dt_nopr_tsd_chp8_092311 DRAFT 8

- i CHAPTER 8. LIFE

- CYCLE COST AND PAYBACK PERIOD ANALYSES

TABLE OF CO NTENTS

8.1 INTRODUCTION

................................ ................................ ................................ ........... 8

- 1

8.1.1 General Approach to Analyses

................................ ................................ ........................ 8

- 1

8.1.2 Baseline Scenario

................................ ................................ ................................ ............. 8

- 2

8.1.3 To tal Owning Cost

................................ ................................ ................................ ........... 8

- 2

8.2 LIFE

- CYCLE COST ANALYSIS METHOD

................................ ................................ . 8

- 3

8.2.1 Definition

................................ ................................ ................................ ......................... 8

- 3

8.2.2 Key Step s in Life

- Cycle Cost Analysis

................................ ................................ ........... 8

- 3

8.2.2.1 Step 1: Select Parameters A and B

................................ ................................ 8

- 5

8.2.2.2 Step 2: Select Designs that Meet a Chosen Candidate Standard Level

......... 8

- 5

8.2.2.3 Step 3: Select Load and Price Profile

................................ ............................ 8

- 6

8.2.2.4 Step 4: Calculate Cost of Loss es

................................ ................................ .... 8

- 6

8.2.2.5 Step 5: Project Losses and Costs into the Future

................................ ........... 8

- 6

8.2.2.6 Step 6: Select Discount Rate

................................ ................................ .......... 8

- 7

8.2.2.7 Step 7: Calculate Present Value of Future Cost of Losses

............................. 8

- 7

8.2.2.8 Step 8: Report Results

................................ ................................ .................... 8

- 7

8.2.2.9 Step 9: Repeat Process and Report Results

................................ .................... 8

- 7

8.3 INPUTS TO LIFE

- CYCLE COST ANALYSIS

................................ ............................. 8

- 7

8.3.1 A and B Transformer Selection Parameters

................................ ................................ ..... 8

- 8

8.3.1.1 A and B Parameter Selection for Liquid

- Immer sed Transformers

................ 8

- 9

8.3.1.2 A and B Parameter Selection for Dry

- Type Transformers

.......................... 8

- 11

8.3.2 Database of Transformer Designs

................................ ................................ .................. 8

- 13

8.3.3 Markup and Installation Costs

................................ ................................ ....................... 8

- 13

8.3.3.1 Projection of Future Product Prices

................................ ............................. 8

- 13

8.3.4 Transformer Loading

................................ ................................ ................................ ..... 8

- 15

8.3.5 Electricity Pric e Analysis

................................ ................................ ............................... 8

- 15

8.3.5.1 Hourly Marginal Electricity Price Model for Liquid

- Immersed

Transformers

................................ ................................ ................................ 8

- 16

8.3.5.2 Monthly Marginal Electricity Price Model for Dry

- Type Transformers

..... 8

- 19

8.3.6 Trends in Load Growth

................................ ................................ ................................ .. 8

- 20

8.3.7 Electricity Cost and Price Trends

................................ ................................ .................. 8

- 20

8.3.8 Discount Rate

................................ ................................ ................................ ................. 8

- 21

8.3.9 Effective Date of Standard

................................ ................................ ............................. 8

- 26

8.3.10 Transformer Service Life

................................ ................................ ............................... 8

- 26

8.3.11 Maintenance Costs

................................ ................................ ................................ ......... 8

- 27

8.3.12 Power Factor

................................ ................................ ................................ .................. 8

- 27

8.3.13 Def ault Scenario

................................ ................................ ................................ ............. 8

- 27

8.4 RESULTS OF LIFE

- CYCLE COST ANALYSIS

................................ ........................ 8

- 27

8.4.2 Results for Design Line 1

................................ ................................ .............................. 8

- 30

8.4.3 Results for Design Line 2

................................ ................................ .............................. 8

- 31

8.4.4 Results for Design Line 3

................................ ................................ .............................. 8

- 31dt_nopr_tsd_chp8_092311 DRAFT 8

- ii 8.4.5 Results for Design Line 4

................................ ................................ .............................. 8

- 32

8.4.6 Results for Design Line 5

................................ ................................ .............................. 8

- 32

8.4.7 Results for Design Line 6

................................ ................................ .............................. 8

- 33

8.4.8 Results for Design Line 7

................................ ................................ .............................. 8

- 33

8.4.9 Results for Design Line 8

................................ ................................ .............................. 8

- 34

8.4.10 Results for Design Line 9

................................ ................................ .............................. 8

- 34

8.4.11 Results for Design Line 10

................................ ................................ ............................ 8

- 35

8.4.12 Results for Design Line 11

................................ ................................ ............................ 8

- 35

8.4.13 Results for Design Line 12

................................ ................................ ............................ 8

- 36

8.4.14 Results for Design Line 13A

................................ ................................ .......................... 8

- 36

8.4.15 Results for Design Line 13B

................................ ................................ .......................... 8

- 37

8.5 LIFE

- CYCLE COST SENSITIVI TY ANALYSIS

................................ ....................... 8

- 37

8.5.1 Sensitivity Results for Design Line 1

................................ ................................ ............ 8

- 38

8.5.2 Sensitivity Results for Design Line 7

................................ ................................ ............ 8

- 40

8.5.3 Sensitivity Results for Design Line 12

................................ ................................ .......... 8

- 42

8.6 PAYBACK PERIOD

................................ ................................ ................................ ..... 8

- 44

8.6.1 Definition

................................ ................................ ................................ ....................... 8

- 44

8.6.2 Inputs to Payback Period

................................ ................................ ............................... 8

- 44

8.6.3 Issues Regarding Baseline Scenario

................................ ................................ .............. 8

- 45

8.6.4 Results of Payback Period Analysis

................................ ................................ .............. 8

- 46

8.6.5 Results for Design Line 1

................................ ................................ .............................. 8

- 46

8.6.6 Results for Design Line 2

................................ ................................ .............................. 8

- 47

8.6.7 Results for Design Line 3

................................ ................................ .............................. 8

- 47

8.6.8 Results for Design Line 4

................................ ................................ .............................. 8

- 48

8.6.9 Results for Design Line 5

................................ ................................ .............................. 8

- 48

8.6.10 Results for Design Line 6

................................ ................................ .............................. 8

- 48

8.6.11 Results for Design Line 7

................................ ................................ .............................. 8

- 49

8.6.12 Results for Design Line 8

................................ ................................ .............................. 8

- 49

8.6.13 Results for Design Line 9

................................ ................................ .............................. 8

- 50

8.6.14 Results for Design Line 10

................................ ................................ ............................ 8

- 50

8.6.15 Results for Design Line 11

................................ ................................ ............................ 8

- 51

8.6.16 Results for Design Line 12

................................ ................................ ............................ 8

- 51

8.6.17 Results for Design Line 13A

................................ ................................ .......................... 8

- 52

8.6.18 Results for Design Line 13B

................................ ................................ .......................... 8

- 52

8.7 REBUTTABLE PRESUMPTI ON

................................ ................................ ................. 8

- 53

LIST OF TABLES

Table 8.3.1 A Parameter Model and Historical Data

................................ ............................ 8

- 10

Table 8. 3.2 A and B Parameter Evaluation Scenarios

................................ .......................... 8

- 12

Table 8.3.3 Transmission and Distribution Loss Factors

................................ ...................... 8

- 17

Table 8.3.4 Generation Capacity Costs

................................ ................................ ................. 8

- 17

Table 8.3.5 Capacity Market Auction Results

................................ ................................ ...... 8

- 18dt_nopr_tsd_chp8_092311 DRAFT 8

- iii Table 8.3.6 Average Seasonal Marginal Energy and Demand Prices by Census

Division

................................ ................................ ................................ .............. 8

- 20

Table 8.3.7 Typical Owners of Various Types of Transformers

................................ .......... 8

- 23

Table 8.3.8 Variables Used to Estimate Discount Rates for the C&I Sector

........................ 8

- 24

Table 8.3.9 Real Discount Rates by Transformer Ownership Category

............................... 8

- 25

Table 8.3.10 Transformer Ownership by Design Line

................................ ........................... 8

- 26

Table 8.4.1 Candidate Standard Levels Evaluated for Each Design Line

............................ 8

- 28

Table 8.4.2 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 1

...... 8

- 30

Table 8.4.3 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 2

...... 8

- 31

Table 8.4.4 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 3

...... 8

- 31

Table 8.4.5 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 4

...... 8

- 32

Table 8.4.6 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 5

...... 8

- 32

Table 8.4.7 Results of Life

- Cycle Cost Analysis: Repre sentative Unit, Design Line 6

...... 8

- 33

Table 8.4.8 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 7

...... 8

- 33

Table 8.4.9 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 8

...... 8

- 34

Table 8.4.10 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 9

...... 8

- 34

Table 8.4.11 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 10

.... 8

- 35

Table 8.4.12 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 11

.... 8

- 35

Table 8.4.13 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 12

.... 8

- 36

Table 8.4.14 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line

13A

................................ ................................ ................................ .................... 8

- 36

Table 8.4. 15 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line

13B

................................ ................................ ................................ ..................... 8

- 37

Table 8.5.1 Effects of Changed Variables on Life

- C ycle Cost Savings for Representative Unit, Design Line 1

................................ ................................ ... 8

- 39

Table 8.5.2 Effects of Changed Variables on Life

- Cycle Cost Savings for Representative Unit, Design Line 7

................................ ................................ ... 8

- 41

Table 8.5.3 Effects of Changed Variables on Life

- Cycle Cost Savings (2010$) for Represen tative Unit, Design Line 12

................................ ................................ . 8

- 43

Table 8.6.1 Possible ΔFC and ΔOC Combinations for Payback Period Analysis

................ 8

- 46

Table 8.6.2 Results of Payback Period Analysis: Representative Unit, Design Line 1

........ 8

- 46

Table 8.6.3 Results of Payback Period Analysis: Representative Unit, Design Line 2

........ 8

- 47

Table 8.6.4 Results of Payback Period Analysis: Representative Unit, Design Line 3

........ 8

- 47

Table 8.6.5 Results of Payback Period Analysis: Representative Unit, Design Line 4

........ 8

- 48

Table 8.6.6 Results of Payback Period Analysis: Representative Unit, Design Line 5

........ 8

- 48

Table 8.6.7 Results of Payback Period Analysis: Representative Unit, Design Line 6

........ 8

- 49

Table 8.6.8 Results of Payback Period Analysis: Representative Unit, Design Line 7

........ 8

- 49

Table 8.6.9 Results of Payback Period Analysis: Representative Unit, Design Line 8

........ 8

- 50

Table 8.6.10 Results of Payback Period Analysis: Representative Unit, Design Line 9

........ 8

- 50

Table 8.6.11 Results of Payback Period Analysis: Representative Unit, Design Line 10

...... 8

- 50

Table 8.6.12 Results of Payback Period Analysis: Representative Unit, Design Line 11

...... 8

- 51

Table 8.6.13 Results of Payback Period Analysis: Representative Unit, Design Line 12

...... 8

- 51

Table 8.6.14 Results of Payback Period Analysis: Representative Unit, Design Line

13A

................................ ................................ ................................ ..................... 8

- 52

Table 8.6.15 Results of Payback Period Analysis: Representative Unit, Design Line

13B

................................ ................................ ................................ ..................... 8

- 52dt_nopr_tsd_chp8_092311 DRAFT 8

- iv Table 8.7.1 Average Transformer Efficiency %

................................ ................................ ... 8

- 55

Table 8.7.2 Average Transformer Installed Cost ($2010)

................................ .................... 8

- 55

Table 8.7.3 First

- Year Operating Cost for Rebuttable Presumption Based on DOE Test

Procedure %

................................ ................................ ................................ ....... 8

- 56

Table 8.7.4 Payback Period for Rebuttable Presumption

................................ ..................... 8

- 57

LIST OF FIGURE S

Figure 8.2.1 Flowchart of Spreadsheet Model for Calculating Transformer Life

- Cycle

Cost

................................ ................................ ................................ ...................... 8

- 4 Figure 8.3.1 Cumulative Distribution of Historical A Parameter and Model A

Parameter

................................ ................................ ................................ ............. 8

- 9 Figure 8.3.2 Distributions of Load Loss (B) Values versus No

- Load Loss (A) Values for Liquid

- Immersed Transformers

................................ ................................ ... 8

- 11 Figure 8.3.3 Electricity Price Forecasts from AEO2011

................................ ........................ 8

- 21 Figure 8.4.2 Design Load Losses versus No

- Load Losses in the Base Case and Candidate Standard Level 1 for Design Line 1

................................ .................. 8

- 29 Figure 8.4.3 Distribution of Life

- Cycle Cost Results for Design Line 2, Candidate

Standard Level 2

................................ ................................ ................................ 8

- 30 Figure 8.5.1 Average Life

- Cycle Cost Savings (2010$) by Scenario for Design Line 1

....... 8

- 40 Figure 8.5.2 Average Life

- Cycle Cost Savings (2010$) by Scenario for Design Line 7

....... 8

- 42 Figure 8.5.3 Average Life

- Cycle Cost Savings (2010$) by Scenario for Design Line 13

..... 8

- 43 Figure 8.6.1 Distribution of Payback Period Results for Design Line 2, Candidate

Standard Level 2

................................ ................................ ................................ 8

- 53dt_nopr_tsd_chp8_092311 DRAFT 8

- 1 CHAPTER 8. LIFE

- CYCLE COST AND PAYBA CK PERIOD ANALYSES

8.1 INTRODUCTION

This chapter of the technical support document (TSD) prepared in support of potential energy efficiency standards for distribution transformers presents DOE’s life

- cycle cost (LCC) and payback period (PBP) analyses. It describes the method DOE used for ana lyzing the economic impacts of possible standards on c ustomers . The effect of standards on customers includes a change in operating expense (usually a decrease) and a change in purchase price (usually an increase). The LCC and PBP analyses produce two basi c outputs to describe the

effect of standards on customers.

**•** LCC is the total (discounted) cost that a customer pays over the lifetime of the equipment, including purchase price, installation cost, and operating expenses.

**•** PBP measures the amount of time it takes customers to recover the estimated higher purchase price of more energy efficient equipment through lower operating costs.

This chapter presents inputs and results for the LCC and PBP analyses, as well as key

varia bles, assumptions, and computational equations. DOE performed the calculations discussed here using a series of Microsoft Excel spreadsheets, which are accessible on DOE's website ( http://www.eere.energy.gov/buildings/appliance_standards/commercial/
distribution_transformers.html ). Appendix 8 A contains details and instructions for using the spreadsheets. There are five appendices to this chapt er , among which are appendix 8C , which

present s a complete set of analytical results; a ppendix 8B , which discusses uncertainty and variability; and a ppendix 8D , which contains a complete set of sensitivity results for transformer design lines 1

, 7

, and 1 2

.

