually.

10.2.2 Inputs

Inputs to t he NES model fall into three broad catego ries: (1) those that help convert the

data from the LCC into data relevant to the equipment classes and transformer size distributions used in the NES; (2) those that help calculate the unit energy consumption; and (3) the site- to

source conversion factor, which enables the calculation of source energy consumption from site energy use. The specific NES model inputs are :

1. s ize scaling of losses and costs

, 2. mapping of LCC design line data to equipment classes

, 3. root mean square loading,

4. load growth,

5. a ffected stock

, 6. e ffective date of standard

, 7. unit energy consumption, and

8. e lectricity site

- to

- source conversion

.

Each input is described further below.

10.2.2.1 Size Scaling of Losses and Costs

Transformers are produced over a broad range of capacities, only a few of which are

modeled explicitly in this analysis. The modeled designs are referred to as representative units. Any given equipment type includes 2-4 representative units at different ca pacity, or kVA values. DOE used a scaling relationship, or equation, to project the economic results from a given transformer design line to similar transformers of different sizes. This relationship is a key element in adjusting losses and costs from a representative transformer in the LCC to the distribution of transformer sizes incorporated in the calculation of NES and subject to potential

standards. The Department uses the 0.75 scaling rule to scale the cost and efficiency results for

the modeled kVA values to the full capacity range for each type , the 0.75 scaling rule is discussed in greater detail in chapter 5 . This rule assumes that both the physical and cost characteristics are determined by the quantity of material required to build the transform er, and is approximately true. In practice, if the kVA

- range over which cost and efficiency data are to be scaled is large, the 0.75 rule is less accurate. This manifests as kinks or angles in the curve of efficiency as a function of capacity for a given e quipment type.10

- 7 The Department has implemented a correction to the 0.75 scaling rule to produce smoother curves of efficiency versu s capacity. This correction adjusts the value of the exponent (the 0.75 of the scaling rule) so that the curve extrapolates correctly between any two representative units. Mathematically, the efficiency of a transformer is equal to the ratio :

Eff = Load
( Load + Losses )

Where:

Eff = transformer efficiency

Load = the load on the transformer

Losses = the transforme r’s combined no-load and load losses.

Load is proportional to capacity kVA , and if the 0.75 scaling rule is valid, losses are proportional to ( kVA ) 0.75 . This expression can thus be written as,

Eff = 1
( 1 + Constant × ( kVA ) −0

. 25 )

Defining the loss function as

Losses = 1
Eff

− 1 ,

Losses = Constant × ( kVA ) −0

. 25

For two representative units labeled 1 and 2,

Log � Losses 1
Losses 2 �

= − 0. 25 Log � kVA 1 kVA 2 �

The validity of the 0.75 scaling rule can thus be tested by evaluating the ratio,

x = − Log � Losses 1 Losses 2 � �

Log � kVA 1 kVA 2 � �

The Department uses the exponent x calculated through the above equation, instead of the

value -0.25 implied by the scaling rule, to interpolate the efficiency between any two representative units. The D OE uses the unmodified scaling rule to extrapolate efficiency values to capacities below the minimum representative unit, or above the maximum representative unit.10

- 8 The D OE calculated an adjustment factor using the exponent x to account for the fact that the representative design

- line unit used in the engineering analysis is not the “average” size for the set of transformers that the design line represent s. This adjustment factor is given by the following equation.

AdjFactor = ∑ [ Sh ip i × Cap i 1+X i ]
( Cap DL 1+X × ∑ Sh ip ii )

Where :

AdjFactor = the adjustment factor that , when multiplied by the design line losses or

costs, gives the shipment- weighted losses or costs per transformer ; Ship i = the shipments in the i- th size category ; Cap i = the rated capacity of the transformers in the i- th size category ; and Cap DL = the rated capacity of the representative unit of the design line.

DOE 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 by :

AvgLossPerCap DL = LossPerCap DL × AdjFactor × Cap DL Cap avg

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.

After the losses and costs from the LCC were adjusted to represent the correct size distribution, they needed a further adjustment to represent the appropriate equipment classes, as

described in the following section.

10.2.2.2 Mapping Design Line Data to Equipment Classes

The calculations of NES and NPV use the LCC calculations (chapter 8) as the source of most input data. DOE performed the LCC calculations by design line, whereas any standard will be promulgated by equipment class. As a first step, therefore, the NES calculation aggregates the LCC design line data into equipment classes. DOE used th is aggregation method to prepare for estimating economic impact s by equipment class.10

- 9 To represent the range of designs in some distribution transformer equip ment classes,

DOE often analyzed several design lines per equipment class. For example , equipment class 1B (single -phase, medium- voltage, pole-mounted, liquid

- immersed trans formers) is represented by two design lines, as is equipment class 2 A (three -phase, medium-voltage, liquid- immersed transformers) whi ch is also represented by two design lines. DOE did not specifically examine some equipment classes. For three-phase, liquid -immersed, equipment class 2B, DOE used factors for the appropriate single

- phase design lines multiplied by three. For single -phase, medium-voltage, d ry

- type design lines, equipment classes 5 , 7, and 9, DOE used factors for the appropriate three-phase design lines divided by three. Table 10.2.1 presents the mapping of

desi gn line (DL) to equipment class ( E C).

