10

- i CHAPTER 10. NATIONAL IMPACT ANALYSIS

TABLE OF CO NTENTS

10.1 INTRODUCTION

................................ ................................ ................................ ......... 10

- 3

10.2 NATIONAL ENERGY SAVI NGS

................................ ................................ ............... 10

- 6

10.2.1 National Energy Savings Overview

................................ ................................ ............... 10

- 6

10.2.2 National Energy Savings Inputs

................................ ................................ ..................... 10

- 7

10.2.2.1 Size Scaling of Losses and Costs

................................ ................................ . 10

- 8

10.2.2.2 Mapping Life

- Cycle Cost Design Line Data to Equipment Classes

............ 10

- 9

10.2.2.3 Root Mean Square Loading

................................ ................................ ....... 10

- 10

10.2.2.4 Load Growth

................................ ................................ .............................. 10

- 10

10.2.2.5 Affected Stock

................................ ................................ ........................... 10

- 12

10 .2.2.6 Unit Energy Consumption

................................ ................................ ......... 10

- 12

10.2.2.7 Electricity Site

- to

- Source Conversion

................................ ....................... 10

- 13

10.3 NET PRESENT VALUE

................................ ................................ ............................. 10

- 14

10.3.1 Net Present Value Overview

................................ ................................ ........................ 10

- 14

10.3.2 Net Present Value Inputs

................................ ................................ ............................. 10

- 16

10.3.2.1 First Cost

................................ ................................ ................................ .... 10

- 16

10.3.2.2 Operating Cost

................................ ................................ ........................... 10

- 17

10.3.2 .3 Peak Responsibility Factor

................................ ................................ ........ 10

- 18

10.3.2.4 Initial Peak Load

................................ ................................ ........................ 10

- 18

10.3.2.5 Electricity Price Forecast Scalar

................................ ................................ 10

- 19

10.3.2.6 Marginal Electricity Costs

................................ ................................ ......... 10

- 19

10.3.2.7 Discount Rate

................................ ................................ ............................. 10

- 20

10.4 RESULTS

................................ ................................ ................................ .................... 10

- 20

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

............ 10

- 20

10.4.1.2 Liquid

- Immersed Results

................................ ................................ ........... 10

- 20

10.4.1.3 Dry

- Type Results

................................ ................................ ....................... 10

- 21

LIST OF TABLES

Table 10.2.1 Mapping of Design Line to Equipment Class

................................ .................... 10

- 9

Table 10.2.2 Average Site

- to

- Source Conversion Factors for No

- Load Losses and Load

Losses

................................ ................................ ................................ ............... 10

- 13

Table 10.3.1 First Cost of Distribution Transformers by Candidate Standard Level and Equipment Class (2010$/kVA)

................................ ................................ ........ 10

- 17

Table 10.3.2 Peak Responsibility Factors by Equipment Class

................................ ............ 10

- 18

Table 10.3.3 Initial Peak Loading by Product Class

................................ ............................. 10

- 19

Table 10.3.4 Marginal Energy and Demand Costs by Equipment Class

.............................. 10

- 19

Table 10.4.1 Summary of Cumulative National Energy Savings (2016

– 2045) and Net Present Value (2016

– 2104) Impac t

................................ ................................ . 10

- 2010

- ii LIST OF FIGURE S

Figure 10.1.1 National Impact Analysis Spreadsheet Flowchart

................................ ............. 10

- 4 Figure 10.4.1 Liquid

- Immersed Distribution Transformers: National Energy Savings and Net Present Value Impacts

................................ ................................ ............... 10

- 21 Figure 10.4.2 Dry

- Type Distribution Transformers: National Energy Savings and Net Present Value Impacts

................................ ................................ ...................... 10

- 2110

- 3 CHAPTER 10. NATIONAL IMPACT ANAL YSIS

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 whether the benefits of the

candidate standard level exceed its burdens. Key factors in this decision are: the total projected amount of energy savings likely to result directly from th e imposition of the standard, and the savings in operating costs throughout the life of the covered equipment 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 equipment t hat are likely to result from the promulgation of the standard.

To satisfy this EPCA requirement and to more fully understand the national impact of potential efficiency regulations for distribution transformers, DOE conducted a national impact analysis (NIA) . This analysis assessed future national energy savings (NES) from transformer energy conservation standards and the national economic impact using the net present value (NPV) metric.