8.1.1 General Approach to Analyses

Recognizing that each transformer customer is unique, DOE calculated the LCC and PBP for a representative sample (a distribution) of individual customers who purchase individual transformers. In this manner, DOE’s analyses exp licitly recognized that there is both variability and uncertainty in the inputs. DOE developed the LCC model using Excel spreadsheets combined with Crystal Ball, a commercially available add

- in program. DOE used Monte Carlo

simulations to model the distrib utions of inputs. The Monte Carlo process statistically captures input variability and distribution without testing all possible input combinations. The results are expressed as the number of transformers that engender economic impacts of varying magnitude s. A ppendix 8

- B provides a detailed explanation of the Monte Carlo simulation process and the use of probability distributions in th e analyses

.

The LCC results are displayed as distributions of impacts compared to baseline

conditions (no new standards)

. The tabular results presented later in this chapter are based on 10,000 samples per Monte Carlo simulation run

.dt_nopr_tsd_chp8_092311 DRAFT 8

- 2 DOE developed two approaches for the LCC calculations: one for liquid

- immersed

transformers

, and one for low

- voltage and medium

- voltage, dry

- ty pe transformers. Because most
owners of liquid

- immersed transformers are utilities, the LCC calculations for liquid

- immersed

transformers used utility marginal costs and distribution markups that do not include wholesaler

or contractor markup s . In contrast , because most owners of dry

- type transformers are commercial and industrial enterprises, DOE used monthly marginal electricity costs and complete distribution markups for calculating the LCC of dry

- type transformer s . For simplicity, DOE used only one type of LCC calculation for each design line of transformer, based on the type of owner that was the majority in that category.

8.1.2 Baseline Scenario

In developing appliance standards, DOE used the existing standard ( 10 CFR Part 43 ) as a baseline from which it calculates the impact of any candidate standard level

. This approach focused on the mix of selection criteria customers are known to use when purchasing

transformers. Those criteria include first cost and what is known in the transformer industry as

total owning cost (TOC), a criterion some customers use in place of first cost. Purchasers of distribution transformers, especially in the utility sector, have long used TOC to determine which transformers to purchase. 1

, 2

To establish the baseline scenario for the L CC , DOE used distributions of efficiencies and an estimated percent of transformers currently being purchased using the TOC method. That scenario represents the range of transformer costs and efficiencies that transformer purchasers likely would face witho ut national energy efficiency standards in place.

8.1.3 Total Owning Cost

The utility industry developed TOC evaluation as an easy

- to

- use tool to reflect the unique financial environment faced by each transformer purchaser. To express variation in such factors

a s the cost s of electric energy

, energy capacity

, and financing, the utility industry developed a range of factors, called A and B values, to use in their evaluation s. A and B are the equivalent

first costs of a transformer’s no

- load losses and load losses

, respectively, in dollars per watt ($/ W ). No

- load losses refer to the core losses that remain roughly constant after the transformer is energized; load losses are the coil losses that vary roughly with the square of the load on the

transformer.

After assign ing an economic value to the A and B parameters of transformer losses, purchasers add those costs to the first cost of acquiring the transformer, thereby deriving TOC. Throughout the LCC analysis, DOE expresses monetary values in units of year 2010 real dollars (2010$). The equation for calculating transformer TOC is:dt_nopr_tsd_chp8_092311 DRAFT 8

- 3 T

OC = FC + (A × NLL) + (B × LL)

.

Where :

FC = first cost of acquiring the transformer, including purchase price and installation cost ( 2010 $);

A = the no

- load loss valuation parameter in dollars per watt ($/W );

NLL = the no

- load loss at nameplate load (W );

B = the load loss valuation parameter ($/W ); and

LL = the load loss at nameplate load (W).

8.2 LIFE

- CYCLE COST ANALYSIS METHOD

The following sections present the LCC equation and define its terms, then describe the

nine key steps DOE used in performing the LC C for distribution transformers.

8.2.1 Definition

The LCC equation serves as t he basis for both the LCC analysis and the LCC spreadsheet model. The LCC equation reflects both t he first cost of a transformer and the present value of the operating costs throughout the service life of th at transformer. The LCC equation is:

LCC = FC + ∑ � OC

n ( 1

+

Drate )

n � �

Lifetime

1 .

Where :

FC = the first cost (2010 $);

n = the index for the year of operation (yr ); Lifetime = the service life of the transformer ; OC

n = the operating cost in year n , including the value of the lo sses and maintenance costs (2010 $/yr ); and

Drate = the discount rate applied to the calculation (%).

8.2.2 Key Steps in Lif e

- Cycle Cost Analysis

Although the LCC relies on a simple equation, DOE's LCC spreadsheet model account s for the dynamic nature of numerous inputs throughout the service life of a transformer. A simplified flowchart ( Figure 8.2.1 ) illustrates the key steps implemented in the LCC spreadsheet:

the primary inputs, the key computational steps, and the important output s. The LCC spreadsheet

are available as an Excel file s on the DOE website at http://www.eere.energy.gov/buildings/appliance_standards/commercia l/distribution_transformer

s.html

.dt_nopr_tsd_chp8_092311 DRAFT 8

- 4 Figure 8.2.1 Flowchart of Spreadsheet Model for Calculating

Transformer Life

- Cycle Cost

Sections 8.2.2.1 through 8.2.2.11 describe the analytical steps of the LCC model shown in the flowchart. Following this description , this chapter presents the specific inputs that DOE developed and then used in the LCC model for this rulemaking (section 8.3) . Next, the chapter presents the results of the LCC model runs for the various design lines (section 8.4) , and the key

sensitivities to those results (section 8. 5 )

.dt_nopr_tsd_chp8_092311 DRAFT 8

- 5 The calculation of LCC determin es the financial impact of the imposition of energy efficiency standards for distribution transformers from the perspective of the c ustomer , or the owner of the transformer. Several types of information are necessary for th e calculation: the first cost of transformers with and without standards, operating costs of transformers with and without standards, the year the standard would become effective, and the lifetime of transformers.

Section 8. 3 explains in more detail DOE’s inputs to the LCC

.

8.2.2.1 Step 1: Select Parameters A and B

The spreadsheet user s elect s customer choice of A and B parameters from the choices on

the A & B Dist worksheet. Th i s step establish es the current environment for the purc hasing decision. For liquid

- immersed transformers , DOE assumed that 50 percent are purchased based

on lowest first cost and 50 percent are purchased using the TOC evaluation. 3

When deciding on which dry

- type transformers to purchase, c ommercial and industrial (C&I) entities also may use an evaluation based on parameters A and B. Although C&I purchasers use a different analytic process for determining A and B values from that used by electric utilities, the fundamental meanings of A and B are the same for both groups of purchasers.

The LCC spreadsheet uses two different models of A and B to simulate the two different transformer purchase decisions

. One model is used for a ll liquid

- immersed transformer design lines, and a different model for dry

- type design lines. The specific input s to the two scenarios are given in section 8.3 of this TSD chapter, as well as in the A & B Dist worksheet of the LCC spreadsheets for liquid

- immersed and the Demand and Usage worksheet for dry

- type units

. These scenarios can be selected using the “Transformer Customer A’s and B’s” pull

- down menu

on the Summary worksheet. Step 2 below explains the application of the A and B distributions

when selecting transformer designs.

8.2.2.2 Step 2: Select Designs that Meet a Chosen Candidate Standard Level

Step 2 a : The spreadsheet model selects a candidate standard level (CSL) and its

associated transformer designs to evaluate

. DOE developed as many as seven CSL s for each design line based on information obtained from the engineering analysis (see chapter 5 )

. The engineering analysis yielded a cost

- efficiency relationship in the form of manufacturer selling prices, no

- load losses, and load losses for a range of realistic transformer designs. This set of data provided the LC C model with a distribution of transformer design choices. ( T he Design

Table worksheet provides a condensed version of the engineering analysis output.) After the user

chooses a CSL , the spreadsheet selects from its database of designs the subset of design s that satisfy the selected CSL and another set of designs that satisfy the baseline scenario.

In addition to the economic value of load and no

- load losses, other factors may affect design selection. DOE accounted for such factors by adding a random facto r to the transformer’s

first cost. By incorporating this factor, DOE captured the range of typical real

- world variation in

the first cost of a transformer. DOE modeled this random cost factor as a uniformly distributed

random number that can either increas e or decrease the first cost of the transformer by as muchdt_nopr_tsd_chp8_092311 DRAFT 8

- 6 as 15 percent. The spreadsheet selects the transformer design that has the lowest TOC (including the random cost factor) for the customer. For each iteration cycle, a design is chosen based on

dist ributions of A and B parameters from Step 1.

Step 2b : The spreadsheet model c alculate s markup and installation costs. For liquid

immersed transformers, which typically are purchased directly by utilities from manufacturer representatives, DOE considered the transformer purchase price to be the manufacturer selling price plus a distributor markup and sales tax. It added installation costs separately. For dry

- type
transformer s, the distribution channel includes various intermediaries who add their own costs to the manufacturer selling price. Th o se costs include a manufacturer markup, distributor markup, contractor markup, installation costs, and sales tax. For this step k ey in puts include markup and

installation costs . DOE presents its specific values for those inputs in chapter 6 of this TSD

.

8.2.2.3 Step 3: Select Load and Price Profile

The spreadsheet model dynamically selects a sample transformer load profile from

distributions derived from available data. For liquid

- immersed transformers, DOE developed an hourly transformer load simulation model to capture the dynamics and economics of transformer loads. DOE then used the marginal cost for the cost of electricity.

To estimate the impact of transformer losses on C&I companies’ electricity bills, DOE modeled the relationship between monthly transformer load characteristics and customer demand and usage. It developed a method to calculate customer monthly bills and derived distrib utions of load parameters from available hourly load data.

The load profiles and characteristics are provided in the Price Load Model worksheet of the LCC spreadsheet for liquid

- immersed transformers and in the Demand & Usage worksheet of the LCC spreads heet for dry

- type transformers. For both types of transformer s , DOE calculated the total cost of electricity both with and without transformer losses and used the difference to calculate incremental electricity costs. S ection 8.3.5 provides a detailed discussion of the electricity price analysis.

8.2.2.4 Step 4: Calculate Cost of Losses

The spreadsheet model estimat es the incremental impacts of no

- load and load losses from the loss coefficients of the design, the monthly customer load chara cteristics (demand and usage), and the cost of electricity. In this step, the spreadsheet combines the no

- load losses, load losses, and electricity price information for each transformer in the baseline scenario and in the

chosen standards scenario. Subseq uent steps project the costs of losses into the future and then convert them back to present values.

8.2.2.5 Step 5: Project Losses and Costs into the Future

The spreadsheet model projects losses and costs into the future based on assumptions regarding load growth and a forecast of future changes in electricity price. Spreadsheet users can

select various scenarios for load growth and future electricity price. The model applies thedt_nopr_tsd_chp8_092311 DRAFT 8

- 7 selected options to the initial cost of losses that were calculated in Ste p 4. DOE presents its specific load growth and electricity price trends in the LCC inputs section (section 8.3) of this chapter.

8.2.2.6 Step 6: Select Discount Rate

To discount the future stream of costs into a present value, the spreadsheet model selects

a disco unt rate from a distribution . The LCC spreadsheet selects a discount rate from a weighted sample of discount rate inputs derived from the financing costs of purchasing transformers. DOE presents its specific discount rates in the LCC inputs section (sectio n 8.3) of this chapter.

8.2.2.7 Step 7: Calculate Present Value of Future Cost of Losses

The spreadsheet model calculates the present value of future operating costs and losses and the present worth per watt of no

- load and load losses. This step applies the discou nt rate selected in Step 6 to the future costs of losses from Step 5 to produce a single, present

- valued number. In addition to the costs from Step 5, the calculation uses as inputs the effective date of the standard, the transformer lifetime, maintenance costs, and a power factor.

8.2.2.8 Step 8: Report Results

The spreadsheet model provides the LCC, LCC savings, payback period, and other

results for inclusion in the distribution of results.

8.2.2.9 Step 9: Repeat Process and Report Results

When applying the Monte Carlo simulation, the model performs a user

- defined number of iterations and reports the results as distributions. The specific number of iterations for the Monte Carlo simulation is specified through the “Repeat Process” decision box. Based on DOE’s rulemaking experience with expressing results as distributions , 10,000 iterations in a Monte Carlo simulation capture sufficient variability. When the specified number of iterations has been reached, the model ends the simulation process and generates result reports.

8.3 INPUTS TO LIFE

- CYCLE COST ANALYSIS

This section describes the LCC inputs used in the spreadsheet model and provides

definitions and data sources for each input . This section also elaborates on how the LCC spreadsheets apply certain user

- chosen inputs to the model. The specific inputs to the model, in the order in which they appear on the left

- hand side of the LCC flowchart ( Figure 8.2.1 ), are:

**•** t ransformer selection A and B parameters

**•** database of transformer designs

**•** markup and installation costs

**•** transformer loadingdt_nopr_tsd_chp8_092311 DRAFT 8

- 8 **•** electricity costs and prices

**•** load growth trends

**•** electricity growth and price trends

**•** discount rate s

**•** effective date of standard

**•** transfo rmer service life

**•** maintenance costs

**•** power factor

8.3.1 A and B Transformer Selection Parameters

The A and B transformer selection parameters that DOE used in calculati ng total owning cost (TOC) characterize the value that transformer purchasers place on reducing no

- load and

load losses

, express ed in terms of dollars per watt of reduced losses. U sing A and B parameters
to represent a customer ’s choice of transformer implies that the value of loss reduction is proportional to the amount by which losses are reduced. Given th e wider applicability of the TOC formulation to the expression of loss valuations, DOE used A and B parameters to

formulate a customer choice model.

To represent the potential range of purchaser s’ valuation of losses, DOE developed three

customer choice scenarios for each LCC calculation. The difference among the three scenarios is the fraction of purchasers who place a value on reducing transformer losses. Those who place a

val ue on reducing losses are described as evaluators ; those who do not consider transformer losses during a purchase decision are termed non

- evaluators . The scenario representing non

evaluation for all purchases has 0 percent evaluators, while the scenario re presenting evaluation for all purchases has 100 percent evaluators.

For liquid

- immersed transformers, DOE’s default scenario is an evaluation rate of 50

percent

. Because few purchasers consider transformer losses as part of the purchase decision for

low

- voltage, dry

- type transformers , DOE assumed a default evaluation rate of 2 percent.

R e garding medium

- voltage, dry

- type transformers, DOE assumed 1 0 percent evaluators for

small

- capacity transformers

— design line s 9 and 11 , and 13A

— and 2 0 percent for large

- capacity

transformers

— design lines 10, 12, and 13 B

.

DOE used the 0

- percent and 100

- percent evaluation scenarios to test the LCC sensitivity to changes in the percentage of transformers purchased using TOC . It estimated the mean value

of A for eval uators from public transformer purchase bids available on the Internet. 3

, 4

, 5

, 6

, 7

, 8

, 9

, 10

, 11
Then, recognizing that there is substantial variability in the value that transformer purchasers may place on reducing losses, DOE created separate statistical models for A and B for liquid

immersed and dry

- type transformers.