Table 10.2.1 Mapping of Design Line to Equipment Class

Equipment Class BIL* kV Capacity kVA Mapping

1 Liquid

- immersed, medium

- voltage, single

- phase < 200 10

– 833 DL 1 + DL2 + DL 3

2 Liquid

- immersed, medium

- voltage, three

- phase < 200 15

– 2,500 DL4 + DL5

3 Dry

- type, low

- voltage, single

- phase ≤ 10 15

– 333 DL6

4 Dry

- type, low

- voltage, three

- phase ≤ 10 15

– 1,000 DL7+DL8

5 Dry

- type, medium

- voltage, single

- phase 20

– 45 15

– 833 (DL9 + DL10)/3

6 Dry

- type, medium

- voltage, three

- phase 20

– 45 15

- 2,500 DL9 + DL10

7 Dry

- type, medium

- voltage, single

- phase 46

– 95 15

– 833 (DL11 + DL12)/3

8 Dry

- type, medium

- voltage, three

- phase 46

– 95 15

– 2,500 DL11 + DL12

9 Dry

- type, medium

- voltage, single

- phase > 95 75

– 833 (DL13A + DL13B)/3

10 Dry

- type, medium

- voltage, three

- phase > 95 225

– 2,500 DL13A + DL13B

* BIL = basic impulse insulation level in kilovolts (kV).

To aggregate losses from more than one design line, DOE applied the average of shipments weighted by capacity of the per -kilovolt- ampere (kVA) transformer characteristics from the economic analysis of the design lines to the estimated capacity shipped for each equipment class. DOE’s contractor 1,2 provided the capacity shipped for each design line (and

each equipment class) . The LCC analysis provided the economic results for each design line, and DOE used the scaling method described in section 10.2.2.1 to estimate the scaled cost and loss estimates for each size category represented by each design line. The following equation provides the average loss per unit capacity for an equipment class ( AvgLossPerCap EC ) as derived from the average loss per unit capacity for a design line. The equation sums those design lines that constitute an equipment class.

AvgLossPerCap EC = ∑ [ AvgLossPerCap DL × MS DL ] DL ∑ MS DLDL .10

- 10 Where :

AvgLossPerCap DL = the average loss per unit capacity for t he design line, and

MS DL = the design line’s market share by capacity

.

The AvgLossPerCap EC represents the average loss per unit capacity of the transformer load. No further adjustment is needed for no- load losses . For load losses, however, the losses at

rated load must be converted to losses at actual loading. R oot mean square ( RMS ) loading is a key factor used in estimating load losses at actual loading. The following section describes the RMS loading input to the N ES

.

10.2.2.3 Mapping Efficiency Level to Trial Standard Level

DOE co nducted the LCC analysis for up to seven energy efficiency levels (EL) for each representative unit in the 14 design lines. DOE selected the ELs for each design line by applying a set of economic and design criteria to intermediate LCC analyses as discussed in c hapter 5, resulting in unique sets of EL efficiencies for each design line. It mapped these LCC analysis

results to trial standard levels ( TSL s) for the 10 equipment classes.

For liquid- immersed distribution transformers the efficiency levels in each TSL can be characterized as follows: TSL 1 represents an increase in efficiency where a diversity of

electrical steels are cost

- competitiv e and economically feasible for all design lines; TSL 2 represents EL1 for all design lines; TSL 3 represents the maximum efficiency level achievable with M3 core steel; TSL 4 represents the maximum NPV with 7 percent discounting; TSL 5 represents EL 3 fo r all design lines; TSL 6 represents the maximum source energy savings with positive NPV with 7 percent discounting; and TSL 7 represents the maximum technologically feasible level (max tech).

For low-voltage, dry-type distribution transformers, the ef ficiency levels in each TSL can be characterized as follows: TSL 1 represents the maximum efficiency level achievable with M6 core steel; TSL 2 represents base efficiency for DL 6, EL 3 for DL 7, and EL2 for DL 8 ; TSL 3 represents the maximum EL achievable using butt-lap miter core manufacturing for single- phase distribution transformers, and full miter core manufacturing for three

- phase distribution transformers; TSL 4 represents the maximum NPV with 7 percent discounting; TSL 5 represents

the maximum sour ce energy savings with positive NPV with 7 percent discounting; and TSL 6 represents the max tech.

For medium-voltage, dry- type distribution transformers, the efficiency levels in each TSL can be characterized as follows: TSL 1 represents EL1 for all de sign lines; TSL 2 represents an increase in efficiency where a diversity of electrical steels are cost -competitive and economically feasible for all design lines; TSL 3 represents the maximum NPV with 7 percent discounting; TSL 4 represents the maximum so urce energy savings with positive NPV with 7 percent discounting; and TSL 5 represents the max tech.10

- 11 Table 10.2.2 Mapping of Efficiency Levels to Trial Standard Levels for Liquid

Immersed Transformers

Design Line TSL1 TSL2 TSL3 TSL4 TSL5 TSL6 TSL7

1 Liquid

- Immersed, 50kVA, single

- phase EL 1 (EL 0.4 actual) EL 1 EL 1 EL 2 EL 3 EL 4 EL 7

2 Liquid

- Immersed, 25kVA, single

- phase Base (EL 0.5 actual) EL 1 EL 1 EL 2 EL 3 EL 4 EL 7

3 Liquid

- Immersed, 500kVA, single

- phase EL 1 (EL 1.1 actual) EL 1 EL 2 EL 4 EL 3 EL 5 EL 7

4 Liquid

- Immersed, 150kVA, three

- phase EL 1 EL 1 EL 1 EL 2 EL 3 EL 4 EL 7

5 Liquid

- Immersed, 1500kVA, three

- phase EL 1 EL 1 EL 2 EL 4 EL 3 EL 5 EL 7

Table 10.2.3 Mapping of Efficiency Levels to Trial Standard Levels for Low -Voltage Dry