This chapter describes the method used to estimate the national i mpacts of candidate standard levels (CSLs) for medium voltage liquid

- immersed and low and medium voltage dry

- type
distribution transformers ; these transformers have been categorized into ten distinct equipment classes. DOE evaluated the following impacts: (1) NES attributable to each possible standard, (2) monetary value of those energy savings to consumers of the considered equipment , (3) increased

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

To conduct its NIA, DOE determined both the NES and NPV for each of the efficiency

levels being considered as the new standard for distribution transformers . DOE performed all

calculations for each considered equipment class using a Microsoft Excel spreadsheet model,

which is accessible on the Internet. < www.eere.energy.gov/buildings/appliance_standards/ > 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 the considered equipment . Chapter 9 provides a detailed description of the shipments models

, includ ing detailed descriptions of consumers’ sensitivities to total installed

cost, operating cost, and income, and how DOE captured those sensitivities within the model.

The NES and NPV together constitute the NIA model. Details and instructions for using the NIA model are provided in appendix 10

- A.

To estimate the national impacts of new standards for all the equipment classes considered in this rulemaking, DOE used a rescaling factor (described in Section 10.2.2.1) to10

- 4 allocate the equipment cost and annual energy consumption of each representative size equipment to all sizes class es within the equipment class

.

Figure 10.1.1 National Impact Analysis Spreadsheet Flowchart

Figure 10.1.1 presents a graphical flow diagram of the distribution transformer NIA (NES and NPV) model and spreadsheet. In the diagram, the arrows show the direction of information

flow for the calculation. The information begins with inputs (shown as parallelograms). As information flows from these inputs, it may be integrated into intermediate results (shown as10

- 5 rectangles) or through integrating sums or differences (shown as circles) into major outputs (shown as boxes with curved bottom edges). Note that the shipments model portion of the flow diagram (shaded) is discussed in Chapt er 9.

The NIA calculation started with the shipments model

. This model integrated the inputs of 2001 shipments estimates from DOE’s contractor 1 , the U.S. Bureau of Economic Analysis (BEA) transformer quantity index 2 , electricity market shares from DOE’s Energy Information

Administratio n (EIA) 3

, 4 and equipment price e stimates from DOE’s life

- cycle cost (LCC) analysis

. The model produce d 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), enabling DOE to estim ate the stock that is affected by trial standards and transformer

retirements.

After the shipments calculation, the NES and NPV calculations 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 the equipment costs

for transformer size and equipment class to convert the data from representative design lines to

average equipment class information. Additional inputs on average and peak losses

— including root mean square (RMS) loading, peak loading, and peak responsibility factor

— allowed DOE to convert rated losses into actual losses. At this point, the information flow for the NES and NPV calculation split into two paths

.

On one path, the NES calculation sums the 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 these 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 the National Energy Modeling System (NEMS) 5 . The average heat rates from NEMS include the

transmission and distribution losses

. Summing the annual energy savings for the forecast period

, which extends from 2016 through 2045

, provide s the final NES result.

On the other path, the NPV calculation starts with 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 actu al peak and average losses, provide the estimate of the operating cost. Meanwhile, the adjusted equipment installed cost times the annual shipments provide s the estimate of the total annual equipment costs. DOE calculated

three differences to assess the net impact of each cand id ate standard level (CSL) . The first

difference was between the candidate standards scenario equipment costs and the base case equipment costs to obtain the net equipment cost increase from a candidate standard. The second

differe nce was between the base case scenario operating cost and the candidate standards scenario operating cost to obtain the net operating cost savings from a candidate standard. The third difference was between the net operating cost savings and the net equip ment cost increase to get the net expense or savings for each year. DOE then discounted the net expenses or savings10

- 6 to 20 10 and summed them over the years 2016

– 2104 a for transformers purchased during 2016

- 2045 to provide the N PV impact of a candidate standard.

T wo models included in the NIA are provided below

— 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 DOE performed ea ch model’s calculations and follows with a summary of the inputs. The final subsections of each technical description describe each of the major inputs and computation steps in detail and with equations, when appropriate. After the technical model descri ptions, this chapter presents the results of the

NIA calculations.

10.2 NATIONAL ENERGY SAVI NGS

DOE 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 ener gy savings. The savings shown in the NES reflect decreased energy losses resulting from the installation of new, more efficient transformer units nationwide, in comparison to a base case with no national standards. Positive values of NES correspond to ne t energy savings, specifically a decrease in energy consumption after implementation of a standard in comparison to the energy consumption

in the base case scenario.

10.2.1 National Energy Savings Overview

DOE calculated the cumulative incremental energy savings from a transformer efficiency standard, relative to a base case scenario of no standard, over the forecast period. It calculated

NES for each candidate standard level, in units of quads, for standards that it assumed will be implemented in the year 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 losses from the LCC analysis (Chapter 8), and calc ulated the total energy use by the stock of transformers for each year, for both a base case and a standards case. Over time, in the standards case, more efficient transformers gradually replace less efficient ones. Thus, the energy per unit capacity use d by the stock of transformers gradually decreases in the standards case relative to the base case. DOE 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 for transmission, distribution, and generation losses. For each year analyzed, the difference in source 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 name

- plate efficiency besides the incremental efficiency improvement indicated by the LCC calculation.