For each value of A that a transformer purchaser may use , there is a range of possible B values that are consistent with the particular A parameter. (B parameters relate s to the value associated with load losses.) In general, the ratio of B to A is a measure of the relative importance of load losses and no

- load losses. For a transformer that is constantly loaded at 100 percent of rated capacity, the value s of B and A should be the same, because both load and no

-dt_nopr_tsd_chp8_092311 DRAFT 8

- 9 load losses will always be at their rated values. Load losses increase with the square of the load,

and transformer mean loads are al most always less than 100 percent. Therefore, in practice, B is always less than A, and is approximately equal to A times the square of the expected load ( not considering peak loads).

8.3.1.1 A and B Parameter Selection for Liquid

- Immersed Transformers

DOE collected A and B parameter values from transformer purchase bids available on the Internet and combined these with the sample used in the previous final rule

. 3 T he bid documents were published in various years . I n order to evaluate the data, DOE there fore normalized the A

and B values to 2010$ using the U.S. Bureau of Labor Statistics’ Producer Price Index for power generation , transmission, and control

. 12

A Parameter : To model the distribution of A values in the data, DOE developed a

p iecewise linear fit to the empirical distribution. Figure 8.3.1 shows the cumulative distribution

function for both the data and the model

.

Figure 8.3.1 Cumulative Distribution of Historical A Parameter

and Model A Parameter

Table 8.3.1 lists midpoints for the A parameter and the cumulative probability of each midpoint estimated by the model, along with the probability derived from the historical data. 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

2.5 3.5 4.5 5.5 6.5 7.5 8.5 9.5 10.5 11.5 12.5Probability

A Value $/W (2010$) Cumulative Distribution of A Values

Historical Data

Modeldt_nopr_tsd_chp8_092311 DRAFT 8

- 10 Table 8.3.1 A Parameter Model and Historical Data

A Parameter Midpoint $/W Cumulative Probability

, Model

% Cumulative Probability

, Historical Data

%

2.5 0.20 0.2051

3.5 0.30 0.2821

4.5 0.60 0.5897

5.5 0.70 0.6667

6.5 0.80 0.7949

7.5 0.90 0.9231

8.5 0.95 0.9487

9.5 0.96 0.9487

10.5 0.97 0.9744

11.5 0.98 0.9744

12.5 0.99 1.0000

B Parameter : The data show that the value of the B parameter depends somewhat on the value of A used by the purchaser, with most of the data points lying in two distinct clusters. The

clusters , which represent different ratios of B to A, like ly reflect the different technologies used to serve base load and peak load . The first cluster, consisting of approximately 40 percent o f the sample, has a B:A ratio of 0.24 and represents utilities that place relatively low economic value on load losses. The second cluster has a B:A ration of 0.46 and represents utilities that p lace relatively higher economic value on load losses. Figure 8.3.2 illustrates the two clusters. Each cluster is modeled as a linear fit plus a rand om increment. In the LCC model, purchasers are assigned randomly to one or the other category of B to A ratio, in the same proportion as seen in

the data.dt_nopr_tsd_chp8_092311 DRAFT 8

- 11 Figure 8.3.2 Distributions of Load Loss (B) Values versus No

Load Loss (A) Values for Liquid

- Immersed

Transformers

8.3.1.2 A and B Parameter Selection for Dry

- Type Transformers

DOE developed models of A and B parameter s for dry

- type transformers that differ from those used for liquid

- immersed transformers. The C& I building owners of dry

- type transformers pay for the energy dissipated by the transformer at a price specified by their electricity tariff. DOE estimated that 60 percent of dry

- type transformers are installed in commercial buildings,

and 40 percent in in dustrial buildings

. 13 T he LCC accounts for t his distribution by adjusting the weights of individual building s . For each design lin e, only buildings having a peak load larger than the transformer capacity are included in the customer sample.

A Parameter : DOE used the following equation to convert the customer’s marginal electricity prices to the appropriate A parameter.

A = HP W × MPE W + HP S × MPE S + M W × MPD W + M S × MPD S FCR

�

.

W here:

MPE W = the winter marginal energy charge ($/kilowatt

- hour [ kWh ] ) (see section

8.3.5.2 ;
MPD W = the winter marginal demand charge ($/kW ) (see section 8.3.5.2 ) ;
MPE S = the summer marginal energy charge ($/ kWh ) (see section 8.3.5.2 ) ;
MPD S = the summer marginal demand charge ($/kW ) (see section 8.3.5.2 )

HP W = the number of hours in the winter period ; y = 0.23x + 0.00
R2 = 0.91

y = 0.45x + 0.02
R2 = 0.61

0 1 2 3 4 5

0 2 4 6 8 10 12 14Load Losses (B) $/W ( 2010$)

No

- load Losses (A) $/W (2010$) Line 1

Line 2

Linear (Line 1)

Linear (Line 2)dt_nopr_tsd_chp8_092311 DRAFT 8

- 12 HP S = the number of hours in the summer period ;
M W = the number of months in the winter period , defined as October through April ;
M S = the number of months in the summ er period , defined as May through September ; and

FCR = the fixed charge rate, here equal to 0. 2

. 14

B Parameter : The equation for B is similar to that for A, modifi ed t o account for the fact that load losses depend on the square of the load on the transformer. The transformer load loss rate is defined assuming the transformer is fully loaded; in reality most of the time a transforme r is only partly loaded. This situation is accounted for by the transformer loss factor (LSF), which

is equal to the average of the square of the transformer load divided by the square of the peak transformer load. The building peak load is reduced by an a mount equal to the square of the load on the transformer at the time of the building peak; this effect is accounted for by the transformer peak responsibility factor. The formula for the B parameter is:

B = LSF ( HP W × MPE W + HP S × MPE S ) + RF ( M W × MPD W + M S × MPD S )
FCR

�

Where :

LSF = the transformer energy loss factor , which is equal to the square of the transformer root mean square (RMS) load ; and

RF = the transformer peak responsibility factor , which is equal to the square of the ratio

of the transformer load during the hour of the building peak to the peak

transformer load

.

For both A and B parameters , the fixed charge rate is used to convert the annual cost of

load losses to a net present value

.

To summarize, DOE characterized transformer purchases with respect to efficiency in terms of two economic valuation parameters. The parameter A expresses the value that a customer gives to reducing no

- load losses in dollars per watt, while the parameter B expresses the value given to reducing load losses at rated load. DOE described purchase behavior in terms of evaluators who place a value on reducing losses, and non

- evaluators who place no value on reducing losses. DOE investigated four scenarios as se nsitivities: (1) liquid

- immersed, (2) small

capacity low

- voltage dry

- type, (3) small

- capacity medium

- voltage dry

- type and (4) large

capacity medium

- voltage dry

- type. The A and B parameter evaluation rates for the low, medium and high sensitivities for each of those scenarios are shown in Table 8.3.2 . For evaluators, DOE

used a distribution of A and B values to characterize the economic criteria used in the purchase

decision.

Table 8.3.2 A and B Parameter Evaluation Scenarios Percentage of Evaluators %

Low Medium Highdt_nopr_tsd_chp8_092311 DRAFT 8

- 13 Liquid

- immersed 0 50 100

Low

- voltage dry

- type 0 2 100

Small

- capacity, medium

- voltage dry

- type 0 10 100 Large

- capacity

, medium

- voltage dry

- type 0 20 100

8.3.2 Database of Transformer Designs

Establishing a relationship between cost and efficiency is an integral part of DOE’s rulemaking process. For transformers, DOE derived this relationship from a database developed during the engineering analysis (chapter 5) of selling prices, no

- load losses, and load losses for

the range of realistic transformer designs contained in the LCC spreadsheets. DOE used a commercial transformer design software company, Optimized Program Service Inc., and its software to create the database of designs. The database comprises a wide range of efficiencies and manufacturer selling prices (including a predetermined manufacturer markup) to represent the variability of designs in the marketplace. C hapter 5 p rovides more detail on the method DOE used to generate the database of transformer designs and the database structure

.

8.3.3 Markup and Installation Costs

Bringing a manufactured transformer into service as an installed piece of electrical equipment entails c ost s for m arkups, sales tax, and installation.

For liquid

- immersed transformers, which utilities typically purchase directly from manufacturers, DOE considered the transformer purchase price to be the manufacturer selling price plus , in some cases a distrib utor markup, and sales tax. DOE added installation costs separately. For dry

- type transformers, the distribution channel includes intermediaries who add their own costs to the manufacturer selling price. C osts therefore include a manufacturer markup,

distr ibution markup, contractor markup, installation cost, and sales tax. See chapter 6 of this TSD for a detailed discussion of the markup calculations.

8.3.3.1 Projection of Future Product Prices

To derive a price trend for medium

- sized electric motors, DOE obtaine d historical Producer Price Index (PPI) data for electric power and specialty transformer manufacturing spanning the time period 1969

- 2010 from the Bureau of Labor Statistics’ (BLS). a

Figure

8.3.3 The PPI data reflect nominal prices, adjusted for product quality changes. An inflation

- adjusted (deflated) price index for integral horsepower motors and generators manufacturing was calculated by dividing the PPI series by the Gross Domestic Product Cha ined Price Index (see

**Error! Reference source not found.** ).

a Series ID PCU335311335311; http://www.bls. gov/ppi/dt_nopr_tsd_chp8_092311 DRAFT 8

- 14 Figure 8.3.3 Historical Nominal and Deflated Producer Price

Indexes for Electric Power and Specialty Transformer Manufacturing

From the mid

- 1970s to 2005, the deflated price index for transformers was in decline

. Since then, the index has risen sharply, primarily due to rising prices of copper and steel products that go into manufacturing transformers (see Figure 8.3.4 ). The rising prices for copper and steel products were primarily a result of strong demand from China and other emerging economies. Given the slowdown in global economic activity in 2011, DOE believes that the extent to which the trends of the past five years will continue is very uncertain. DOE performed an exponential fit on the deflated price index for transformers , but the R 2 was relatively low (0 .21 ).

Given the above considerations, DOE decided to use a constant price assumption as the default price factor index to project future distribution trans formers prices in 201 6

. Thus, prices forecast for the LCC and PBP analysis are equal to the 2010 values for each efficiency level in each product class. 0 50 100 150 200 250

0.0 0.2 0.4 0.6 0.8 1.0 1.2

1967 1972 1977 1982 1987 1992 1997 2002 2007**Nominal PPI (1983=100) Deflated PPI (2010=1)** 

Deflated Electric Power and Specialty Transformer Manufacturing PPI

Nominal Electric Power and Specialty Transformer Manufacturing PPIdt_nopr_tsd_chp8_092311 DRAFT 8

- 15 Figure 8.3.4 Historical Deflated Producer Price Indexes for Copper Smelting, Steel Mills Manufacturing and

Electr ic Power and Specialty Transformer Manufacturing

8.3.4 Transformer Loading

To estimate the economic burdens and benefits of efficiency improvements, DOE characterized the energy use and losses of distribution transformers by estimating the loads on

them. Becaus e the application s for distribution transformers vary significantly by type of transformer (liquid

- immersed or dry

- type) and ownership ( 95 percent of electric utilities own liquid

- immersed ; C&I entities primari l y use dry

- type), DOE performed two separate l oad analyses to evaluate the efficiency of the two types of distribution transformers. Chapter 7 of this
TSD, Energy Use and End

- Use Load Characterization

, describe s the two separate load analyses.

8.3.5 Electricity Price Analysis

This section describes the electricity price analysis DOE performed to determine the energy portion of the annual operating expenses for distribution transformers. DOE performed two types of analys e s : one investigated the nature of hourly transformer loads , their correlation with the overall utility system load, and their correlation with hourly electricity costs and prices ; another estimated the impacts of transformer loads and resultant losses on monthly electricity usage, demand, and electricity bills. D OE refers to the two analyses as hourly and monthly analyses, respectively. DOE used the hourly analysis for liquid

- immersed transformers, which 0 0.2 0.4 0.6 0.8

1 1.2 1.4 1.6

1960 1970 1980 1990 2000 2010 2020**Deflated Commodity Price Index (2010=1)**

**Year** Primary Copper Smelting PPI

Iron and Steel Mills PPI

Delfated Distribuiton Transformers PPIdt_nopr_tsd_chp8_092311 DRAFT 8

- 16 are owned predominantly by utilities that pay costs that vary by the hour. DOE used the monthly analysis for dr y

- type transformers, which typically are owned by C&I establishments that receive monthly electricity bills.

8.3.5.1 Hourly Marginal Electricity Price Model for Liquid

- Immersed

Transformers

To evaluate the electricity costs associated with liquid

- immersed transfo rmers, DOE used marginal electricity prices. Marginal prices are those utilities pay for the last kilowatt

- hour of electricity produced. A utility’s marginal price may be higher or lower than its average price, depending on the relationships among capacity , generation, transmission, and distribution costs. The general structure of the hourly marginal cost equation divides the costs of electricity into (1) capacity components and (2) energy cost components. For each component DOE estimated the

economic value for both no

- load losses and load losses. The capacity components include generation and transmission capacity. Capacity components also include a reserve margin for ensuring system reliability , along with factors that account for system losses. Energy cost components include a marginal cost of supply that varies by the hour. DOE developed two methods to calculate marginal costs for the set of regions defined in the Energy Information Administration’s ( EIA ’ s) National Energy Modeling System (NEMS) electricity market module (EMM). 15 The method chosen depends on whether the utility is p art of a traditionally regulated system, or part of a restructured system that includes functioning capacity markets. DOE developed two sets of capacity costs to be applied to the two types of losses

.

CC NLL = the value of the capacity costs associated with no

- load losses, and

CC LL = the value of the capacity costs associated with load losses.

These terms are defined as follows

.

CC NLL = ( 1 + CM ) ( βC G F G + C T F T )

, and

CC LL = ( 1 + CM ) ( βC G F G + C T F T ) ∆ P

.

W here:

C M = t he reserve capacity margin ; β = a load adjustment factor, which is one plus the estimated system losses ; C G = t he cost in $/kW of building new generation capacity ;
F

G = the fixed charge rate used to calculate the annual revenue needed to support an investment in generation capacity ; C T = the overnight cost in $/kW of new transmission capacity ;
F T = the fixed charge rate for transmission investments ; and

∆ P = the reduction in system peak load.

DOE calculated the various inputs of this equati on as follows

.dt_nopr_tsd_chp8_092311 DRAFT 8

- 17 Capacity Margin (C M ) : This factor represents the fraction of extra or reserve capacity needed to ensure system reliability per unit of additional capacity requirement. DOE used the industry standard of 15 percent.