- Type Transformers
Design Line TSL1 TSL2 TSL3 TSL4 TSL5 TSL6

6 LVDT, 25kVA, single-phase Base Base EL 4 EL 6 EL 6 EL 7

7 LVDT, 75kVA, three -phase EL 2 EL 3 EL 4 EL 6 EL 6 EL 7

8 LVDT, 300kVA, three -phase EL 2 EL 2 EL 4 EL 6 EL 7 EL 7

Table 10.2.4 Mapping of Efficiency Levels to Trial Standard Levels for Medium

Voltage Dry- Type Transformers
Design Line TSL 1 TSL 2 TSL 3 TSL 4 TSL 5

9 MVDT, 300kVA, three-phase, 45kV BIL EL 1 EL 1 EL 2 EL 2 EL 7

10 MVDT, 1500kVA, three-phase, 45kV BIL EL 1 EL 2 EL 2 EL 2 EL 7

11 MVDT, 300kVA, three-phase, 95kV BIL EL 1 EL 1 EL 4 EL 4 EL 7

12 MVDT, 1500kVA, three

- phase, 95kV BIL EL 1 EL 2 EL 4 EL 4 EL 7

13A MVDT, 300kVA, three-phase, 125kV BIL EL 1 EL 1 EL 2 EL 4 EL 6

13B MVDT, 2000kVA, three-phase, 125kV BIL EL 1 EL 2 EL 2 EL 2 EL 5

10.2.2.4 Root Mean Square Load

Energy losses in transformers follow the RMS load, not the arithmetic average load. DOE

calculated the RMS load as the RMS of the transformer load divided by the transformer rated capacity, then multiplied by the power factor. (As explained in chapter 6 of the TSD, although DOE’s analy tical method can derive results for varying power factors, for the analysis presented here DOE set the power factor to a value of one.) DOE used the average national RMS load for each design line as calculated for the LCC analysis. Those values range from 22.1 percent to
41.2 percent for the various design lines.

10.2.2.5 Load Growth

The load growth is the fraction by which the load increases after a transformer is installed. DOE investigated load growth as a sensitivity analysis (described in appendix 10B). Load growth occurs when new equipment, new appliances, or additional activities increase the10

- 12 energy loads on the circuits serve d by distribution transformers. Load growth increas es the load

losses relative to th os e estimated to have occurred during the first year of i nstallation

.

DOE calculated the fractional load growth from an estimated rate that it used as an input to the LCC analysis. There is a maximum load growth, LGRMax , which DOE set at 50 percent for liquid- immersed transformers. The 50- percent value represents the approximate amount of growth in load that can occur without overloading the transformer beyond a reasonable point. When overloading occurs, DOE assumed that the transformer would be installed in a new

location where the initial peak loading would be the same as when originally installed. 7 See Institute of Electrical and Electronics Engineers, Inc. (IEEE) St andar d C57.91-1995, Guide for Loading Mineral- Oil

- Immersed Transformers and Step -Voltage Regulators, 8 for details on permissible electrical overloading of mineral-oil- immersed transformers. Because IEEE does not report data on permissible overloading of dry-type units, DOE used the same values for both liquid -immersed and dry-type transformers. The age at which a transformer load switches back to initial peak load is given by the following equation.

age Max = ln (1 + LGRM ax )

ln ( 1 + LGR )

.

Where :

age Max = the maximum age of the transformer after which time the load switches back 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:

LGrwth(age) = (1 − LGR) (age) − 1

for age < age Max , and

LGr wth(age) = (1 − LGR) (age −ageMax) − 1

for age >= age Max

.

Where :

LGrwth (age) = the fractional load growth, and

age = the age of the transformer (years).

DOE then used the load growth to adjust the estimate of RMS load for the affected stock. The mathematical equation for this adjustment is:10

- 13 LAdjust ( y ) = � � [ Stock ( y
, age ) × (1 + LGrwt h ( age ) ) 2 ]

Aff

_ Stock ( y ) y− Std

_ year

age =1 ,

where LAdjust(y) is the load adjustment factor in year y . All other variables were defined for previous equations. DOE applied a load adjustment factor to RMS loading to incorporate load growth into the unit energy consumption, as described in section 10.2.2.7

.

10.2.2.6 Affected Stock

The affected stock , an output of the shipments model ( chapter 9), is a key input for the

NES and NPV calculations. The affected stoc k represents that part of the transformer stock that would be impacted by a standard. It consists of those transformers purchased in or after the year

the standard takes effect, as described by the following equation

.

Aff Stock ( y ) = Sh ip ( y ) + � Stock ( age ) y− St d year

age =1 .

Where :

Aff_Stock(y) = stock of affected transformers of all vintages that are operational in

year y , Ship(y) = shipment of new transformers in year y , Std_year = year the standard becomes effective, and Stock(age) = age in years of the stock of transformers.

10.2.2.7 Unit Energy Consumption

One of the final quantities DOE calculated to estimate the NES was the unit energy consumption for affected stock. The unit energy consumption multiplied by the capacity shipped

and t he site

- to -source conversion factor equals the annual site energy consumption from which

DOE derived total NES.

Annual unit energy consumption (UEC(y)) for affected stock is the annual energy consumption per unit capacity for transformers shipped after t he effective date of a standard. DOE calculated the losses per transformer as the sum of no -load losses plus load losses. It calculated the load losses as the rated load loss times the square of the RMS load, adjusted for load growth. Average energy consum ed per unit capacity for affected stock varies from year to

year because of load growth effects. The annual unit energy consumption for affected stock of distribution transformers is given by the following equation.

UEC(y) = E NL + E LL

× [RMS × LAdjust(y )] 2

.10

- 14 Where :

E NL = rated no

- load losses per kVA capacity,

E

LL = rated load losses per kVA capacity,

RMS = root mean square, and

LA djust(y) = load adjustment factor for year y

.

After DOE defined the unit energy consumption for affected stock, only one more input was necessary to complete the NES calculation: the site

- to -source conversion factor.