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

maximum life

- 1).10

- 7 DOE examined proprietary shipments data provided by the transformer industry and fo und that the data lacked conclusive trends in efficiency improvement. Therefore, DOE felt that future efficiency trends were generally indeterminate and chose to use a fixed baseline efficiency. DOE also assumed that the efficiency of transformers does n ot degrade over time. This means the annual energy savings can be described in terms of an affected stock (see Equation 10.1), as described in section 9.3.11 in the shipments chapter:

In calculating the NES, DOE did not assume any trends in transformer name

- plate efficiency besides the incremental efficiency improvement indicated by the LCC calculation. DOE examined proprietary shipments data provided by the transformer industry and found that the data lacked conclusive trends in efficiency improvement. Therefore, DOE felt that future efficiency trends were generally indeterminate and chose to use fixed baseline efficiency. DOE also assumed that the efficiency of transformers does not degrade over time. This means the annual energy savings can be described in terms of an affected stock (see Equation 10.1), as described in section 9.3.11 in the shipments chapter:

AES(y) = (UEC Base − UECStd ) × Aff _ Stock(y) Eq. 10.1

where:

AES(y) = the annual energy savings in yea r 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) = stock of transformers of all vintages that are operational in year y.

Then, given the annual ener gy savings, the NES can be calculated as a simple sum:

NES = ∑ SiteToSource ( y

) × AEC ( y

) 2045

y

=

St

d year Eq. 10.2

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 of the affected stock, the key to the NES calculation is in calculating UECBase and UECStd, using the input from the LCC analysis and including the site

- to

- sourc e conversion factor. The next section summarizes the inputs necessary for the NES calculation and then presents them individually.

10.2.2 National Energy Savings Inputs

The NES model inputs fall into three broad categories: (1) those that help convert the

data from the LCC into data for 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

- source10

- 8 conversion factor, which enables the calculation of source energ y consumption from site energy use. The specific list of NES model inputs is as follows:

1. s ize scaling of losses and costs ; 2. m apping of LCC design line data to equipment classes ; 3. r oot mean square loading ; 4. l oad growth ;
5. a ffected stock ; 6. e ffective date of stand ard ;
7. u nit energy consumption ; and

8. e lectricity site

- to

- source conversion

.

10.2.2.1 Size Scaling of Losses and Costs

DOE used a scaling relationship, or equation, to project the economic results from one transformer design line to similar transformers of different s izes. This relationship is a key element in adjusting losses and costs from a representative transformer in the LCC to the distribution of transformer sizes represented in the NES calculation.

As described in the engineering analysis, DOE applied the “ 0.75 scaling rule ” for projecting losses and costs from one design line to transformers of other sizes. In the NES analysis, DOE calculated shipments in terms of installed capacity. It estimated the losses associated with a stock of transformers, and the c osts associated with a capacity shipped, by multiplying the relevant capacity by the average losses, or costs

, per unit capacity. Before applying the 0.75 scaling rule, DOE calculated the losses and costs per unit of installed capacity within a given engin eering design line. Then it calculated an adjustment factor using the 0.75 scaling 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 transform ers that the design line represents. This adjustment factor is given by the following equation:

AdjFactor = ∑ [ S h ip i × Cap i 0

. 75 i ] / ( Cap DL 0

. 75 × ∑ S h ip i i ) Eq. 10.3

where:

AdjFactor = adjustment factor that gives the shipment

- weighted losses or costs per transformer when multiplied by the design line losses or costs, Ship i Cap = shipments in the i

- th size category,

i Cap = the rated capacity for the transformers in the i

- th size category, and

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

in the following equation:

AvgLossPerCapDL = LossPerCapDL × AdjFactor × Cap DL / Capavg Eq. 10.410

- 9 where:

LossPerCap DL

Cap = t he loss, or cost per unit capacity, for the design line unit from the LCC analysis, and

avg = the shipme nt

- weighted average size of transformers represented by a particular design line.

Once the losses and costs from the LCC represented the correct size distribution, they needed a further adjustment so that they represented the appropriate equipment classe s, as described in the next section.

10.2.2.2 Mapping Life

- Cycle Cost Design Line Data to Equipment Classes

The NES and NPV calculations use the LCC calculations as the source of most input data. DOE performed the LCC calculations by design line, whereas any eventual standard would be promulgated by equipment class. As a first step, therefore, the NES calculation aggregates the LCC design line data into equipment classes. This design

- line

- to

- equipment

- class aggregation

was the process by which DOE took the res ults from an economic analysis of engineering design

lines and combined them to provide estimates of economic impact by equipment class.