Loss Adjustment Factor (β) : The loss adjustment factor represents the fraction of electricity that is dissipated from the electrical system during generation and transmission. It is one plus the fractional losses in the system. DOE used a constant average value of 1.08, based on the regional transmission and distribution loss factors from the NEMS p lanning model

. 3 The regional transmission and distribution loss factors are given in Table 8.3.3

.

Table 8.3.3 Transmission and Distribution Loss Factors

EMM 1 2 3 4 5 6 7 8 9 10 11 12 13 β 1.070 1.065 1.072 1.068 1.088 1.080 1.080 1.068 1.068 1.081 1.093 1.093 1.093

Unit Generation Capacity Cost (C G ) : This factor represent s the overnight cost of building new generating capacity, as provided by NEMS. 15 The costs do not include financing charges; DOE added the cost of financing to the overnight costs assuming a cost of capital of 5

percent. Table 8.3.4 show s the rates for generating no

- load loss and load loss capacity for regulated systems.

Table 8.3.4 Generation Capacity Costs

EMM

R egion EMM Region Load Loss Generation No

- load Loss Generation
Technology $/kW

- year Technology $/kW

- year

1 ECAR Combined Cycle 158.71 Advanced Coal 560.39

2 ERCOT Combined Cycle 158.71 Advanced Coal 560.39

3 MAAC Half & Half 359.55 Advanced Coal 560.39

4 MAIN Half & Half 359.55 Advanced Coal 560.39

5 MAPP Half & Half 359.55 Advanced Coal 560.39

6 NY Combined Cycle 158.71 Combined Cycle 158.71

7 NE Combined Cycle 158.71 Combined Cycle 158.71

8 FL Combined Cycle 158.71 Advanced Coal 560.39

9 SERC Half & Half 359.55 Advanced Coal 560.39

10 SPP Half & Half 359.55 Advanced Coal 560.39

11 NPP Combined Cycle 158.71 Advanced Coal 560.39

12 RA Combined Cycle 158.71 Advanced Coal 560.39

13 CA Combined Cycle 158.71 Advanced Coal 560.39

Generation Fixed Charge Rate (F G ) : This fixed charge rate is used to calculate the annual revenue required to pay for investment in generation capacity. DOE used a value of 0.15. 3

Unit Transmission Capacity Cost (C T ) : This overnight cost per unit for an increment of new transmission capacity is provided by NEMS

. 15dt_nopr_tsd_chp8_092311 DRAFT 8

- 18 Transmission Fixed Charge Rate (F T ) : This rate is used to convert a lump

- sum investment into an annual revenue requirement. DOE used a value of 0.12. 15

Peak Load Reduction ( ∆P) : Th is reduction results from improved transformer efficiency.

DOE used a statistical model to estimate th e reduction consistent with the methodology used to model transformer hourly loads.

DOE p reformed similar calculations for regions that have functioning capacity markets.

For those regions DOE assumed that the value of generation capacity for load losses can be inferred from the capacity market results :

CC LL = ( 1 + CM ) ( CAP + C T F T ) ∆ P

.

Capacity Market Rate ( CAP ) : For systems having functioning capacity markets, DOE

collected forward results for capacity market auction s from the website of each region’s independent system operator (ISO)

. 16

, 17

, 18 Those values are shown in Table 8.3.5

.

Table 8.3.5 Capacity Market Auction Results

EMM Region ISO Market Auction Results

Percent of Region Served % CAP $/KW

- year

1 ECAR PJM 30 63.66

3 MAAC PJM 100 64.45

4 MAIN PJM 20 63.66

6 NY NYISO 100 162.18

7 NE NEISO 100 54.00

9 SERC PJM 5 63.66

DOE developed two sets of energy costs to be applied to the two types of losses:

EC NLL = the value of the capacity costs associated with no

- load losses, and

EC LL = the value of the capacity costs associated with load losses.

These terms can be further expressed as:

EC NLL = β ∈ NLL ∑ P ( h ) h , and

EC LL = β ∈ LL ∑ P ( h ) e 2 ( h ) h

.

Where:

β = a load adjustment factor, which is one plus the estimated system losses ;

∈ NLL = the no

- load (constant) loss rate ;dt_nopr_tsd_chp8_092311 DRAFT 8

- 19 ∈ LL = the load loss rate ; P(h) = the h ourly electricity price ; and

e 2 (h) = the h ourly transformer load

.

Hourly Electricity Price (P(h)) : To calculate the hourly price of electricity

, DOE used the day

- ahead market clearing price for regions having wholesale electricity markets, and system lambda values for all other regions. System lambda values , which are roughly equal to the operating cost of the next unit in line for dispatch, are filed by control area operators under Federal Energy Regulatory Commission ( FERC ) Form 714

. 19 DOE used the most recent data

available , from 2008, for both market prices and system lambdas.

Hourly Transformer Load ( e 2 (h) ) : DOE used a statistical model to represent hourly variations in transformer loading and the correlation with hourly

- varying system electricity prices. The hourly load model is discussed in detail in chapter 7 of this TSD.

No

- load Loss Rate ( ∈ NLL ) : This par ameter , which provides the no

- load loss rate of the selected transformers, is imported from the database of transformer design options developed in the engineering analysis (chapter 5 )

.

Load Lo s s Rate ( ∈ LL ) : This parameter , which provides the load loss rate of the selected transformers, is imported from the database of transformer design options. The load loss rate is estimated while the transformer is fully loaded

.

8.3.5.2 Monthly Marginal Electricity Price Model for Dry

- Type Transformers

For C&I owners of dry

- type transformers, DOE developed average marginal electricity prices from a n analysis of marginal energy prices from tariffs for commercial buildings. 20

, 21

E lectricity tariffs for C&I c usto mers can be complex, incorporating block rates, seasonal rates, dem and charges, and time

- of

- use rates. To calculate commercial electricity bills requires both the monthly consumption and demand; if the supplying utilit y imposes mandatory time

- of

use (TOU) tariffs

, consumption and demand data are required for each TOU peri od. Monthly billing data, consisting of electricity consumption, demand, and expenditures, are available from

the EIA’s Commercial Building Energy Consumption Survey for 1992 and 199 5 survey years

. a

a See: Chapter 7, Energy Use and End

- Use Load Characterization, for details regarding DOE’s treatment of the CBECS sample. Those monthly data were processed using Coughlin et al.’s tariff bill calculation tools 20 to
generate the corresponding monthly utility bill. DOE used the baseline utility bills to calculate average prices. Because the customer bill depends on both energy consumption and demand, separate marginal prices are needed to represent the effect of independently v arying those two quantities. The monthly price of marginal electricity consumption (or demand) is calculated by decrementing the electricity consumption (or demand) and recalculating the bill. DOE calculated seasonal marginal energy prices (MPE) and margin al demand prices (MPD) for each building in the sample. The summer season is defined as the months May through September, and the winter

season all other months.dt_nopr_tsd_chp8_092311 DRAFT 8

- 20 DOE’s tariff data were updated most recently in 2004. To convert to 2010 dollars, DOE

used two datasets: (1) t he report

, Average Regulated Retail Price of Electricity 22 for 2004

– 2007,

and (2) the Edison Electric Institute (EEI) Typical Bills and Average Rate reports for 2007 23
through 2010. 24

, 25 Based on those data, DOE used customer counts to calculate a weighted

average price escalation factor for each region. The customer counts came from the most recent

EIA Form 861 data. 13 The E EI data cover only publicly owned companies. An analysis of EIA

data for 2003

– 2006 showed that the rate of price escalation does not differ significantly for publicly versus privately owned utility companies, so DOE used the same escalation factors for

both market sectors. Table 8.3.6 provides the average marginal energy and demand prices by

season for the U.S. Censu s divisions. DOE dived the census divisions 8 (Mountain) and 9 (Pacific) into North and South sub regions to account for the impacts of climate on electricity prices.

Table 8.3.6 Average Seasonal Marginal Energy and Demand Prices by Census

Division

Census Division Marginal Energy Price

2010 $/kWh Marginal Demand Price

2010 $/kW

Summer Winter Summer Winter

1 (New England) 0.11 0.10 16.46 12.98

2 (Mid

- Atlantic) 0.09 0.09 14.90 13.15

3 (East North Central) 0.06 0.05 14.04 12.70

4 (West North Central) 0.05 0.05 7.10 5.65

5 (South Atlantic) 0.07 0.07 10.12 9.83

6 (East South Central) 0.06 0.06 9.24 8.87

7 (West South Central) 0.09 0.07 7.18 5.89

8 (Mountain) North 0.05 0.05 3.97 3.94

8 (Mountain) South 0.07 0.08 9.90 9.49

9 (Pacific) North 0.06 0.06 3.48 3.48

9 (Pacific) South 0.11 0.11 9.97 4.54

8.3.6 Trends in Load Growth

The LCC analysis examines a cross

- section of transformers. As part of an LCC sensitivity analysis, DOE applied a load growth trend to each new transformer. Spreadsheet users can choose among three scenarios using the “ Transformer Load Growth/Year ” drop

- box on the Summary worksheet. The three scenarios are : no growth, one

- half

- percent

- per

- year growth, and

one

- percent

- per

- year growth. A s the default scenario DOE used a no growth trend for both liquid

- immersed 3 and dry

- type transformer s

.

8.3.7 Electricity Cost and Price Trends

For the relative change in electricity prices for future years, DOE used the price trends

from the three forecast scenarios in the EIA’s AEO201 1

. 26 The default price trend scenario that DOE used in the LCC analysis is the trend in the AEO201 1 reference case. LCC spreadsheet

users have the choice of using electricity price trends from the AEO 201 1 low

- g rowth scenario

,dt_nopr_tsd_chp8_092311 DRAFT 8

- 21 r eference scenario , or h igh

- g rowth scenario

.

Figure 8.3.5 shows the trends for the three AEO201 1 price projections. Because

AEO201 1 does not forecast beyond 20 3 5, DOE extrapolated the values in later years from the price trend s of the forecast from 2015 to 20 3 5. This method of extrapolation is in line with

method s the EIA currently use s to forecast fuel prices for the Federal Energy Management Program.

Figure 8.3.5 Electricity Price Forecasts from AEO201 1

8.3.8 Discount Rate

The discount rate is the rate at which future expenditures are discounted to estimate their present val ue. DOE derived the discount rates for use in the transformer LCC analysis from estimates of the cost of capital for companies that purchase transformers. Following financial theory, the cost of capital can be interpreted as ( 1) the discount rate that shou ld be used to reduce the future value of cash flows to be derived from a typical company project or investment; ( 2)

the economic cost to a firm of attracting and retaining capital in a competitive environment; or ( 3) the return that investors require from their investment in a firm’s debt or equity. 27 DOE used primarily the first interpretation. Because m ost companies use both debt a nd equity capital to fund investments; for most companies, the cost of capital is the weighted average of the cost to the firm of equity and debt financing. 28

DOE estimated the cost of equity financing using the Capital Asset Pricing Model (CAPM). A mong the most widely used models to estimate the cost of equity financing, the

CAPM assumes that the cost of equity is proportional to the amount of systematic risk associated

with a firm. T he cost of equity financing tends to be high when a firm faces a large degree of systematic risk, and low when the firm faces a small degree of system atic risk. The degree of systematic risk facing a firm and the subsequent cost of equity financing are determined by several variables, including the risk coefficient of a firm (beta, or B ); the expected return on risk

free assets ( R f ); and the additional return expected on assets facing average market risk (which is 80% 85% 90% 95% 100% 105%

2005 2010 2015 2020 2025 2030 2035Real Price Relative to 2008

Year Reference Case High Growth Low Growthdt_nopr_tsd_chp8_092311 DRAFT 8

- 22 known as the equity risk premium, or ERP). The beta indicates the degree of risk associated with a given firm relative to the level of risk (or price variability) in the overall stock market. B etas usually fall between 0.5 and 2.0. A firm having a beta of 0.5 faces half the risk of other stocks in the market; a firm having a beta of 2.0 faces twice the overall stock market risk. Following this approach, the cost of equity financing for a particu lar company is given by the following equation

.

k

e = R f + (B × ERP)

.

W here:

k

e = the cost of equity for a company,

R

f = the expected return of a risk

- free asset,

B = the beta of the company stock, and

ERP = the expected equity risk premium, or the amount by which investors expect the future return on equities to exceed that on a risk

- free asset.

The cost of debt financing ( k d ) is the yield or interest rate paid on money borrowed by a company (for example by selling bonds). As defined here, the cost of debt includes compensation for default risk and excludes deductions for taxes. DOE estimated the cost of debt for companies by adding a risk adjustment factor ( R

a ) to the current yield on long

- term corporate
bo nds (the risk

- free rate). DOE used t his procedure to estimate current (and future) company costs to obtain debt financing. The adjustment factor is based on indicators of company risk, such as credit rating or variability of stock returns.

The discount r ate of companies is the weighted average cost of debt and equity financing, less expected inflation. DOE estimated the discount rate using the equation:

k = (k

e × w e ) + (k d × w d )

.

W here:

k = the (nominal) cost of capital,

k

e and k d = the expected rates of return on equity and debt, respectively, and

w e and w d = the proportion s of equity and debt financing, respectively.

The real discount rate deducts expected inflation from the nominal rate. The expected

return on risk

- free assets, or the risk

- free rat e, is defined by the current yield on long

- term government bonds. The ERP represents the difference between the expected (average) stock

market return and the risk

- free rate. 29 DOE adjusted the risk

- free rate for inflation to arrive at the

real risk

- free rate, which it then used in the CAPM to estimate of the real discount rate as

described above. 30

Table 8.3.7 shows the typical owners of transformers, grouped by transformer type ( the design lines DOE used in the engineering analysis). DOE used a sample of approximately 3,200 companies drawn from the various owner categories to represent transformer purchasers. DOEdt_nopr_tsd_chp8_092311 DRAFT 8

- 23 took the sample from the list of companies included on the Damodaran Online website. 31 DOE obtained the firm beta, the percent of debt and equity financing, the risk

- free rate, and the equity risk premium from Damodaran Online.