10.2.2.8 Site

- to

- Source Electricity Conversion

The site

- to

- source conversion factor for electricity is the factor by which site energy (in

kilowatt -hours (kWh) ) is multiplied to obtain primary (source) energy (in quadrillion British

thermal units (quads). Because the NES estimates the change in energy use of the resource (e.g.,

at the power plant), this conversion factor is necessary to account for losses in generation, transmission, and distribution. After calculating energy consumption at the site of use— the

installed transformer

— DOE multiplied the site energy consumption by the conversion factor to obtain primary energy consumption, expressed in quads. This conversion permitted comparison across (source) fuels by taking into account the heat content of various fuels and the efficiency of various energy conversion processes. The annual conversion factor s are the U nited States

average s for generating electrici ty for both peak and base loads . DOE used average heat rates corresponding to base load for no- load losses (or core losses) , and average heat rates corresponding to peak load for load losses (or coil losses). It used different rates because load

losses are higher during transformer peak loads, whereas no- load losses occur at all times. DOE developed conversion factors using a variant of the NEMS 5 called NEMS

- BT. b Table 10.2.5 presents the average annual conversion factors DOE used.

b DOE/EIA approve d use of the name NEMS to describe only an official version of the model without any modification to code or data. Because this analysis entailed 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).10

- 15 Table 10.2.5 Average Site

- to -Source Conversion Factors for No-Load Losses and Load

Losses

Year No

- Load Losses Load Losses

2015 1.890 2.443

2016 1.888 2.446

2017 1.885 2.444

2018 1.883 2.443

2019 1.883 2.444

2020 1.886 2.446

2021 1.896 2.452

2022 1.900 2.450

2023 1.907 2.447

2024 1.915 2.448

2025 1.915 2.439

2026 1.916 2.425

2027 1.920 2.414

2028 1.921 2.395

2029 1.920 2.377

2030 1.919 2.355

2031 1.920 2.345

2032 1.920 2.330

2033 1.919 2.308

2034 1.920 2.294

2035 1.923 2.289

2036

– 2045 1.923 2.289

The conversion factors change over time to account for the changes in electricity

generating sources. The NES spreadsheet model includes the conversion factors for each year of the projection. DOE and interested parties can examine the effects of alternative assumptions by revising th e conversion factors in the NES spreadsheet

.

The conversion of site energy savings to source energy savings and the summation of energy savings throughout the forecast period complete the calculations needed to estimate the NES. The next section (section 10.3) describes the technical details of the NPV calculation. Section 10.4 presents the NES and N PV results from the NIA spreadsheet model.

10.3 NET PRESENT VALUE

DOE used a national net present value (NPV) accounting component in the NIA spreadsheet to estimate the national financial impact on customers from the imposition of potential energy efficiency standards. DOE combined the output of the shipments model with energy savings and financial data from the LCC analysis to calculate an annual stream of costs and benefits resulting from trial standard levels ( TSL s) for distribution transformers. It10

- 16 discounted this time series to 2010 and summed the result for 2016–2105 (the year the last unit shipped in 2045 retires from service) , yielding the national NPV.

10.3.1 Overview

The NPV is the present value of the incremental economic impact of a TSL . Like the

N ES, the NPV calculation started with distribution transformer shipments and stocks, estimates of which are outputs of the shipments model. DOE then obtained estimates of distribution transformer first costs, losses, and average marginal electricity costs f rom the LCC analysis. It

calculated the costs of transformer purchases and installation, then the corresponding operating

costs for both a base case and a standards case, by applying marginal prices to the energy ( both

energy and electricity system capacit y) used by the stock of transformers for each year. In the standards case, more expensive, but more efficient

, transformers gradually replace less efficient units. Thus, the operating cost per unit capacity for the stock of transformers gradually decreases in the standards case relative to the base case, while equipment costs increase.

DOE used a simple national average discount factor to discount purchases, expenses, and operating costs for distribution transformers. The discount factor converts a future expense or benefit to a present value. The difference in present value of all expenses and benefits between

the base

- case and standards scenario represents the impact on national NPV. DOE calculated the NPV impact for transformers purchased during the forecast period ( between the effective date of the standard and 2104, inclusive) . Mathematically, NPV is the value in the present of a time series of costs and savings, described by the equation:

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 three equations.

PVS = � � OC Base Cap ( y ) × OC Std Cap ( y ) � × Af f Stock ( y ) × Discount Factor ( y )

. 2104

y=Std

_ year

Where :

OC Base /Cap(y) = operating cost in year y per unit capacity of transformer for the base case, Aff_Stock(y) = stock of transformers of all vintages that are operational in year

y ,

y = the year (from effective date of the standard to the year when units purchased in 2045 retire (in 2104), and10

- 17 Discount Factor(y) = discount factor for year y , defined in the next equation.

Discount Factor ( y ) = 1
(1 + Discount Rate ) ( y− referen ce year )

W here:

reference year = 2016, and

discount rate = the discount rate, as described in section 10.3.2.7

.

PVC is determined as follows.

PVC = Std

_ year 2104 � FC std Cap ( y )

− FC Base Cap ( y ) � × Sh ip ( y ) × DiscountFactor ( y )

.

Where :

FC Base /Cap (y) = first cost of the transformer per unit of capacity in the Base case for a

EL Base in year y (first cost is described in section 10.3.2.1);

FC Std

/Cap (y) = first cost of the transformer per unit of capacity in the Standards case

for a EL Std in year y ( first cost is described in section 10.3.2.1 ); Std_year = the year the standard come s into effect, and Ship (y) = shipments of transformers in year y for the standards case.