To represent the variety of designs in some equipment classes, DOE analyzed up to three different design lines per eq uipment class. Specifically, equipment class 1 (single

- phase,

medium

- voltage, liquid

- immersed transformers) is represented by three design lines, and equipment class 2 (three

- phase, medium

- voltage, liquid

- immersed transformers) is represented by two design lines. DOE did not specifically examine single

- phase, medium

- voltage dry

- type design lines. For single

- phase equipment classes 5 , 7

, and 9, DOE used the appropriate three

phase design lines divided by three. Table 10.2.1 presents the mapping of design lin e (DL) to equipment class ( E C).

Table 10.2.1 Mapping of Design Line to Equipment Class Equipment Class BIL Capacity Mapping Liquid

- immersed, medium

- voltage, single

- phase Any 10

- 833 DL1 + DL2 + DL3 Liquid

- immersed, medium

- voltage, three

- phase Any 15

- 2500 DL4 + DL5 Dry

- type, low

- voltage, single

- phase ≤ 10 kV 15

- 333 DL6 Dry

- type, low

- voltage, three

- phase ≤ 10 kV 15

- 1000 DL7+DL8 Dry

- type, medium

- voltage, single

- phase, 20

- 45 kV 15

- 833 (DL9 + DL10)/3 Dry

- type, medium

- voltage, three

- phase, 20

- 45 kV 15

- 2500 DL9 + DL10 Dry

- type, medium

- voltage, single

- phase, 46

- 95 kV 15

- 833 (DL11+DL12)/3 Dry

- type, medium

- voltage, three

- phase, 46

- 95 kV 15

- 2500 DL11 + DL12 Dry

- type, medium

- voltage, single

- phase, > 95 kV 75

- 833 DL13/3 Dry

- type, medium

- voltage, three

- phase, > 95 kV 225

- 2500 DL13

To aggregate losses from more than one design line, DOE took a shipments

- capacity weighted average of the per

- kilovolt

- ampere (kVA) transformer characteristics from the economic analysis of the design lines and applied the average per

- capa city values to the estimated capacity shipped for each equipment class. DOE’s contractor 1 provided the capacity10

- 10 shipped for each de sign line (and each equipment class)

. T he LCC analysis provided the

economic results for each design line, and DOE used the 0.75 scaling rule to estimate the re

scaled cost and loss estimates for each size category represented by each design line. Equation 10.5 provides the average loss per unit capacity of equipment class (AvgLossPerCap E C), as derived from the average loss per unit capacity for a design line:

AvgLossPerCap EC = ∑ [ AvgLossPerCap DL × MS DL ] DL ∑ MS DL DL � Eq. 10.5

where:

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

DL = the capacity market share of the design line.

Equation 10.5 sums those design lines that constitute a n equipment class.

The AvgLossPerCap E C

10.2.2.3 Root Mean Square Loading represents the average loss per unit capacity of the transformer

load. For no

- load losses, no more adjustment is needed; for load losses, however, 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.

Energy losses in transformers follow the RMS load, not the arithmetic average load. DOE calculated the RMS loading as the RMS of the transformer load, divided by the transformer rated capacity, multiplied by the power factor. (As explained in Chapter 6, while DOE’s method for analysis can derive results for varying power factors, for the analysis presented here DOE set the power factor to the value of one.) DOE used the average national RMS loading for each design line as calculated in the LCC analysis. These values range between 26.2 % and 41.9 % for the different design lines.

10.2.2.4 Load Growth

The fractional load growth is the fraction by which the load has increased since a transformer was installed. DOE investigated load growth as a sensitivity. Load growth occurs when new equipment, new appliances, or additional activities increase the energ y loads on the circuits served by distribution transformers. Load growth has the impact of increasing the load losses relative to the losses that DOE estimated to have occurred during the first year of

i nstallation

.

DOE calculated the fractional load gro wth from an estimated load growth 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 l oad that can occur without overloading the transformer beyond a reasonable point. When overloading does occur, the transformer is assumed to be relocated and10

- 11 installed in a new location with the same initial peak loading as when originally installed. 6 See Institute of Electrical and Electronics Engineers, Inc. (IEEE) Std C57.91

- 1995 7 for details on permissible overloading of mineral

- oil

- immersed transformers. Since IEEE does not report data on permissible overloading of dry

- type units, DOE used the same values for both liquid

immersed a nd dry

- type transformers. The age of the transformer at which the load switches to initial peak load is given by Equation 10.6:

age Max = ln ( 1 + LGRMax ) ln ( 1 + LGR ) � Eq. 10.6

where:

age Max

LGR = the annual load growth rate (%). = the maximum age of transformer after which time the load switches to initial peak load (years), and

Thus, the equation for the load growth as a function of the age of the transformer is as follows:

LGrwth(age) = (1 − LGR) (age) − 1 Eq. 10.7

for age < age Max , and

LGr wth(age) = (1 − LGR) (age −ageMax) − 1 Eq. 10.8

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 RMS loading estimate for the affected stock. The mathematical equation for this adjustment is as follows:

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

− Std

_ year

age = 1 / Aff

_ Stock ( y ) Eq. 10.9

where LAdjust(y) is the load adjustment factor in year y . All other variables have been defined in previous equations.