Table 8.3.7 Typical Owners of Various Types of Transformers

Design Line Typical Ownership Categories
1, 2, 3, 4 Electric utilities, both publicly and investor owned

5 , 6, 7 Electric utilities, commercial property owners, commercial and

industrial
8, 9, 10, 11, 12, 13 A, 13B C ompanies, government offices

Transformers are purchased and owned by electric utilities (publicly and investor

owned), C& I companies, the owners of commercial buildings (property owners), and all levels of

government. DOE estimated the cost of debt financing for these companies from the 40 year geometric average of the 10

- year Treasury note annual rate and the standard devia tion of the stock price. Publicly owned utilities, including municipals and cooperatives, do not issue stock

and tend to be financed with debt. DOE obtained the cost of debt for th o se companies from information provided in FERC Form 1 filings. Finally, f or owners of government offices, the discount rate represents an average of the Federal rate and the State and local bond rate s . DOE drew the Federal rate directly from the U.S. Office of Management and Budget discount rate for investments in energy effici ency in government buildings. 32 DOE estimated the State and local

discount rates from the interest rates on State and local bonds between 19 71 and 20 10

. 33

Table 8.3.8 shows the average values DOE used for the parameters re lated to cost of equity financing and discount rate for industrial companies, commercial companies, commercial property owners, and i nvestor

- owned utilities. The risk

- free rate and equity risk premium are constant across sectors in each year, but the cost of debt, percent debt financing, and systematic firm risk vary by sector.dt_nopr_tsd_chp8_092311 DRAFT 8

- 24 Table 8.3.8 Variables Used to Estimate Discount Rates for the C&I Sect or

Sector Year β R f % ERP % R
a % w e % w d %

Industrial Companies (SIC 1

– 4) 2005 1.03 3.47 3.89 1.50 79 21

2006 1.00 3.44 4.55 2.00 81 19

2007 1.03 3.74 3.80 2.00 78 22

2008 1.10 4.21 2.19 4.00 73 27

2009 1.06 4.15 3.20 4.00 76 24

2010 1.12 6.74 3.23 2.50 74 26

Commercial Companies (SIC 5

– 8) 2005 0.88 3.47 3.89 1.25 80 20

2006 0.88 3.44 4.55 1.25 78 22

2007 0.90 3.74 3.80 1.25 75 25

2008 0.95 4.21 2.19 3.00 64 36

2009 0.94 4.15 3.20 4.00 68 32

2010 0.98 6.74 3.23 2.00 62 38

Commercial Property

Owners (SIC 6720) 2005 0.70 3.47 3.89 0.25 77 23

2006 0.84 3.44 4.55 0.50 55 45

2007 0.91 3.74 3.80 0.50 60 40

2008 1.06 4.21 2.19 3.00 47 53

2009 1.22 4.15 3.20 3.00 56 44

2010 1.02 6.74 3.23 1.50 67 33

Utilities, Investor

Owned (SIC 49) 2005 0.86 3.47 3.89 0.50 61 39

2006 0.92 3.44 4.55 0.25 61 39

2007 0.88 3.74 3.80 0.25 60 40

2008 0.79 4.21 2.19 1.00 50 50

2009 0.76 4.15 3.20 1.50 51 49

2010 0.75 6.74 3.23 1.00 53 47

* SIC codes refer to the U.S. Standard Industrial Classification system.

As mentioned above, the cost of capital may be viewed as the discount rate that should be used to reduce the future value of typical company project cash flows. It is a nominal discount rate, since anticipated future inflation is included in both stock and bond expected returns. Deducting expected inflation from the cost of capital provides estimates of the real discount rate by ownership category (Table 8.3.9). The mean real discount rate for these companies varies between 2.4 per cent (government offices) and 5.4 percent (industrial companies).dt_nopr_tsd_chp8_092311 DRAFT 8

- 25 Table 8.3.9 Real Discount Rates by Transformer Ownership Category

Ownership Category SIC

Code ( s ) * Mean Real

Discount Rate

% Standard

Deviation

% Number of

Observations

Industrial Companies 1

– 4 5.4 0.4 1866 Commercial Companies 5

– 8 4.6 1.4 1303 Commercial Property Owners 6720 4.6 0.4 3 Utilities, Investor

- Owned 49 3.5 0.4 61 Utilities, Publicly Owned n/a 3.8 0.3 7

Government Offices n/a 2.4 2.2 40

* SIC c odes refer to the U.S. Standard Industrial Classification system.

Because IOUs purchase the bulk of many of the transformer design lines evaluated here, the discount rates calculated for that sector ( Table 8.3.9 ) are particularly important. DOE estimated that the average IOU real discount rate is 3.5 percent. Th at figure is an after

- tax discount rate, representing the return required by such utilities to attract financing. Privat e financial data companies, including Ibbotson Associates, offer similar estimates. Using Ibbotson Associates debt, equity, standard deviation of stock price, and company beta statistics for 2008 in

the electric

, gas , and sanitary services sector (SIC 49), DOE estimates a similar discount rate of

3.84 percent. 27 DOE used the value of 3.5 percent, estimated from the company

- level

Damo daran data, because it is tailored specifically to IOUs, not the broader SIC 49 sector.

DOE’s approach to estimating the cost of capital provides a measure of the spread as well as the average of the discount rate. DOE inferred the spread of the discount rate by ownership category from the standard deviation, which ranges from 0.4 percent to 2.2 percent ( Table

8.3.10 ). Discount rates for p u blicly owned utilit ies and commercial property owner s are narrowly

concentrated around their mean value s

. D iscount rates for C&I compan ies are dispersed across a broader range.dt_nopr_tsd_chp8_092311 DRAFT 8

- 26 Table 8.3.10 Transformer Ownership by Design Line

Design

Line Property

Owners

% Industrial Companies

% Commercial Companies

% Investor

Owned

Utilities

% Publicly

Owned

Utilities

% Government

Offices

%

1 0.4 0.5 0.9 72.0 26.0 0.2

2 0.4 0.5 0.9 72.0 26.0 0.2

3 2.1 2.4 4.5 80.0 10.0 1.0

4 0.4 0.5 0.9 72.0 26.0 0.2

5 9.5 9.5 27.0 35.0 15.0 4.0

6 19.0 19.0 54.0 0 0 7.9

7 19.0 19.0 54.0 0 0 7.9

8 19.0 19.0 54.0 0 0 7.9

9 19.0 19.0 54.0 0 0 7.9

10 19.0 19.0 54.0 0 0 7.9

11 19.0 19.0 54.0 0 0 7.9

12 19.0 19.0 54.0 0 0 7.9

13 A 19.0 19.0 54.0 0 0 7.9

13B 19.0 19.0 54.0 0 0 7.9

Source: DOE contractors.

Various combinations of commercial property owners and commercial, industrial, and utility buyers purchase the different transformer design lines included in the engineering analysis ( c hapter 5). Accordingly, DOE constructed the discount rates associated with any given design

line from various combinations of discount rates for commercial property owner s , commercial, industrial, and utility enterprises

. 34 DOE estimated distributions of discount rate s for the different design lines as a weighted average of the distributions for the ownership types.

8.3.9 Effective Date of Standard

The effective date of the revised energy efficiency standard for distribution transformers

is four years after DOE issues the final rule. DOE assumes that it will issue the final rule in 2012

, so the new standard will take effect in 2016 . DOE calculated the LCC for all users as if each purchase of a new distribution transformer occurs in the year the standard takes effect. It based the cost of the equipment on that year; as stated above, however, DOE expresses all dollar values

in 20 10 $.

8.3.10 Transformer Service Life

DOE defined distribution transformer service life as the age at which a transformer retires from service. DOE assumed, based on Barnes et al. (1996)

, 35 that the average life of distribution transformers is 32 years. This lifetime includes a constant failure rate of 0.5 percent per year due to lightning and other random failures unrelat ed to transformer age, and an additional corrosive failure rate of 0.5 percent per year starting at year 15. DOE adjusted the retirement distribution to maintain an average life of 32 years.dt_nopr_tsd_chp8_092311 DRAFT 8

- 27 8.3.11 Maintenance Costs

M aintenance cost s are those the customer incurs to maintain equipment operation.

M aintenance cost s are not associated with the replacement or repair of components that fail , but

rather with general maintenance. DOE assumed that the cost for general maintenance will not

ch ange with increased efficiency. In practice, there is little scheduled maintenance for

transformers beyond brief annual checks for dust buildup, vermin infestation, and accident or lightning damage.

8.3.12 Power Factor

The power factor of a transformer is the rea l power divided by the apparent power. Real power is the time average of the instantaneous product of voltage and current. Apparent power is the product of the root mean square (RMS) voltage times the RMS current. Transformer efficiency specifications, suc h as NEMA's TP 1

- 2002, assume a power factor of 1.0. 1 Therefore, DOE used a power factor of 1.0, both in calculating efficiency levels in the engineering analysis and when preparing candidate standard levels.

I n real

- world installations, however, the load s experienced by distribution transformers are likely to have power factors of less than 1.0. Because the LCC analysis models transformers that are installed and operating in the field, DOE created the LCC spreadsheet with an adjustable power factor, enabl ing the incorporat ion of lower power factors. In the absence of any specific data or guidance on the appropriate power factor, DOE used 1.0 for this LCC analysis.

8.3.13 Default Scenario

DOE developed separate low, medium, and high scenarios for several key in put parameters. For each of the key inputs, DOE chose the medium designation as the default scenario. The overall default scenario used in the LCC analysis has the following values

.

**•** Transformer load growth per year: medium (one percent) for liquid

- immerse d ; low (zero percent) for dry

- type

.

**•** Transformer loading (relative to current estimate): medium (zero percent ).

**•** Electricity prices (relative to current estimate): medium (zero percent ).

**•** Transformer customer A and B parameters : medium

.

**•** Future energy price trend: AEO2011 reference

.

Other scenarios can be used to explore the sensitivities to variations of these key

variables.

8.4 RESULTS OF LIFE

- CYCLE COST ANALYSIS

This section presents LCC results for the candidate efficiency improvement levels

evaluated for all 14 transformer design lines. Table 8.4.1 summarizes the seven candidate

standard efficiency levels DOE evaluated for each of the 14 design lines examined for thedt_nopr_tsd_chp8_092311 DRAFT 8

- 28 preliminary analysis . The lowest candidate sta ndard level (CSL) is baseline and current standard

, and the highest is the most efficient design identified in the engineering analysis. The other six efficiency levels fall between those two bounds. DOE expresses all CSLs in terms of efficiency, assuming no explicit or implicit technology. The column labeled “ Base +” shows by how much a given standard level exceeds the baseline . DOE based the results presented in this section on the inputs described in section 8.3.

Table 8.4.1 Candidate Standard Levels Evaluated for Each Design Line

**CSL Variable**  Design Line

1 2 3 4 5 6 7 8 9 10 11 12 13A 13B

Baseline (Current DOE Standard) % 99.08 98.91 99.42 99.08 99.42 98.00 98.00 98.60 98.82 99.22 98. 67 99.12 98.63 99.15

1 Base + % 0.08 0.09 0.06 0.08 0.06 0.23 0.23 0.2 0.17 0.09 0.14 0.09 0.13 0.08

Efficiency % 99.16 99 99.48 99.16 99.48 98.23 98.23 98.8 98.99 99.31 98.81 99.21 98.76 99.23

2 Base + % 0.14 0.16 0.09 0.14 0.09 0.47 0.47 0.42 0.3 0.18 0.27 0.18 0.22 0.16

Efficiency % 99.22 99.07 99.51 99.22 99.51 98.47 98.47 99.02 99.12 99.4 98.94 99.3 98.85 99.31

3 Base + % 0.17 0.20 0.12 0.17 0.12 0.60 0.60 0.54 0.46 0.28 0.39 0.27 0.29 0.23

Efficiency % 99.25 99.11 99.54 99.25 99.54 98.6 98.6 99.14 99.28 99.5 99.06 99.39 98.92 99.38

4 Base + % 0.23 0.27 0.15 0.23 0.15 0.80 0.80 0.65 0.56 0.31 0.46 0.34 0.47 0.28

Efficiency % 99.31 99.18 99.57 99.31 99.57 98.8 98.8 99.25 99 .38 99.53 99.13 99.46 99.1 99.43

5 Base + % 0.34 0.40 0.19 0.34 0.19 0.93 0.93 0.72 0.68 0.38 0.65 0.41 0.66 0.34

Efficiency % 99.42 99.31 9 9.61 99.42 99.61 98.93 98.93 99.32 99.5 99.6 99.32 99.53 99.29 99.49

6 Base + % 0.42 0.50 0.27 0.42 0.27 1.17 1.17 0.84 0.77 0.45 0.83 0.47 0.85 0.43

Efficiency % 99.5 99.41 99.69 99.5 99.69 99.17 99.17 99.44 99 .59 99.67 99.5 99.59 99.48 99.58

7 Base + % 0.42 0.55 0.31 0.52 0.27 1.44 1.44 0.98 0.77 0.45 0.83 0.53 0.85 0.43

Efficiency % 99.5 99.46 99 .73 99.6 99.69 99.44 99.44 99.58 99.59 99.67 99.5 99.65 99.48 99.58

One major impact of an energy efficiency standard is t o change the set of transformer designs available for purchase and their corresponding loss characteristics: load losses (LL) and

no

- load losses (NL). This effe ct is illustrated in the “ LL versus NL graph ” (worksheet LL versus

NL in the LCC spreadsheet).

Figure 8.4.2 provides an example of the “ LL versus NL graph ” from the LCC spreadsheet for design line 1, using CSL 1

. Becaus e each design line has a unique set of engineering constraints, the LL

- versus

- NL graph for each will be different. This graph plots results of a Crystal Ball run for LCC . It shows different sets of designs by their LL at rated load and by their

NL . Potential designs are shown as both small dots and small triangles . The selected des igns not subject to standard constraints are plotted as circles . The designs subject to standards constraints are plotted as dots. As the required efficiency level increases, the cluster of selected designs moves to the left (to the area for lower losses. The efficiency level is defined at 50 percent load liq uid

- immersed and medium

- voltage dry

- type , and 35 percent load for low

- voltage dry

- type
transformers , while the LL and NL for the design assumptions are defined by nameplate loading (100 percent). For th ose designs having higher LL , the heating from losses causes the actual efficiency to drop, shifting the design to the right in the graph

.dt_nopr_tsd_chp8_092311 DRAFT 8

- 29 Figure 8.4.2 Design Load Losses versus No

- Load Losses in the

Base Case and Candidate Standard Level 1 for Design Line 1

Figure 8.4.3 illustrates the distribution of results of the LCC analysis for one design line

at one CSL. The LCC spreadsheet tool can generate g raphical representations such as Figure

8.4.3 for each design line and candidate standard level. 0.00 100.00 200.00 300.00 400.00 500.00 600.00 700.00 800.00 900.00 1,000.00

0 20 40 60 80 100 120 140 160 180**Load Losses (watts)**

**No Load Losses (watts) Load Losses (LL) vs No** 

**- Load Losses (NL)** 

Available Designs

Selected Designs, Base

Selected Designs, Standarddt_nopr_tsd_chp8_092311 DRAFT 8

- 30 Figure 8.4.3 Distribution of Life

- Cycle Cost Results for Design

Line 2 , C andidate Standard Level 2

The 1 4 tables that follow summarize the results from DOE’s LCC analysis. For each evaluated design line and each CSL, DOE presents the percent efficiency; the percent of evaluated transformer purchases that would experience negative, zero, and positive LCC savings when subject to the CSL; and t he mean LCC savings.

8.4.2 Results for Design Line 1

Table 8.4. 2 summar izes the results of the LCC analysis for the representative unit from design line 1, a 50

- kVA, liquid

- immersed, single

- phase, pad

- mounted transformer. The average efficiency of the baseline units selected during the LCC analysis was 99.17 percent. The customer equipment cost before installation, which includes the manufacturer selling price, shipping costs, distributor markup, and sales tax, was $2,149; the installation cost was $1,381.