DOE calculated NPV using its projections of national expenditures for distribution transformers, including purchase price (equipment and installation price) and operating costs (electricity and maintenance costs). It calculated costs and savings as the difference between a

TSL and a base case lacking national standards. It discounte d future costs and savings to the

present (2012$). DOE calculated a discount factor from the discount rate and the number of years between the year to which the sum is being discounted (2012) and the year in which the costs and savings occur. The NPV is th e sum over time ( 2016–2104) of the discounted net financial savings.

The following sections describe inputs to the NPV calculation that are not described

elsewhere

.

10.3.2 Inputs

Inputs to t he NPV model include cost inputs, inputs important for detailing electricity capacity costs, and several of the inputs used by the NES calculation. This section provides details on those inputs that were not described for the NES or shipments model . The specific input s for the NPV are :

1. f irst cost

, 2. o perating cost

,10

- 18 3. peak responsibility factor,

4. i nitial peak load

, 5. scalar for e lectricity price forecast

, 6. m arginal electricity costs

, and

7. discount rate.

Each input is described in detail below.

10.3.2.1 First Cost

The first cost includes all the initial costs incurred with the installation of a distribution transformer. DOE expresses first cost in terms of cost per unit capacity. Specifically, it defines the first cost of acquiring a transformer with the following equation.

FC/C ap = (P + Install)/Cap.

Where :

FC = first cost ; Cap = rated capacity of the transformer ;
P = price of the transformer including shipping, and taxes ; and

Install = installation cost of the transformer.

The above values we re obtained from the LCC calculation as the averages for individual design lines. DOE convert ed the first cost of a representative design to an estimated average first cost for a distribution of sizes within a particular equipment class. The adjustment inc orporates the 0.75 scaling rule and the mapping of design line to equipment class discussed in sections 10.2.2.1 and 10.2.2.2. Costs are expressed in units of 2011$ per kVA of rated transformer capacity. Table 10.3.1 shows the resulting mean first costs per kVA for distribution transformers by EL and equipment class.10

- 19 Table 10.3.1 First Cost c

Equipment

Class of Distribution Transformers by Trial Standard Level and Equipment Cl ass (2011 $/kVA)

Base TSL 1 TSL 2 TSL 3 TSL 4 TSL 5 TSL 6 TSL 7

1 99.98 102.50 107.97 107.99 111.64 113.59 118.19 164.42

2 30.60 32.84 95.49 95.52 98.80 100.67 103.97 151.11

3 75.31 75.31 75.31 95.54 110.81 110.81 153.61

4 55.78 61.60 61.62 65.13 72.81 79.39 103.53

5 41.85 42.12 44.10 44.63 44.63 72.26

6 33.03 33.22 35.46 35.56 35.56 59.34

7 55.12 57.51 59.54 69.61 69.61 94.96

8 39.59 41.09 43.39 51.00 51.00 71.01

9 51.03 51.93 57.01 57.01 57.01 81.11

10 39.48 40.17 44.10 44.11 44.11 62.76

10.3.2.2 Operating Costs

Transformer operating cost s are the annual cost of transformer losses. Operating costs are a complex, yet essential, part of calculating the national economic impact of a standard . DOE

used distinct costs to calc ulate the value of various types of losses and peak capacity savings. Potential load growth also requires an adjustment factor. Peak loading, peak load coincidence, and average loading require additional factors to characterize load losses. Finally, DOE used a

scalar for the electricity price forecast to characterize future trends in electricity prices consistent

with the EIA’s AEO20 12 forecast

. 4

In calculating transformer operating costs, DOE assumed zero incremental maintenance

cost s . It used the following formula to capture the diversity of factors that can affect annual operating costs.

OC/Cap = EPFS(y) × (E NL × (NLL MCC + 8760 × NLL MEC ) + E LL × (LAdjust(y)) 2

× (PRF × PL 2 × LL MCC + 876 0 × RMS 2 × LL MEC ))/Cap

.

Where :

OC = the operating cost, Cap = the rated capacity of the transformer, EPFS(y) = the scalar for the electricity price forecast for year y , E

NL = the no-load losses at rated load,

NLL MCC = the marginal cost of capacity for no -load losses,

NLL MEC = the marginal cost of energy for no-load loss es
,

c First c ost inc ludes installation cost.10

- 20 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,

LL MCC = the marginal cost of capacity for load losses,

R MS = the root mean square loading of the transformer, and

LL MEC = the marginal cost of energy for load loss es

.

DOE expressed the operating costs in 2011 $ per kVA of rated capacity. W hen calculating the NES (sections 10.2.2.1 and 10.2.2.2), DOE also used an adjustment factor to scale to E NL

and

E

LL

to convert from design- line data to equipment class estimates.

10.3.2.3 Peak Responsibility Factor

The transformer peak responsibility factor (PRF) is the fraction of the distribution transformer peak load that is coincident with the system peak, calculated by taking the square of

the ratio of the transformer load at the ti me of the customer peak load to the transformer peak load. In combination with the initial peak load, the PRF is necessary for estimating impacts on capacity costs of transformer load losses. DOE used the average PRF from the hourly and the monthly load analyses for liquid -immersed and dry- type transformers, respectively, as reported in the LCC analysi s. Table 10.3.2 presents the PRFs used in the analysis of the 12 equipment

classes (EC s).

Table 10.3.2 Peak Responsibility Factors by Equipment Class

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10

PRF 0. 28 0.3 6 0.23 0.23 0.46 0.46 0.46 0.46 0.46 0.46

10.3.2.4 Initial Peak Load

The initial peak load is the annual per-unit peak load on the distribution transformer during the first year of operation. This factor, in combination with the PRF, is necessary for calculating impacts on capacity cost s from transformer load losses. The initial peak load is estimated as a percentage of the rated peak load of the transformer. The IEEE Draft Guide for

Distribution Transformer Loss Evaluation (2001) 7 defines a similar , but different, measure of peak transformer load called an “Equivalent Annual Peak Load” that accounts for chan ges in peak load during the life of the transformer. Rather than use the equivalent annual peak load,

DOE used a distribution to characterize a range of initial peak loads. Chapter 6, sections 6.2.3.3 and 6.3.3.3, further describe DOE’s method. Table 10.3.3 presents the initial peak loads used in

the NPV analysis for the 12 equipment classes.