DOE used a load adjustment factor to calculate an adjusted RMS loading that

inco rporates load growth into the unit energy consumption, as described in section 10.2.2.6

.10

- 12 10.2.2.5 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 represents that portion of the transformer stock that is potentially impacted by a standard. It therefore consists of those transformers in the stock that are purchased in or after the year the standard has taken effect, as described by the following equation:

Af f Stock ( y ) = S h ip ( y ) + ∑ Stock ( age ) y

− St d year

age = 1 Eq. 10.10

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.

10.2.2.6 Unit Energy Consumption

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

and the site

- to

- source conversion factor equals the annual 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 the effective date of a standard. DOE calculated the losses per transformer as the sum of no

- l oad losses plus the load losses. It 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 effect s.

The annual unit energy consumption for affected stock of distribution transformers is given by Equation 10.11:

UEC(y) = E NL + E LL × [RMS × LAdjust(y)] 2 Eq. 10.11

where:

E NL E = rated no

- load losses per kVA capacity,

LL RMS = root mean square, and = rated load losses per kVA capacity,

LA djust(y) = loading adjustment factor for year y.

Once 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

- 13 10.2.2.7 Electricity Site

- to

- Source 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 Btu). Since t he NES estimates the change in energy use of the resource (e.g., 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 its use

— the inst alled 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 different fuels and the efficiency of different energy conversion processes. The

annual conversion factor values are the U.S. average s for electricity generation for both peak and

base load. 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

these different rates because load losses are higher during transformer peak loads while no

- load

losses occur at all times. DOE obtained these conve rsion factors using a variant of the NEMS,

called NEMS

- BT. a Table 10.2.2 presents the average annual conversion factors DOE used.

Table 10.2.2 Average Site

- to

- Source Conversion Factors for No

- Load Losses and Load

Losses

Year For No

- Load Losses For Load Losses

2015 1.906 2.582

2016 1.906 2.577

2017 1.900 2.563

2018 1.896 2.555

2019 1.892 2.544

2020 1.885 2.540

2021 1.887 2.545

2022 1.890 2.531

2023 1.888 2.518

2024 1.890 2.503

2025 1.892 2.482

2026 1.890 2.455

2027 1.893 2.437

2028 1.901 2.418

2029 1.891 2.403

2030 1.902 2.396

2031 1.901 2.388

2032 1.907 2.381

2033 1.895 2.375

a For more information on NEMS, refer to DOE’s EIA documentation. A useful summary is National Energy Modeling System: An Overview 2003.5 DOE/EIA approves use of the name NEMS to describe only an official

versio n 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

- 14 2034 1.896 2.369

2035 1.904 2.365

2036

- 2045 1.904 2.365

The conversion factors change over time and account for the displacement of generating sources. The NES spreadsheet model includes the conversion factors for each year of the projection. DOE 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 summ ation of energy savings over the forecast period complete the calculations needed to estimate the NES.

The next section of the chapter (section 10.3) describes the technical details of the NPV

calculation. The results section (section 10.4) presents the NE S and NPV results from the national impact spreadsheet.

10.3 NET PRESENT VALUE

DOE estimated the national financial impact on consumers from the imposition of new energy efficiency standards using a national NPV accounting component in the national impact

spr eadsheet. DOE combined the output of the shipments model with energy savings and financial data from the LCC to calculate an annual stream of costs and benefits resulting from candidate distribution transformer energy efficiency standards. It discounted th is time series to the year

20 10 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 candidate standard level. Like the NES, the NPV calculation started with tran sformer shipments and transformer stocks, estimates of which are outputs from the shipments model. DOE then obtained estimates of transformer first costs, losses, and average marginal electricity costs from the LCC analysis. It calculated the amount spent on transformer purchases and installation, and 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 for each year, for both a base ca se and a standards case. Over time

, in the standards case, more expensive, 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 t he standards case relative to the base case, while the equipment costs increase.