Table 8.4.2 Re sults of Life

- Cycle Cost Analysis: Representative Unit, Design Line 1

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.16% 99.22% 99.25% 99.31% 99.42% 99.50% 99.50%

Transformers with Net Increase in LCC (%) 41.18% 0.69% 0.59% 3.93% 11.20% 38.08% 38.08%

Transformers with No Impact on LCC (%) 17.94% 15.54% 15.54% 11.66% 8.44% 0.08% 0.08%

Transformers with Net LCC Savings (%) 40.88% 83.77% 83.87% 84.41% 80.36% 61.84% 61.84%

Mean LCC Savings ($) 116 918 920 902 797 369 369

Median LCC Savings ($) 0 976 977 946 761 251 251dt_nopr_tsd_chp8_092311 DRAFT 8

- 31 8.4.3 Results for Design Line 2

Table 8.4. 3 summar izes results of the LCC analysis for the representative unit from design line 2, a 25

- kVA, liquid

- immersed, single

- phase, pole

- mounted transformer. The average efficiency of the baseline units selected during the LCC analysis was 98.9 6 percent. The

c ustomer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax , was $ 1, 365 ; the installation cost was $ 1, 608

.

Table 8.4.3 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 2

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.00% 99.07% 99.11% 99.18% 99.31% 99.41% 99.46%

Transformers with Net Increase in LCC (%) 14.98% 5.50% 6.44% 10.35% 29.64% 48.46% 66.73%

Transformers with No Impact on LCC (%) 11.87% 11.34% 10.41% 6.88% 2.13% 0.18% 0.00%

Transformers with Net LCC Savings (%) 73.15% 83.16% 83.15% 82.77% 68.23% 51.36% 33.27%

Mean LCC Savings ($) 467 574 562 528 215 11

- 214

Median LCC Savings ($) 525 621 607 575 230 18

- 219

8.4.4 Results for Design Line 3

Table 8.4. 4 summar izes the results of the LCC analysis for the representative unit from design line 3, a 500

- kVA, liquid

- immersed, single

- phase distribution transformer. The average efficiency of the baseline units selected during the LCC analysis was 99. 51 percent. The

c ustomer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax , was $ 9,519 ; the installation cost was $ 4,343

.

Table 8.4.4 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 3

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.48% 99.51% 99.54% 99.57% 99.61% 99.69% 99.73%

Transformers with Net Increase in LCC (%) 4.44% 4.87% 1.66% 1.15% 1.64% 9.54% 27.12%

Transformers with No Impact on LCC (%) 48.48% 43.30% 28.70% 27.83% 24.68% 10.16% 0.00%

Transformers with Net LCC Savings (%) 47.08% 51.83% 69.64% 71.02% 73.68% 80.30% 72.88%

Mean LCC Savings ($) 2192 2739 5371 5733 6748 8485 7110

Median LCC Savings ($) 0 513 5704 6239 7157 7734 5278dt_nopr_tsd_chp8_092311 DRAFT 8

- 32 8.4.5 Results for Design Line 4

Table 8.4. 5 summar izes results of the LCC analysis for the representative unit from design line 4, a 150

- kVA, liquid

- immersed, three

- phase distribution transformer. The average efficiency of the baseline units selected during the LCC analysis was 99. 23 percent. The

customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax , was $ 5,902 ; the installation cost was $ 3 ,964

.

Table 8.4.5 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 4

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.16% 99.22% 99.25% 99.31% 99.42% 99.50% 99.60%

Transformers with Net Increase in LCC (%) 6.02% 0.03% 0.03% 0.03% 0.44% 18.86% 42.53%

Transformers with No Impact on LCC (%) 35.55% 35.55% 35.55% 35.55% 33.48% 8.67% 0.00%

Transformers with Net LCC Savings (%) 58.43% 64.42% 64.42% 64.42% 66.08% 72.47% 57.47%

Mean LCC Savings ($) 1429 2953.9 2953.9 2954.3 3023.3 2874 1187
Median LCC Savings ($) 275 3499.7 3499.7 3501.3 3570.5 2793 772

8.4.6 Results for Design Line 5

Table 8.4. 6 summar izes results of the LCC analysis for the representative unit from design line 5, a 1

, 500

- kVA, liquid

- immersed, three

- phase distribution transformer. The average efficiency of the baseline units selected during the LCC analysis was 99. 4 5 percent. The

c ustomer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax , was $ 26, 553 ; the installation cost was $ 11,199

.

Table 8.4.6 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 5

Candidate Stan dard Level

1 2 3 4 5 6 7

Efficiency (%) 99.48% 99.51% 99.54% 99.57% 99.61% 99.69% 99.69%

Transformers with Net Increase in LCC (%) 27.61% 24.66% 15.91% 14.50% 10.42% 17.97% 17.97%

Transformers with No Impact on LCC (%) 9.87% 3.70% 1.93% 1.30% 0.00% 0.00% 0.00%

Transformers with Net LCC Savings (%) 62.52% 71.64% 82.16% 84.20% 89.58% 82.03% 82.03%

Mean LCC Savings ($) 4937 7786 10734 11282 15347 15754 15754
Median LCC Savings ($) 4662 7359 8991 9588 14095 13993 13993dt_nopr_tsd_chp8_092311 DRAFT 8

- 33 8.4.7 Results for Design Line 6

Table 8.4.7 summar izes results of the LCC analysis for the representative unit from design line 6 , a 25

- kVA, low

- voltage, dry

- type, three

- phase transformer with a 10

- kilovolt (kV) basic impulse insulation level ( BIL ). T he average efficiency of the basel ine units selected during the LCC analysis was 98. 33 . The c ustomer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $ 1, 006 ; the installation cost was $ 900

.

Table 8.4.7 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 6

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.23% 98.47% 98.60% 98.80% 98.93% 99.17% 99.44%

Transformers with Net Increase in LCC (%) 0.00% 36.61% 25.24% 37.54% 32.43% 53.32% 97.68%

Transformers with No Impact on LCC (%) 0.00% 61.96% 74.53% 62.46% 67.57% 46.68% 2.32%

Transformers with Net LCC Savings (%) 100.00% 1.43% 0.23% 0.00% 0.00% 0.00% 0.00%

Mean LCC Savings ($) 0 29 59 76 122 9

- 952

Median LCC Savings ($) 0 18 48 60 102

- 24

- 1005

8.4.8 Results for Design Line 7

Table 8.4. 8 summarizes results of the LCC analysis for the representative unit from design line 7 , a 75

- kVA, low

- voltage, dry

- type, three

- phase transformer with a 10

- kV basic BIL. The average efficiency of the baseline units selected during the LCC analysis was 98. 41 percent.
The c ustomer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax , was $ 2, 5 57 ; the installation cost was $ 1, 604

.

Table 8.4.8 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 7

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.23% 98.47% 98.60% 98.80% 98.93% 99.17% 99.44%

Transformers with Net Increase in LCC (%) 0.0% 0.5% 18.5% 10.9% 10.1% 69.8% 69.8%

Transformers with No Impact on LCC (%) 21.5% 72.8% 80.0% 89.1% 90.0% 30.2% 30.2%

Transformers with Net LCC Savings (%) 78.5% 26.7% 1.5% 0.0% 0.0% 0.0% 0.0%

Mean LCC Savings ($) 323 826 849 1093 1328

- 511

- 511
Median LCC Savings ($) 0 685 657 883 1103

- 745

- 745dt_nopr_tsd_chp8_092311 DRAFT 8

- 34 8.4.9 Results for Design Line 8

Table 8.4. 9 summarizes results of the LCC analysis for the representative unit from design line 8 , a 300

- kVA, low

- voltage, dry

- type, three

- phase transformer with a 20

- kV BIL. The average efficiency of the baseline units selected during the LCC analysis was 98

. 6 7 percent. The

customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax , was $ 6

, 144 ; the installation cost was $ 2

, 734

.

Table 8.4.9 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 8

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.80% 99.02% 99.14% 99.25% 99.32% 99.44% 99.58%

Transformers with Net LCC Cost (%) 3.87% 1.30% 1.93% 5.15% 4.05% 4.06% 56.08%

Transformers with Net LCC Benefit (%) 86.71% 91.63% 94.83% 94.85% 95.95% 95.94% 43.92%

Transformers with No Change in LCC (%) 9.42% 7.07% 3.24% 0.00% 0.00% 0.00% 0.00%

Mean LCC Savings ($) 1401 3554 4253 4999 5826 5844

- 186
Median LCC Savings ($) 1172 3487 4162 4537 5510 5531

- 632

8.4.10 Results for Design Line 9

Table 8.4. 10 summarizes results of the LCC analysis for the representative unit from design line 9, a 300

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 45

- kV BIL. The average efficiency of the baseline units selected during the LCC analysis was 98. 8 6 percent

. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor ma rkup, and sales tax, was $ 10, 717 ; the installation cost was $ 3

, 157

.

Table 8.4.10 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 9

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.99% 99.12% 99.28% 99.38% 99.50% 99.59% 99.59%

Transformers with Net LCC Cost (%) 0.48% 2.18% 10.97% 7.72% 18.57% 60.50% 60.50%

Transformers with Net LCC Benefit (%) 88.25% 96.29% 89.03% 92.28% 81.43% 39.50% 39.50%

Transformers with No Change in LCC (%) 11.27% 1.53% 0.00% 0.00% 0.00% 0.00% 0.00%

Mean LCC Savings ($) 2761 3863 3700 5085 3998

- 673

- 673
Median LCC Savings ($) 2746 3807 3298 4708 3488

- 1285

- 1285dt_nopr_tsd_chp8_092311 DRAFT 8

- 35 8.4.11 Results for Design Line 10

Table 8.4. 11 summarizes results of the LCC analysis for the representative unit from design line 10, a 1

, 500

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 45

- kV

BIL. The average efficiency of the baseline units selected during the LCC analysis was 99. 2 8 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $ 37

, 303 ; the installation cost was $ 6,328

.

Table 8.4.11 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 10

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.31% 99.40% 99.50% 99.53% 99.60% 99.67% 99.67%

Transformers with Net LCC Cost (%) 11.05% 24.79% 31.68% 27.38% 35.45% 69.49% 69.49%

Transformers with Net LCC Benefit (%) 82.63% 75.18% 68.32% 72.62% 64.55% 30.51% 30.51%

Transformers with No Change in LCC (%) 6.32% 0.03% 0.00% 0.00% 0.00% 0.00% 0.00%

Mean LCC Savings ($) 2778 4329 4849 6311 5574

- 5311

- 5311
Median LCC Savings ($) 2142 3372 3787 4986 3842

- 7440

- 7440

8.4.12 Results for Design Line 11

Table 8.4.1 2 summarizes results of the LCC analysis for the representative unit from design line 11, a 300

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 95

- kV

BIL. The average efficiency of the baseline units sele cted during the LCC analysis was 98. 70 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $ 16,358 ; the installation cost was $ 3,755

.

Table 8.4.12 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 11

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.81% 98.94% 99.06% 99.13% 99.32% 99.50% 99.50%

Transformers with Net LCC Cost (%) 27.05% 46.40% 16.55% 14.00% 22.24% 57.84% 57.84%

Transformers with Net LCC Benefit (%) 70.46% 53.60% 83.45% 86.00% 77.76% 42.16% 42.16%

Transformers with No Change in LCC (%) 2.49% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%

Mean LCC Savings ($) 810 497 2709 3121 3120

- 309

- 309
Median LCC Savings ($) 606 177 2477 2857 2673

- 1003

- 1003dt_nopr_tsd_chp8_092311 DRAFT 8

- 36 8.4.13 Results for Design Line 12

Table 8.4.1 3 summarizes results of the LCC analysis for the representative unit from design line 12, a 1500

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 95

- kV

BIL. The average efficiency of the baseline units selected during the LCC analysis was 99. 1 4 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $ 44,8 86 ; the installation cost was $ 6,773

.

Table 8.4.13 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line 12

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.21% 99.30% 99.39% 99.46% 99.53% 99.59% 99.65%

Transformers with Net LCC Cost (%) 15.02% 13.00% 24.56% 24.33% 25.64% 33.51% 64.68%

Transformers with Net LCC Benefit (%) 79.00% 85.75% 75.44% 75.67% 74.36% 66.49% 35.32%

Transformers with No Change in LCC (%) 5.98% 1.25% 0.00% 0.00% 0.00% 0.00% 0.00%

Mean LCC Savings ($) 5322 8865 8644 8076 9726 8504

- 4210
Median LCC Savings ($) 4216 7422 6868 6644 7815 6146

- 6987

8.4.14 Results for Design Line 13 A

Table 8.4.1 4 summarizes results of the LCC analysis for the representative unit from design line 13, a 2

, 000

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 125

- kV

BIL. The average efficiency of the baseline units selected during the LCC analysis was 98.6 6 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $ 23,567 ; the installation cost was $ 4,562

.

Table 8.4.14 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line

13 A

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 98.76% 98.85% 98.92% 99.10% 99.29% 99.48% 99.48%

Transformers with Net LCC Cost (%) 27.55% 28.94% 41.10% 30.88% 33.17% 87.49% 87.49%

Transformers with Net LCC Benefit (%) 70.74% 71.01% 58.90% 69.12% 66.83% 12.51% 12.51%

Transformers with No Change in LCC (%) 1.71% 0.05% 0.00% 0.00% 0.00% 0.00% 0.00%

Mean LCC Savings ($) 855 1107 749 1701 2060

- 6331

- 6331
Median LCC Savings ($) 654 860 470 1439 1600

- 7068

- 7068dt_nopr_tsd_chp8_092311 DRAFT 8

- 37 8.4.15 Results for Design Line 13B

Table 8.4.14 summarizes results of the LCC analysis for the representative unit from design line 13, a 2,000

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 125

- kV BIL. The average efficiency of the baseline units selected during the LCC analysis was 99. 1 8 percent. The customer equipment cost before installation, which includes the manuf acturer selling price, distributor markup, contractor markup, and sales tax, was $ 60,907 ; the installation cost was $ 8,485

.

Table 8.4.15 Results of Life

- Cycle Cost Analysis: Representative Unit, Design Line

13B

Candidate Standard Level

1 2 3 4 5 6 7

Efficiency (%) 99.23% 99.31% 99.38% 99.43% 99.49% 99.58% 99.58%

Transformers with Net LCC Cost (%) 20.61% 12.20% 19.90% 39.80% 26.67% 39.77% 39.77%

Transformers with Net LCC Benefit (%) 73.56% 87.69% 80.10% 60.20% 73.33% 60.23% 60.23%

Transformers with No Change in LCC (%) 5.83% 0.11% 0.00% 0.00% 0.00% 0.00% 0.00%

Mean LCC Savings ($) 4351 8668 8878 4642 9271 6033 6033
Median LCC Savings ($) 3397 7455 7495 2917 7794 4359 4359

8.5 LIFE

- CYCLE COST SENSITIVI TY ANALYSIS

DOE recognizes that all engineering and economic analyses involve some uncertainty . To minimize that uncertainty, DOE strives to use the best techniques and the best data at its disposal. To account for the widest possible set of scenarios, DOE used distributions of values for key inputs to the analysis . For some variables, DOE went one step further by incorporating in the LCC spreadsheet the ability to repeat a given LCC analysis using values different from the default set used to produce DOE’s results.