Table 10.3.3 Initial Peak Loading by Equipment Class

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10

Initial Peak Load 0.88 0.88 0.80 0.80 0.80 0.80 0.80 0.80 0.80 0.8010

- 21 10.3.2.5 Scalar for Electricity Price Projection s

The scalar for forecasting electricity price s converts current electricity costs into projected costs for 2010 through 2105. The scalar is the ratio of the unit cost of electricity in real dollars in a given year to the real cost of electricity in 2011 . DOE used projection s from

AEO20 12 4 to obtain the scalar for electricity price projections. For the period beyond 2035,

DOE extrapolated the scalar based on the EIA real dollar price trend for 2025–2035.

10.3.2.6 Marginal Electricity Costs

DOE needed to characterize f our distinct marginal electricity costs to calculate the operating costs of distribution transformers and the financial impact of potential efficiency standards. The four marginal costs are: the marginal capacity cost for no-load loss es
, (t he marginal capacity cost for load loss es
, the marginal energy cost for no- load loss es , and the marginal energy cost for load loss es . A n electricity system has both energy costs and capacity costs. Depending on the shape of a particular load, the average value of capacity costs may differ

from those of energy costs. Because no-load losses and load losses have distinct load shapes, and

because different customers experience different load shapes, costs vary both by loss type and by

the equipment class of a transformer. DOE therefore used distinct marginal energy and capacity costs for no-load losses and load losses for each transformer equipment class. No transfor mer size scaling is necessary for the marginal costs, although DOE needed to map design line s to equipment classes (as described in section 10.2.2.2) to convert the design line output from the

LCC to equipment class information for calculating the NPV. DOE calculated capacity costs in units of 2011$/kilowatt ( kW)/year, and energy costs in units of 2011$/kWh. Table 10.3.4 summarizes the four marginal costs for the 12 equipment classes

.

Table 10.3.4 Marginal Energy and Capacity Costs by Equipment Class
Marginal Energy Cost by Equipment Class $/kWh

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10

NLL 0.067 0.067 0.060 0.060 0.060 0.060 0.060 0.060 0.060 0.060

LL 0.073 0.073 0.059 0.059 0.059 0.059 0.059 0.059 0.059 0.059
Marginal Capacity Cost by Equipment Class $/kW/year

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10

NLL 264.97 266.15 142.62 142.62 142.62 142.62 142.62 142.62 142.62 142.62

LL 164.37 165.64 114.40 114.86 101.46 101.46 101.69 101.47 101.46 101.46

10.3.2.7 Discount Rate

The discount rate, which is the final input to the NPV calculation, expresses the time value of money. DOE used real discount rates of 3 percent and 7 percent, as established by the Office of Management and Budget guidelines on regulatory analysis. 9 The discount rates DOE

used in the LCC differ from those used in the NPV calculations, in that the NPV d iscount rates represent 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.10

- 22 10.3.2.8 Projection of Future Product Prices

For reasons discussed in chapter 8 (Section 8.2.1.1), DOE used a constant price assumption for the default forecast in the NIA. To investigate the impact of different product price forecasts on the consumer NPV for the considered TSL s for medium electric m otors, DOE also considered two alternative price trends. Both trends are based on a power

- law fit on the

deflated producer price index for electric power and specialty transformer manufacturing

. Details on how these alternative price trends were developed are in appendix 10B of the TSD, which also presents the results of the sensitivity analysis.

10.4 RESULTS

The following sections summarize the results of the NES and NPV calculations performed for the NIA

.

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

Table 10.4.1 presents the NES and NPV results from the spreadsheet model for TSL s 1–5

for medium- voltage liquid

- immersed and dry- type distribution transformers and TSL s 1

– 6 for low-voltage dry- type transformers . It should be reiterated that the NES spreadsheet model uses discrete point values rather than a distribution of values for all inputs.10

- 23 Table 10.4.1 Results for Cumulative National Energy Savings (2016–2045 ) and Net Present Value ( 2016–2104 )

Discount Rate (%) Trial Standard Level

1 2 3 4 5 6 7

Liquid

- Immersed

Cumulative Source Savings 2044 (Quads) 0.92 1.56 1.76 3.31 3.30 4.09 7.01

Net Present Value (billion 2011$) 3 2.00 3.00 4.00 5.00 6.00 7.00

- 8.50

7 0.58 0.69 0.91 1.92 1.60 0.74

- 12.97

Low

- Voltage Dry

- Type

Cumulative Source Savings 2044 (Quads) 2.28 2.43 3.05 4.39 4.48 4.94

Net Present Value (billion 2011$) 3 8.38 9.04 10.38 13.65 11.80 5.17

7 2.45 2.67 2.82 3.34 2.22 -1.92

Medium

- Voltage Dry

- Type

Cumulative Source Savings 2044 (Quads) 0.15 0.29 0.53 0.53 0.84

Net Present Value (billion 2011$) 3 0.49 0.79 1.12 1.12

- 0.20

7 0.13 0.17 0.12 0.12 -0.89

10.4.1.2 Results for Liquid

- Immersed Distribution Transformers

Figure 10.4.1 illustrates the typical pattern of source energy savings and costs resulting from standards for liquid- immersed distribution transformers. The figure shows the nature of net savings for all six TSL s relative to the base case. The figure also shows the NPV at both a 3- percent and a 7

- percent discount rate.