DOE discounted purchases, expenses, and operating costs for transformers using a simple national average discount factor. The discount factor converts a future expense or be nefit to a present value. The difference in present value of all expenses and benefits between the base case and standards scenario is the national NPV impact. DOE calculated the NPV impact from transformers that were purchased between the effective date o f the standard and 2045 , inclusive, to calculate the total NPV impact from purchases during the forecast period. Mathematically,10

- 15 NPV is the value in the present time of a time series of costs and savings, described by the equation:

NPV = PVS − PVC Eq. 10.12

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:

PVS = ∑ � OC Base Cap � ( y ) × OC Std Cap � ( y ) � × Aff

_ Stock ( y ) × Discount Factor ( y ) 21053
y = Std

_ year Eq. 10.13

where:

OC Base

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

y ear y ,

y = the year (from effective date of the trial standard to the year when units purchased in 2045 retire), and Discount Factor(y) = discount factor for the year y , defined in Eq. 10.14.

Discount Factor ( y ) = 1 ( 1 + Discount Rate ) ( y

− reference year ) � Eq. 10.14

where:

reference year = year 2010 , and

discount rate = the rate of discount as described i n section 10.3.2.7

.

PVC = ∑ � FC std Cap � ( y )

− FC Base Cap � ( y ) � 2105 Std

_ year × S h ip ( y ) × DiscountFactor ( y ) Eq. 10.15

where:

FC Std

Std_year = the year standards come into effect, and /Cap (y) = first cost of the transformer per unit of capacity for a candidate

standard level Std in year y , ( First cost is defined in Eq. 10.16 and

described in section 10.3.2.1. )

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

candidate standards case and a base case scenario without national standards. It discounted future costs and savings to the present.10

- 16 DOE calculated a discount factor from the discount rate and the number of years between the year to which the sum is being discounted ( 20 10 ) and the year in which the costs and savings occur. The NPV is the sum over time ( 2016

– 2104 ) of the discounted net financial savings. The following sections describe the inputs specific to the NPV calculation.

10.3.2 Net Present Value Inputs

The NPV model inputs 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 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. f irst cost ; 2. o perating cost ; 3. p eak responsibility factor ; 4. i nitial peak load ;
5. e lectricity price forecast scalar ; 6. m arginal electricity costs ; and

7. d iscount rate

.

10.3.2.1 First Cost

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

FC/C ap = (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.

In the NPV calculation, these values are obtained from the LCC calculation as the averages for specific design lines. DOE applied an adjustment factor to convert 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 incorporates the 0.75 scaling rule and the design

- line

to

- equipment

- 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 20 10 $ per kVA of rated transformer capacity.

Table 10.3.1 show s the resulting mean first costs per kVA for distribution transformers by C SL and e quipment class.10

- 17 Table 10.3.1 First Cost a

Equipment Class of Distribution Transformers by Candidate Standard Level

and Equipment Class (2010$/kVA)

Base CSL 1 CSL 2 CSL 3 CSL 4 CSL 5 CSL 6 CSL 7 Liquid

- immersed, medium

voltage, single

- phase 82.81 92.32 100.92 109.15 117.68 137.97 144.78 145.01

Liquid

- immersed, medium

voltage, three

- phase 27.54 29.94 31.40 32.36 33.18 38.60 59.22 59.22

Dry

- type, low

- voltage, single

- phase 63.90 66.64 74.94 81.15 82.92 90.75 101.59 137.04

Dry

- type, low

- voltage,

three

- phase 42.99 43.48 46.35 51.57 55.83 66.62 70.64 94.83

Dry

- type, medium

- voltage, single

- phase, 34.39 39.97 43.13 47.20 51.21 70.81 70.81 70.81

Dry

- type, medium

- voltage,

three

- phase, 28.76 33.96 35.78 38.82 41.57 58.52 58.52 58.52

Dry

- type, medium

- voltage, single

- phase, 44.88 49.53 54.15 59.53 62.78 75.16 90.25 90.25

Dry

- type, medium

- voltage,

three

- phase, 32.18 36.13 39.30 43.59 45.20 51.86 68.99 68.99

Dry

- type, medium

- voltage, single

- phase, 38.54 43.51 49.91 54.23 60.32 79.85 79.85 79.85

Dry

- type, medium

- voltage,

three

- phase, 29.81 33.65 38.60 41.94 46.65 61.75 61.75 61.75

10.3.2.2 Operating Cost

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

transformer standard. DOE used distinct costs to calculate the value of different types of losses

and peak capacity savings. Potential load growth also requires a load growth adjustment factor. Peak loading, peak load coincidence, and average loading require additional factors to characterize load losses. Finally, DOE used an electricity price forecast scalar to charac terize future trends in electricity prices consistent with the AEO20 10 forecast.