Detailed descriptions of all of the LCC input variables are included in the discussion of inputs in section 8.3, with additional information in chapters 6 and 7. This section focuses on five key variables and the effect on the LCC results if they are assigned d ifferent values. The five

variable s and the location of their descriptive materials are:

1. percentage of transformers purchased using evaluation of parameters A and B (see

section 8.3.1 );

2. transformer loading relative to current estimate (see chapter 7 );

3. electricity price (see chapter 7) ; 4. load growth trends (see section 8.3.6 ) ; and

5. equipment price (see chapter 6) ; and

6. electricity price trends (see section 8.3.7 ).dt_nopr_tsd_chp8_092311 DRAFT 8

- 38 This analysis examines how sensitive the LCC results are to change s in key DOE assumptions. For this NOPR , DOE conducted the sensitivity analysis on design lines 1

, 7

, and

12

. Because t h e analysis treats ea ch variable independently, the default val ues remain in effect for all variables except the one being examined. Sensitivity results should always be compared to

default results. Each of the six variables has three values

— low, medium, and high

— that are

described in the previous sections d iscussing each individual input variable.

The variable that characterizes the percentage of transformers purchased using evaluation of parameters A and B uses the same set of low and high values , but different medium values, for liquid

- immersed and dry

- type tran sformers. The low value represents a scenario in which no transformer purchases are evaluated ( the non

- evaluating scenario ) . The high value represents a

scenario in which all transformer purchases are evaluated. The medium value for liquid

immersed transfo rmers represents a scenario in which 50 percent of purchases are evaluated. The

medium value for low

- voltage dry

- type transformers represents a scenario in which 2 percent of purchases are evaluated. The medium value for small

- capacity, medium

- voltage, dry

- type transformers represents a scenario in which 1 0 percent of purchases are evaluated. The medium value for large

- capacity, medium

- voltage, dry

- type transformers represents a scenario in which

2 0 percent of purchases are evaluated.

For transformer loading, the medium scenario represents the output of the load simulation

described in chapter 7 . The low scenario decreases the medium scenario load by 15 percent ; the high scenario increases it by 15 percent. For load growth, the annual l ow, medium, and high

scenarios are 0 percent, 1 percent, and 2 percent, respectively. Electricity price trends use the

AEO2011 low, reference, and high growth scenarios.

8.5.1 Sensitivity Results for Design Line 1

The representative unit from design line 1 is a 50

- kVA, liquid

- immersed, single

- phase, pad

- mounted transformer. T he average efficiency of the baseline units selected during the LCC analysis was 9 9

. 17 percent. The c ustomer equipment cost before installation, which includes the manufacturer selling price, shipping costs, distributor markup, and sales tax, was $ 2

, 149 ; the installation cost was $1, 381

.

Table 8.5.1 and Figure 8.5.1 illustrate the LCC sensitivity to changes in the six user

selectable variables. For all variables, each sensitivity run causes some change in the LCC results. For design line 1, the change in percentage of transformer loading results in the most significant changes in LCC savings for all CSLs examin ed. The reason that transformer loading is so important is that it is related directly to the amount of electricity that passes through a transformer. When the load on a transformer is increased, the load losses also increase. Thus at higher loading levels the economic gains from the reduction in losses are significant compared to

the baseline.dt_nopr_tsd_chp8_092311 DRAFT 8

- 39 Table 8.5.1 Effects of Changed Variables on Life

- Cycle Cost Savings for Representative Unit, Design Line 1

Scenario Candidate Standard Level

1 2 3 4 5 6 Efficiency % 99.16% 99.22% 99.25% 99.31% 99.42% 99.50%

Baseline 144 913 915 916 851 459

Low A & B Distribution

- 73 996 996 982 899 450 High A & B Distribution 205 880 883 861 745 328 Low Loading 39 934 937 864 645 115 High Loading 206 900 901 946 974 664

Low Electricity Price 87 828 830 802 683 251 High Electricity Price 147 1011 1013 1005 920 505

No Load Growth 116 918 920 902 797 369 High Load Growth 175 906 908 931 913 561 Low Equipment Price 24 917 921 929 888 592 High Equipment Price

- 135 790 792 713 504

- 148 Low Electricity Price Trend 102 874 876 854 740 307 High Electricity Price Trend 130 963 965 951 854 431dt_nopr_tsd_chp8_092311 DRAFT 8

- 40 Figure 8.5.1 Average Life

- Cycle Cost Savings ( 2010 $) by Scenario for Design Line 1

8.5.2 Sensitivity Results for Design Line 7

The representative unit from design line 7 is a 75

- kVA, low

- voltage, dry

- type, three

phase transformer with a 10

- kV basic BIL. The average efficiency of the baseline units selected during the LCC analysis was 98.41 percent. The customer equipment cost before installation,

w hich includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $2,557; the installation cost was $1,604.

Table 8.5.2 and Figure 8.5.2 illustrate the LCC sensitivity to changes in the six user

selectable variables for design line 7. For all variables, each sensitivity run causes some change in the LCC results. The changes tend to increase with the efficiency o f the CSL. For design line 7, the change in percentage of transformers purchased using evaluation of parameters A and B; low equipment prices; and, at higher efficiency levels, high electricity cost result in significantly larger changes in the LCC savings than do the other variables for all CSLs examined. The purchase behavior described by evaluation of parameters A and B strongly affects how much energy is used when there is no standard, and thus affects potential savings. The low savings

from the case of high A and B evaluation result from the fact that DOE assumes that all purchasers place an economic value on losses and will purchase a transformer based on those

values instead of lowest first cost. - 200 0 200 400 600 800 1000 1200

99.16% 99.22% 99.25% 99.31% 99.42% 99.50% 99.50%Life-Cycle Cost Savings ($2010)

Transformer Efficiency Baseline

Low A & B Distribution

High A & B Distribution

Low Loading

High Loading

Low Electricity Price

High Electricity Price

No Load Growth

High Load Growth

Low Equipment Price

High Equipment Price

Low Electricity Price Trend

High Electricity Price Trenddt_nopr_tsd_chp8_092311 DRAFT 8

- 41 Table 8.5.2 Effects of Changed Variables on Life

- Cycle Cost Savin gs for Representative Unit, Design Line 7

Scenario Candidate Standard Level

1 2 3 4 5 6 7 Efficiency % 98.23% 98.47% 98.60% 98.80% 98.93% 99.17% 99.44%

Baseline 323 756 826 849 1093 1328

- 511

Low A & B Distribution 359 839 915 948 1,173 1,422

- 418 High A & B Distribution 0 1 6

- 53 395 473

- 1,362 Low Loading 325 746 800 693 1,136 1,193

- 871 High Loading 322 762 839 927 1,072 1,396

- 332 Low Electricity Price 286 671 733 736 874 1,064

- 787 High Electricity Price 360 841 918 963 1,313 1,593

- 236

Medium Load Growth 322 762 840 935 1,070 1,403

- 315 High Load Growth 321 769 856 1,032 1,044 1,486

- 94 Low Equipment Price 19 210 471 554 854 1,157

- 254 High Equipment Price 233 562 852 819 890 1,032

- 1,491 Low Electricity Price Trend 296 694 757 750 941 1,124

- 750 High Electricity Price Trend 345 809 884 933 1,222 1,501

- 310dt_nopr_tsd_chp8_092311 DRAFT 8

- 42 Figure 8.5.2 Average Life

- Cycle Cost Savings ( 2010 $) by Scenario for Design Line 7

8.5.3 Sensitivity Results for Design Line 1 2

The representative unit from design line 1 3 is a 1500

- kVA, medium

- voltage, dry

- type,
three

- phase transformer with a 95

- kV BIL. The average efficiency of the baseline units selected during the LCC analysis was 99.14 percent. The customer equipment cost before installation, which includes the manufacturer selling pr ice, distributor markup, contractor markup, and sales tax, was $44,886; the installation cost was $6,773.

Table 8.5.3 and Figure 8.5.3 illustrate the LCC sensitivity to changes in the six user

selectable variables for design line 13. For all the variables , each sensitivity run causes some change in the LCC results. The changes tend to increase with the efficiency of the CSL. For design line 13, the change in percentage of transformer loading results in the most significant increase in LCC savings for all C SLs examined. The reason that transformer loading is important is that it is directly related to the amount of electricity that passes through a transformer. When the load on a transformer is increased, the load losses also increase; at higher loading leve ls the economic gains from the reduction in losses are greater when compared to the baseline. - 2000 - 1500 - 1000

- 500 0 500 1000 1500 2000

98.23% 98.47% 98.60% 98.80% 98.93% 99.17% 99.44%Life-Cycle Cost Savings ($2010)

Transformer Efficiency Baseline

Low A & B Distribution

High A & B Distribution

Low Loading

High Loading

Low Electricity Price

High Electricity Price

Medium Load Growth

High Load Growth

Low Equipment Price

High Equipment Price

Low Electricity Price Trend

High Electricity Price Trenddt_nopr_tsd_chp8_092311 DRAFT 8

- 43 Table 8.5.3 Effects of Changed Variables on Life

- Cycle Cost Savings (2010$) for Representative Unit, Design Line 1 2

Scenario Candidate Standard Level

1 2 3 4 5 6 7 Efficiency % 99.21% 99.30% 99.39% 99.46% 99.53% 99.59% 99.65%

Baseline 5,322 8,865 8,644 8,076 9,726 8,504

- 4,210

Low A & B Distribution 5,443 9,112 8,912 8,349 9,999 8,778

- 3,935 High A & B Distribution 4,011 6,302 5,852 5,273 6,917 5,693

- 7,025 Low Loading 2,318 4,205 2,198 4,278 4,213 1,353

- 12,989 High Loading 6,706 11,007 11,603 9,817 12,261 11,791

- 177 Low Electricity Price 4,722 7,795 7,160 5,405 6,573 5,070

- 7,900 High Electricity Price 5,921 9,935 10,128 10,747 12,878 11,939

- 521

Medium Load Growth 6,770 11,107 11,744 9,901 12,379 11,947 16 High Load Growth 8,400 13,629 15,233 11,956 15,365 15,820 4,771 Low Equipment Price 5,314 7,836 9,986 10,448 13,600 13,681 5,090 High Equipment Price 4,725 5,731 4,311 810 1,214

- 1,862

- 20,753 Low Electricity Price Trend 4,654 7,728 7,067 5,860 7,029 5,475

- 7,553 High Electricity Price Trend 5,886 9,825 9,974 9,943 11,999 11,058

- 1,393

Figure 8.5.3 Average Life

- Cycle Cost Savings ( 2010 $) by Scenario for Design Line 13 - 25,000 - 20,000 - 15,000 - 10,000

- 5,000 0 5,000 10,000 15,000 20,000

99.21% 99.30% 99.39% 99.46% 99.53% 99.59% 99.65%Life-Cycle Cost Savings ($2010)

Transformer Efficiency Baseline

Low A & B Distribution

High A & B Distribution

Low Loading

High Loading

Low Electricity Price

High Electricity Price

Medium Load Growth

High Load Growth

Low Equipment Price

High Equipment Price

Low Electricity Price Trend

High Electricity Price Trenddt_nopr_tsd_chp8_092311 DRAFT 8

- 44 8.6 PAYBACK PERIOD

The payback period ( PBP ) analysis is commonly used to evaluat e investment decisions. A more energy efficient device usually cost s more to purchase than a device of standard energy efficiency. T he more efficient device usually cost s less to operate, however, be cause of its lower

energy consumption . The payback period is the time (usually expressed in years) it takes to recover the additional first cost of the efficient device through its energy cost savings. Because the LCC analysis uses distributions of inputs, DOE gives PBP results in the form of distributions.

8.6.1 Definition

The PBP is the ratio of the incr ease in purchase expense ( for a more efficient design compared to a less efficient design ) to the decrease in annual operating expenditures for the more

effici ent design . This calculation provides what is known as a simple payback period because it does not take into account changes in operating costs over time. PBP is found using the equation:

PBP = ∆ FC ∆ OC �

.

W here:

ΔFC = installed purchase price (first cost) of a transformer that satisf ies the given CSL minus the first cost of a transformer in the absence of the standard (assumes the transformer meeting the standard is more expensive than the transformer not subject to the standard) ( 20 10 $), and

ΔOC = operating cost of the transformer not subject to the standard minus operating cost of the transformer subject to the standard (assumes the transformer meeting the candidate standard level has lower energy consumption, and hen ce lower operating cost). Because Δ OC is expressed in annual terms, PBP is expressed in years.

DOE calculates the PBP both for a distribution of transformers and for an average

transformer. F or the national average transformer

, the average values of the increase in first cost
and the operating

- cost savings are used to calculate the PBP.

8.6.2 Inputs to Payback Period

The inputs to PBP are: ( 1) the purchase expense, otherwise known as the total installed

customer cost, or first cost, for each selected design; and ( 2) the annual (first

- year) operating expenditures for each selected design. The inputs to the purchase expense are the equipment price and the installation cost including appropriate markups. The inputs t o operating costs are the annual ( first

- year) energy consumption and the electricity price. The distributional PBP uses the same inputs as the LCC analysis described in section 8.3, except that, because this is a simple payback, the electricity price DOE u ses is only for the year the standard takes effect, assumed

here to be 2016

.dt_nopr_tsd_chp8_092311 DRAFT 8

- 45 8.6.3 Issues Regarding Baseline Scenario

DOE’s default assumption for the baseline scenario was that some p ercentage of transformer purchase decisions are based on evaluating the total owning cost (TOC) through parameters A and B . Specifically, the default assumptions are that 50 percent of purchase

decisions for liquid

- immersed , 2 percent for low

- voltage dry

- type transformers

, and 1 0 to 20 percent for medium

- voltage, dry

- type transform ers use TOC

- type evaluations that incorporate

various distributions of values for parameters A and B. Especially at the lower candidate

standard levels (CSLs) that DOE evaluated, transformer purchases based on TOC may not satisfy the basic PBP assumptions of higher purchase price and lower operating costs for the transformers subject to the CSL . When those basic assumptions are not satisfied, the traditional PBP calculation loses its validity.

For example, a current transformer purchase decision (subject to the current standards) based on TOC may have a first cost (Δ FC = 0) that is identical to a transformer that just meet s CSL 1. In addition, the transformer that meet s the standard may have a different operating cost

from a transformer that does not . In such a situation, PBP = 0. In another example, a current transformer purchase decision based on TOC may result in a transformer that cost s more to purchase and install but consum es less electricity than a transformer that just meets baseline . In

th is case, the PBP calculation for the standards case is nonsensical, because it would imply a negative payback period.