Figure 10.4.1 Liquid

- Immersed Distribution Transformers: Impacts of Standards on National Energy Savings

and Net Present Value - 15.0 - 10.0 - 5.0 0.0 5.0 10.0 15.0

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0

1 2 3 4 5 6 7Net Present Value (Billion US$)Cumulative Source Energy Savings (Quads)

Trial Standard Levels Cumulative Source Energy Savings and NPV for Liquid

- Immersed Units

Cumulative Source Savings 2105 (Quads) Net Present Value ($Billions) discounted at 7%

Net Present Value ($Billions) discounted at 3%10

- 24 Figure 10.4.1 shows that, although the savings in ene rgy (quads) are greatest at TSL s 7 (max tech), the associated financial savings decrease at either the 3

- percent or 7 -percent discount

rate. A t a discount rate of three percent, the NPV of cumulative source savings for liquid

immersed transformers are high est at TSL 4. At a discount rate of seven percent, the NPV is highest at TSL 4.

10.4.1.3 Results for Low-Voltage Dry

- Type Distribution Transformers

Figure 10.4.2 shows the pattern of source energy savings and costs resulting from potential standards for low -voltage dry- type distribution transformers. The figure shows the nature of net savings for the s ix TSL s relative to the base case. The figure also shows the NPV at

both a 3- percent and a 7

- percent discount rate.

Figure 10.4.2 Low-Voltage Dry

- Type Distribution Tr ansformers: Impacts of Standards on National Energy Savings

and Net Present Value

Figure 10.4.2 shows that the cumulative savings in energy (quads) is highest under TSL s
6 , the associated financial savings decrease dramatically at either discount rate. A t a discount rate

of three percent, the NPV of cumulative source savings for dry- type transformers are highest

under TSL 4. At a discount rate of seven percent, the savings are highest under TSL 4.

10.4.1.4 Results for Medium

- Voltage Dry

- Type Distribution Transformers

Figure 10.4.3 illustrates the typical pattern of source energy savings and costs resulting

from standards for medium

- voltage dry

- type distribution transformers. The figure shows the nature of net savings for all five TSL s relative to the base case. The figure also shows the NPV at

both a 3- percent and a 7 -percent discount rate. - 4.0 - 2.0 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0

0.0 1.0 2.0 3.0 4.0 5.0 6.0

1 2 3 4 5 6Net Present Value (Billion US$)Cumulative Source Energy Savings (Quads)

Trial Standard Levels Cumulative Source Energy Savings and NPV for Low

- Voltage Dry

- Type Units

Cumulative Source Savings 2105 (Quads) Net Present Value ($Billions) discounted at 7%

Net Present Value ($Billions) discounted at 3%10

- 25 Figure 10.4.3 Medium -Voltage Dry- Type Distribution Transformers: Impacts of Standards on National Energy Savings and Net Present Value

Figure 10.4.3 shows that, although the savings in energy (quads) are greatest at TSL s 5 (max tech), the associated financial savings decrease dramatically at either the 3

- percent or 7

- percent discount rate. At a discount rate of three percent, the NPV of cumulative source savings

for medium-vol tage dry

- type distribution transformers are highest at TSL 4. At a discount rate of

seven percent, the NPV is highest at TSL 3.

10.5 ANNUALIZED NATIONAL COSTS AND BENEFITS

The benefits and costs of the proposed standards for distribution transformers can be expressed in terms of annualized values over the analysis period. The annualized monetary values are the sum of (1) the annualized national economic value of the benefits from operating products that meet the proposed standards (consisting primarily of ope rating cost savings from using less energy, minus increases in equipment purchase costs, which is another way of representing consumer NPV), and (2) the monetary value of the benefits of emission reductions, including CO 2 emission reductions. The emissions reductions for each TSL are described in chapter 15, and the derivation of the monetary value of the benefits of emission reductions is described in chapter 16 of this TSD. The value of the CO 2 reductions, otherwise known as the

s ocial cost of carbon (SCC ), is calculated using a range of values per metric ton of CO 2 developed by a recent interagency process. The derivation of the time series of SCC values is discussed in Appendix 16-A of this TSD.

Although combining the values of operating savings and CO 2 reductions provides a useful perspective, two issues should be considered. First, the national operating savings are - 1.0 - 0.5 0.0 0.5 1.0 1.5

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90

1 2 3 4 5Net Present Value (Billion US$)Cumulative Source Energy Savings (Quads)

Trial Standard Levels Cumulative Source Energy Savings and NPV for Medium

- Voltage Dry

- Type Units

Cumulative Source Savings 2105 (Quads) Net Present Value ($Billions) discounted at 7%

Net Present Value ($Billions) discounted at 3%10

- 26 domestic U.S. consumer monetary savings that occur as a result of market transactions while the

value of CO 2 reductions is based on a global value. Second, the assessments of operating cost savings and CO 2 savings are performed with different methods that use quite different time frames for analysis. The national operating cost savings is measured for the lifetime of equipment shipped in the 30-year analysis period. The SCC values, on the other hand, reflect the present value of future climate -related impacts resulting from the emission of one ton of carbon dioxide in each year. These impacts go well beyond 2100.

10.5.1 Calculation Method

DOE us es a two

- step calculation process to convert each time

- series of costs and benefits into annualized values. First, DOE calculates a present value in the “present” year used in discounting the NPV of total consumer costs and savings. d For this calculation, DOE uses discount rates of three and seven percent for all costs and benefits except for the value of CO 2 reductions. For the latter, DOE uses the discount rate appropriate for each SCC time- series (see chapter 16 for discussion).