DOE assumed zero incremental maintenance cost in calculating the transformer operating costs. It calculated annual operating costs using the following formula to capture the diversity of potential factors that can affect these costs:

OC/Cap = EPFS(y) × (E NL × (NLLMCC + 8760 × NLLMEC) + E LL × (LAdjust(y)) × (PRF × PL2 × LLMCC + 876 0 × RMS2 × LLMEC))/Cap Eq. 10.17 2

where:

OC = the operating cost,

a First Cost here includes installation cost.10

- 18 Cap = the rated capacity of the transformer, EPFS(y) = the electricity price forecast scalar for year y,

E NL NLLMCC = the no

- load loss marginal cost of capacity, = the no

- load losses at rated load,

NLLMEC = the no

- load loss marginal energy cost,

E LL LAdjust(y) = the load growth adjustment factor in year y, = the load losses at rated load,

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.

DOE expressed the operating costs in units of 20 10 $ per kVA of rated capacity. As in the NES calculation (see sections 10.2.2.1 and 10.2.2.2), DOE also applied an adjustment fa ctor to incorporate the 0.75 scaling rule to E NL and E LL , to convert from design line data to equipment

class estimates.

The following four sections explain the inputs of the operating cost equation that are not explained in the NES section.

10.3.2.3 Peak Respons ibility Factor

The transformer peak responsibility factor (PRF) is the fraction of the transformer peak that is coincident with the system peak, calculated by taking the square of the ratio of the transformer load at the time of the customer peak load to the transformer peak load. In combination with the initial peak loading, the PRF is necessary for estimating the capacity cost impacts of transformer load losses. DOE used the average PRF from the hourly and monthly load analysis for the liquid

- immersed an d dry

- type transformers, respectively, as reported in the LCC analysis. Table 10.3.2 presents the PRFs used in the analysis for ten equipment classes.

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 0.48 0.48 0.36 0.36 0.46 0.54 0.51 0.56 0.56 0.56

10.3.2.4 Initial Peak Load

The initial peak loading is the annual per

- unit peak load on the transformer during the first year of operation. This factor, in combination with the PRF, is necessary for calculating capacity cost impacts from transformer load losses. The initial peak load is estimated as a percentage of the rated peak load of the transformer. The Institute of Electrical and Electronics Engineers Draft Guide for Distribution Transformer Loss Evaluation 6 defines 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, DOE characterized a range of possible initial peak loads by defining a10

- 19 distribution of initial peak loads. Chapter 6, sections 6.2.3.3 and 6.3.3.3, provide further description of DOE’s method. Table 10.3.3 presents the initial peak loadings used in the analysis

for the 10 equipment classes.

Table 10.3.3 Initial Peak Loading by Product Class

EC 1 EC 2 EC 3 EC 4 EC 5 EC 6 EC 7 EC 8 EC 9 EC 10 Initial Peak Loading 0.88 0.88 0.80 0.79 0.85 0.85 0.81 0.80 0.80 0.80

10.3.2.5 Electricity Price Forecast Scalar

The electricity price forecast scalar converts current electricity costs into forecasted costs for the period 20 10

– 2 105 . 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 20 10 . DOE used

AEO20 10 4

10.3.2.6 Marginal Electricity Costs forecasts to obtain the electricity price forecast scalar. For the period beyond 20 3 5,

DOE used the EIA real dollar price trend from 20 25 to 20 3 5 to extrapolate the electricity price

scalar.

The characterization of four distinc t marginal electricity costs was necessary to calculate the operating costs of transformers and the financial impact of transformer efficiency standards. The four types of marginal costs 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). 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. Because no

- load losses and load losses have distinct load shapes, and

because different customers have different load shapes, costs vary both by loss type and by the equipment class of the transformer. DOE th erefore used distinct marginal energy and capacity

costs for no

- load losses and load losses for each transformer equipment class. No transformer size scaling is necessary for the marginal costs, although DOE needed to apply the design

- line

to

- equipment

- cla ss mapping described in section 10.2.2.2 to convert the design line output from

the LCC to equipment class information for the NPV calculation. DOE calculated capacity costs

in units of 20 08 $/kW/year, and energy costs in units of 20 0 8 $/kWh. Table 10.3. 4 summarizes the four marginal costs for the 10 equipment classes

.

Table 10.3.4 Marginal Energy and Demand 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 0.049 0.060 0.060 0.060 0.060 0.060 0.060 0.060 0.060

LL 0.073 0.054 0.059 0.059 0.059 0.059 0.059 0.059 0.059 0.059 Marginal Demand 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 498.59 498.59 142.62 142.62 142.62 142.62 142.62 142.62 142.62 142.62

LL 197.66 197.66 104.25 104.68 104.25 104.25 104.25 104.25 104.25 104.2510

- 20 10.3.2.7 Discount Rate

The discount rate expresses the time value of money and is the final input to the NPV

calculation. DOE used real discount rates of 3 percent and 7 percent , as established by the U.S. Office of Management and Budget (OMB) guidelines on regulatory analysis. 8

10.4 RESULTS The discount rates

DOE used in the LCC are distinct from those it used in the NPV calculations, in that the NPV discount 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 utiliti es and commercial and

industrial entities.

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

Table 10.4.1 presents the NES and NPV results from the NES spreadsheet model for CSL 1 through CSL 7

. It should be reiterated that, currently, the NES spreadsheet model uses discrete point values rather than a distribution of values for all inputs.

Table 10.4.1 Summary of Cumulative National Energy Saving s ( 2016

– 2045 ) and Net Present Value ( 2016

– 2104 ) Impact

Analysis Discount

Rate (%) Candidate Standard Level

1 2 3 4 5 6 7

Liquid

- Immersed
Cumulative Source Savings 2045 (Quads) 0.63 1.39 1.70 1.94 2.29 2.52 2.53

Net Present Value (B 2010$) 3 5.31 14.08 15.36 15.28 8.94

- 3.49

- 3.57

7 0.46 2.43 1.81 0.76

- 4.10

- 11.69

- 11.73

Dry

- Type
Cumulative Source Savings 2045 (Quads) 0.27 0.65 1.02 1.33 1.84 2.11 2.40

Net Present Value (B 2010$) 3 2.17 4.92 6.62 8.13 8.60 8.25 2.89

7 0.56 1.14 1.20 1.33 0.47

- 0.31

- 3.86

10.4.1.2 Liquid

- Immersed Results

Figure 10.4.1 illustrates the typical pattern of primary energy savings and costs resulting from standards for liquid

- immersed transformers over time. The figure shows the nature of net savings for all seven CSLs relative to the base case. In this figure, the levels are ordered from lowest to highest energy savings.10

- 21 Figure 10.4.1 Liquid

- Immersed Distribution Transformers: National Energy Savings and Net Present Value Impacts

10.4.1.3 Dry

- Type Results

Figure 10.4.2 shows the typical pattern of national savings and costs resulting from standards for dry

- type transformers over time. Again, the figure shows the nature of net savings for six dry

- type transformer C SLs relative to the base case.

Figure 10.4.2 D ry

- Type Distribution Transformers: National Energy Savings and Net Present Value Impacts

The national impact spreadsheet is available as an Excel file on the DOE website: www.eere.energy.gov/buildings/appliance_standards/commercial/distribution_transformers.html

. Instructions for using the spreadsheet are in Appendix 10A of this TSD. - 15.0 - 10.0 - 5.0 0.0 5.0 10.0 15.0 20.0

0.0 0.5 1.0 1.5 2.0 2.5 3.0

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

Candidate Standard Levels Cumulative Source Energy Savings and NPV for Liquid

- Immersed Units

Cumulative Source Savings 2044 (Quads) Net Present Value at 3% Discount Rate ($Billions)

Net Present Value at 7% Discount Rate ($Billions)

- 6.0 - 4.0 - 2.0 0.0 2.0 4.0 6.0 8.0 10.0

0.0 0.5 1.0 1.5 2.0 2.5 3.0

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

Candidate Standard Levels Cumulative Source Energy Savings and NPV for Dry

- Type Units

Cumulative Source Savings 2044 (Quads) Net Present Value at 3% Discount Rate ($Billions)

Net Present Value at 7% Discount Rate ($Billions)10

- 22 REFERENCES

1. Hopkinson, P. Distribution Transformer Market Shipment Estimates for 2009 . (Washington DC., 2010).

2. Bureau of Economic Analysis Industry Economic Accounts Information Guide. Annual Industry Accounts. Gross Domestic Product (GDP) by Industry. (2005).

3. U.S. Departme nt of Energy

- Energy Information Administration Annual Energy Review 2009, Chapter 8: Electricity, Table 8.9 Electricity End Use, 1949

- 2009 . (U.S. Department of Energy: Washington DC, 2010).

4. U.S. Department of Energy

– Energy Information Administration Annual Energy Outlook 2010: With Projections Through 2035 . (U.S. Department of Energy: Washington DC, 2010).

5. Energy Information Administration

- Office of Integrated Analysis and Forecasting The National Energy Modeling System . (U.S. Department of Ene rgy: Washington DC, 2009).at <http://www.eia.doe.gov/oiaf/aeo/overview/>

6. Institute of Electrical and Electronics Engineers Inc. Draft Guide for Distribution Transformer Loss Evaluation. (2001).

7. Institute of Electrical and Electronic Engineers Inc. G uide for Loading Mineral Oil

- Immersed Transformers. (1995).

8. U.S. Office of Management and Budget Circular A

- 4: Regulatory Analysis. (2003).