PV x = � ( x ( t )

∙ ( 1 + r x ) y NPV − t )

t = y 1 , y T

Where:

x ( t ) = Time -series under evaluation,

PV x = Present value of the time

- series x
, y 1 = First year in the analysis period,

y T = Last year in the analysis period,

y NPV = Year to which the NPV of consumers’ costs and savings are being discounted,

r x = Discount rate used to discount the annual values of time- series x to year y NPV

.

In the second step, DOE calculates, from the present values, the fixed annual payments over a 30-year period, starting in the first year of the analysis period (i.e., the compliance year), which yields the same present values with discount rates of three and seven percent. This requires projecting the present values in the “present” year ahead to the compliance year. The fixed annual payments are the annualized values.

Ann
x

, r = PV x ∙ f y 1 − y NPV , r ∙ a 30

, r = PV x ∙ ( 1 + r ) y 1 − y NPV

∙ r ∙ ( 1 + r ) 30

( 1 + r ) 30

− 1

Where:

Ann
x

, r = Annualized value of the time- series x
,

d For the value of emissions reductions, DOE uses a time series that corresponds to the time period used in calculating the operating cost savings (i.e., through the final year in which products shipped are still operating).10

- 27 f

n

, r = Factor to project a value n years ahead e

n = Nu mber of years between the “present” year and the compliance year

, with r discount rate,

a 30

, r = Factor to annualize present values over a 30-year period with r discount rate.

Although DOE calculates annualized values, this does not imply that the time- series of cost and benefits from which the annualized values were determined would be a steady stream of

payments.

10.5.2 Results for the Considered Standards

The notice associated with this TSD states that DOE is selecting amended energy conservation standards that correspond to TSL 1 for liquid- immersed distribution transformers,

TSL 2 for low -voltage dry- type distribution transformers, and TSL 2 for medium-voltage drytype distribution transformers. Estimates of annualized benefits and costs for the proposed

standards are shown in Table 10.5.1.

The Primary Estimate , Low Net Benefits Estimate , and High Net Benefits Estimate utilize forecasts of energy prices from the AEO201 2 Reference case, Low Economic Growth case, and High Economic Growth case, respectively. In addition, incremental equipment costs reflect no change in the Primary es timate, rising equipment prices in the Low Net Benefits estimate, and declining equipment prices in the High Net Benefits E stimate

.

e n is the number of years between the “present” year and the compliance year.10

- 28 Table 10.5.1 Annualized Benefits and Costs of Standards for Distribution Transformers

Discount Rate

% Primary

Estimate* Low Net Benefits

Estimate* High Net Benefits

Estimate*

Million 2011$/year

Benefits

Operating cost savings 7% 581 559 590

3% 983 930 1003

CO 2 reduction monetized value ($4.9/t case)** 5% 57.7 57.7 57.7

CO 2 reduction monetized value ($22.3/t case)** 3% 237 237 237

CO 2 reduction monetized value ($36.5/t case)** 2.5% 377 377 377

CO 2 reduction monetized value ($67.6/t case)** 3% 721 721 721

NO X reduction monetized value ($2,591/ton)** 7% 8.60 8.60 8.60

3% 12.67 12.67 12.67

Total benefits† 7% plus CO 2 range 648 to 1311 625 to 1288 656 to 1319

7% 827 805 836

3% plus CO 2 range 1053 to 1716 1000 to 1663 1074 to 1737

3% 1233 1179 1253

Costs

Incremental product costs 7% 266 300 257

3% 282 325 271

Net Benefits

Total† 7% plus CO 2 range 381 to 1044 325 to 988 400 to 106310

- 29 7% 561 504 579

3% plus CO 2
range 771 to 1434 675 to 1338 803 to 1466

3% 950 854 982

* T his table presents the annualized costs and benefits associated with transformers shipped in 2016 −2045. These results include benefits to customers that accrue after 2045 from equipment purchased in 2016 −2045. Costs incurred by manufacturers, some of which may be incurred in preparation for the rule, are not directly included, but are indirectly included as part of incremental equipment costs. The Primary, Low Benefits, and High Benefits estimates utilize projections of energy prices from the AEO201 2

** The CO 2 values represent global monetized values of the SCC, in 2011$, in 201 1 under several scenarios. The values of $ 4.9 , $2 2.3 , and $ 36.5 per me tric ton are the averages of SCC distributions calculated using 5%, 3%, and 2.5% discount rates, respectively. The value of $ 6 7. 6 /t represents the 95 th percentile of the SCC distribution calculated using a 3% discount rate. The SCC time series used by DOE incorporate an escalation factor. The value

for NO X (in 2011$) is the average of the low and high values used in DOE’s analysis. Refere nce case, Low Estimate, and High Estimate, respectively. In addition, incremental equipment costs reflect a constant equipment price trend in the Primary Estimate, an increasing price trend in the Low Benefits Estimate, and a declin ing price trend in the H igh Benefits Estimate. The methods used to derive projected price trends are explained in section IV.F.2.

† Total Benefits for both the 3% and 7% cases are derived using the series corresponding to SCC value of $2 2.3 /t. In

the rows l abeled “7% plus CO 2 range” and “3% plus CO 2 range,” the operating cost and NO X benefits are calculated using the labeled discount rate, and those values are added to the full range of CO 2 values.

.10

- 30 REFERENCES

1. Hopkinson, P. & Puri, J. Distribution Transformer Market Shipment Estimates for 2001

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2. Hopkinson, P. & Puri, J. Distribution Transformer Market Shipment Estimates for 2009

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- Bureau of Economic Analysis Industry Economic Accounts Information Guide. Annual industry accounts: gross domestic product (GDP) by industry

. (2010).

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2036 . (U.S. Department of Energy: Washington DC, 2011).

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