DOE’s method of calculating PBP is shown below.

ΔFC = FC( standard )

- FC( baseline ) ( ΔFC usua lly is positive

. )

ΔOC = OC( standard )

- OC( b aseline ) ( ΔOC usua lly is negative

. )

PBP =

- ΔFC/ΔOC (For the usually positive ΔFC and the usually negative ΔOC , PBP is positive

. )

Because ΔFC can be 0 or negative, and because ΔOC also can be 0 or negative, there are nine possible situations, which can be grouped into five computational cases. Table 8.6.1 shows

the possible relationships between ΔFC and ΔOC and the resultant effect on PBP.dt_nopr_tsd_chp8_092311 DRAFT 8

- 46 Table 8.6.1 Possible ΔFC and ΔOC Combinations for Payback Period Analysis

Case # Possible Cases Effect on PBP Calculation

1 ΔFC > 0 and ΔOC < 0 Well

- defined PBP

.
2 ΔFC = 0 and ΔOC = 0 Unaffected by the standard

.

3 ΔFC < 0 and ΔOC = 0 , or ΔFC > 0 and ΔOC = 0 Division by 0 : PBP is undefined

.

4 ΔFC = 0 and ΔOC > 0 , or ΔFC = 0 and ΔOC < 0 PBP = 0

.

5 ΔFC < 0 and ΔOC < 0, or

ΔFC > 0 and ΔOC > 0, or

ΔFC < 0 and ΔOC > 0 Not valid: negative or double

- negative PBP

, PBP = 0

.

8.6.4 Results of Payback Period Analysis

Tables 8.6.2 through 8.6. 14 illustrate, for each of the 1 4 design lines and their 7 candidate standard levels, the mean PBP and the percentage of the 10,000 Monte Carlo simulations to
which the PBP calculation applies. For every CSL for each design line, the sum of the categories

“Transformers Having Well

- Defined Payback Period,” and “Tr ansformers H aving Undefined Payback Period” should equal 100 percent. a

8.6.5 Results for Design Line 1 As the efficiency of the CSLs increases, so does the percentage of purchase decisions in which the PBP i s well defined. DOE calculates the PBP both for a distribution of transformers. The PBP for the national average transformer is calculated using the average values of the first cost increase and operating cost savings.

Table 8.6.2 summarizes results of the PBP analysis for the representative unit from design line 1, a 50

- kVA, liquid

- immersed, single

- phase, pad

- mount ed transformer. The average efficiency of the baseline units selected during the LCC analysis was 99.14 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax, was $2,259; the installation cost was $2,162.

Table 8.6.2 Results of Payback Period Analysis : Representative Unit, Design Line 1

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 30.7 8.8 8.8 11.6 16.3 26.2 26.2

Median Payback (Years) 19.6 8.4 8.4 10.0 13.5 20.3 20.3

Transformers having Well Defined Payback (%) 70.93% 84.45% 84.46% 87.69% 90.36% 96.31% 96.31%

Transformers having Undefined Payback (%) 29.07% 15.55% 15.54% 12.31% 9.64% 3.69% 3.69%

Mean Incremental First Cost ($) 2,253 2,313 2,314 2,360 2,449 2,591 2,591

a For simplicity of presentation, c ases 3, 4

, and 5 , shown in Table 8.6.1

, were combined into the “Transformers

H aving Undefined Payback Period” category in Tables 8.6.2 through 8.6.1 4

.dt_nopr_tsd_chp8_092311 DRAFT 8

- 47 Mean Operating Cost Savings ($) 178 138 137 132 122 116 116

8.6.6 Results for Design Line 2

Table 8.6.3 summarizes results of the PBP analysis for the representative unit from design line 2, a 25

- kVA, liquid

- immersed, single

- phase, pole

- mounted transformer. The average efficiency of the baseli ne units selected during the LCC analysis was 98.96 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax, was $1,365; the installation cost was $1,608.

Table 8.6.3 Results of Payback Period Analysis: Representative Unit, Design Line 2

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 17.4 12.6 13.3 16.6 25.9 31.3 35.6

Median Payback (Years) 9.7 9.7 10.1 11.7 19.2 23.5 27.6

Transformers having Well Defined Payback (%) 86.19% 88.33% 88.95% 92.68% 95.78% 98.65% 99.63%

Transformers having Undefined Payback (%) 13.81% 11.67% 11.05% 7.32% 4.22% 1.35% 0.37%

Mean Incremental First Cost ($) 1,768 1,795 1,804 1,845 2,017 2,051 1,946

Mean Operating Cost Savings ($) 87 80 80 78 72 68 65

8.6.7 Results for Design Line 3

Table 8.6.4 summarizes results of the PBP analysis for the representative unit from design line 3, a 500

- kVA, liquid

- immersed, single

- phase distribution transformer. The average efficiency of the baseline units selected during the LCC analysis was 99.51 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax, was $9,519; the installatio n cost was $4,343.

Table 8.6.4 Results of Payback Period Analysis: Representative Unit, Design Line 3

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 6.6 7.6 6.2 5.9 6.5 13.0 23.6

Median Payback (Years) 4.2 4.3 4.9 4.9 5.2 8.3 14.4

Transformers having Well Defined Payback (%) 48.83% 54.49% 71.08% 72.09% 75.28% 89.38% 98.22%

Transformers having Undefined Payback (%) 51.17% 45.51% 28.92% 27.91% 24.72% 10.62% 1.78%

Mean Incremental First Cost ($) 4,395 4,434 4,538 4,554 4,612 4,994 5,608

Mean Operating Cost Savings ($) 1,208 1,177 1,041 1,023 966 805 703dt_nopr_tsd_chp8_092311 DRAFT 8

- 48 8.6.8 Results for Design Line 4

Table 8.6.5 summarizes results of the PBP analysis for the representative unit from design line 4, a 150

- kVA, liquid

- immersed, three

- phase distribution transformer. The average efficiency of the baselin e units selected during the LCC analysis was 99.23 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax, was $5,902; the installation cost was $3,964.

Table 8.6.5 Results of Payback Period Analysis: Representative Unit, Design Line 4

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 12.9 6.5 6.5 6.5 6.9 19.7 32.9

Median Payback (Years) 11.7 6.2 6.2 6.2 6.3 11.3 20.9

Transformers having Well Defined Payback (%) 64.45% 64.45% 64.45% 64.45% 66.50% 88.58% 99.91%

Transformers having Undefined Payback (%) 35.55% 35.55% 35.55% 35.55% 33.50% 11.42% 0.09%

Mean Incremental First Cost ($) 4,160 4,222 4,222 4,222 4,232 4,570 4,664

Mean Operating Cost Savings ($) 492 419 419 419 415 365 305

8.6.9 Results for Design Line 5

Table 8.6.6 summarizes results of the PBP analysis for the representative unit from design line 5, a 1 ,500

- kVA, liquid

- immersed, three

- phase distribution transformer. The average efficiency of the baseline units selected during the LCC analysis was 99.45 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, and sales tax, was $26,553; the installati on cost was $11,199.

Table 8.6.6 Results of Payback Period Analysis: Representative Unit, Design Line 5

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 16.9 15.7 13.1 13.2 12.7 17.7 17.7

Median Payback (Years) 8.8 12.4 14.2 14.5 13.8 16.2 16.2

Transformers having Well Defined Payback (%) 75.90% 86.47% 92.98% 94.63% 99.22% 100.00% 100.00%

Transformers having Undefined Payback (%) 24.10% 13.53% 7.02% 5.37% 0.78% 0.00% 0.00%

Mean Incremental First Cost ($) 11,235 12,214 13,480 13,768 14,531 11,274 11,274

Mean Operating Cost Savings ($) 4,318 4,097 3,880 3,829 3,496 2,761 2,761

8.6.10 Results for Design Line 6

Table 8.6.7 summarizes results of the PBP analysis for the representative unit from design line 6, a 25

- kVA, low

- voltage, dry

- type, three

- phase transformer with a 10

- kV basic impulse insulation level (BI L). The average efficiency of the baseline units selected during thedt_nopr_tsd_chp8_092311 DRAFT 8

- 49 LCC analysis was 98.33. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $1,006; the installation cost was $900.

Table 8.6.7 Results of Payback Period Analysis: Representative Unit, Design Line 6

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) NA 17.4 14.5 17.6 16.0 19.8 41.7

Median Payback (Years) NA 15.4 13.4 16.3 15.6 19.2 40.0

Transformers having Well Defined Payback (%) 0.00% 97.75% 99.73% 99.97% 100.00% 100.00% 100.00%

Transformers having Undefined Payback (%) 100.00% 2.25% 0.27% 0.03% 0.00% 0.00% 0.00%

Mean Incremental First Cost ($) 0 111 138 417 508 781 1,871

Mean Operating Cost Savings ($) 0 8 11 27 34 43 50

8.6.11 Results for Design Line 7

Table 8.6.8 summarizes results of the PBP analysis for the representative unit from design line 7, a 75

- kVA, low

- voltage, dry

- type, three

- phase transformer with a 10

- kV BIL. The average efficiency of the baseline units selected during the LCC analysis was 98.41 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $2, 557; the installation cost was $1,604.

Table 8.6.8 Results of Payback Period Analysis: Representative Unit, Design Line 7

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 0.1 0.6 1.1 11.1 9.5 9.8 25.7

Median Payback (Years) 0.0 0.0 0.0 5.6 8.1 9.0 23.4

Transformers having Well Defined Payback (%) 22% 62% 73% 97% 100% 100% 100%

Transformers having Undefined Payback (%) 78% 38% 27% 3% 0% 0% 0%

Mean Incremental First Cost ($)

- 10

- 20

- 7 325 711 1,097 3,337

Mean Operating Cost Savings ($) 17 40 44 63 97 131 153

8.6.12 Results for Design Line 8

Table 8.6.9 summarizes results of the PBP analysis for the representative unit from design line 8, a 300

- kVA, low

- voltage, dry

- type, three

- phase transformer with a 20

- kV BIL. The average efficiency of t he baseline units selected during the LCC analysis was 98.67 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $6,144; the installation cost wa s $2,734.dt_nopr_tsd_chp8_092311 DRAFT 8

- 50 Table 8.6.9 Results of Payback Period Analysis: Representative Unit, Design Line 8

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 7.0 4.2 4.4 8.0 7.3 7.3 20.9

Median Payback (Years) 6.5 4.0 4.0 7.6 7.0 7.0 19.7

Transformers having Well Defined Payback (%) 90.58% 92.93% 96.65% 100.00% 100.00% 100.00% 100.00%

Transformers having Undefined Payback (%) 9.42% 7.07% 3.35% 0.00% 0.00% 0.00% 0.00%

Mean Incremental First Cost ($) 649 912 1,118 3,196 3,281 3,291 10,522

Mean Operating Cost Savings ($) 110 241 289 442 491 492 557

8.6.13 Results for Design Line 9

Table 8.6.10 summarizes results of the PBP analysis for the representative unit from design line 9, a 300

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 45

- kV BIL. The average efficiency of the baseline units selected during the LCC analysis was 98.86 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $10, 717; the installation cost was $3,157.

Table 8.6.10 Results of Payback Period Analysis: Representative Unit, Design Line 9

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 1.9 3.8 10.6 9.5 13.0 22.2 22.2

Median Payback (Years) 1.8 3.1 9.3 8.9 12.2 20.6 20.6

Transformers having Well Defined Payback (%) 88.67% 98.40% 99.87% 100.00% 100.00% 100.00% 100.00%

Transformers having Undefined Payback (%) 11.33% 1.60% 0.13% 0.00% 0.00% 0.00% 0.00%

Mean Incremental First Cost ($) 290 753 3,386 4,391 6,859 12,111 12,111

Mean Operating Cost Savings ($) 164 249 382 511 585 617 617

8.6.14 Results for Design Line 10

Table 8.6.11 summarizes results of the PBP analysis for the representative unit from design line 10, a 1 ,500

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 45

- kV

BIL. The average efficienc y of the baseline units selected during the LCC analysis was 99.28 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $37,303; the installation cost was $6,328.

Table 8.6.11 Results of Payback Period Analysis: Representative Unit, Design Line 10

Candidate Standard Leveldt_nopr_tsd_chp8_092311 DRAFT 8

- 51 1 2 3 4 5 6 7

Mean Payback (Years) 8.2 14.9 16.6 14.8 16.5 25.2 25.2

Median Payback (Years) 5.2 11.1 14.5 14.1 15.5 23.1 23.1

Transformers having Well Defined Payback (%) 92.30% 98.93% 99.91% 100.00% 100.00% 100.00% 100.00%

Transformers having Undefined Payback (%) 7.70% 1.07% 0.09% 0.00% 0.00% 0.00% 0.00%

Mean Incremental First Cost ($) 1,119 5,611 14,638 16,183 20,807 35,727 35,727

Mean Operating Cost Savings ($) 210 536 1,051 1,213 1,423 1,641 1,641

8.6.15 Results for Design Line 11

Table 8.6.12 summarizes results of the PBP analysis for the representative unit from design line 11, a 300

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 95

- kV

BIL. The average efficiency of the baseline units selected during the LCC analysis was 98.70 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $16, 358; the installation cost was $3,755.

Table 8.6.12 Results of Payback Period Analysis: Representative Unit, Design Line 11

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 15.8 21.1 12.8 12.2 14.0 20.9 20.9

Median Payback (Years) 11.4 17.0 12.0 11.9 13.5 20.0 20.0

Transformers having Well Defined Payback (%) 95.25% 99.07% 100.00% 100.00% 100.00% 100.00% 100.00%

Transformers having Undefined Payback (%) 4.75% 0.93% 0.00% 0.00% 0.00% 0.00% 0.00%

Mean Incremental First Cost ($) 1,250 3,275 4,494 4,926 7,213 12,644 12,644

Mean Operating Cost Savings ($) 111 203 389 434 557 665 665

8.6.16 Results for Design Line 12

Table 8.6.13 summarizes results of the PBP analysis for the representative unit from design line 12, a 1 ,500

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 95

- kV

BIL. The average efficiency of the baseline units selected during the LCC analysis was 99.14 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $44,886; the installation

c ost was $6,773.

Table 8.6.13 Results of Payback Period Analysis: Representative Unit, Design Line 12

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 9.9 9.9 14.7 14.3 14.4 16.1 23.8

Median Payback (Years) 6.3 6.7 10.6 13.5 13.7 15.0 21.7dt_nopr_tsd_chp8_092311 DRAFT 8

- 52 Transformers having Well Defined Payback (%) 91.10% 97.59% 98.83% 100.00% 100.00% 100.00% 100.00%

Transformers having Undefined Payback (%) 8.90% 2.41% 1.17% 0.00% 0.00% 0.00% 0.00%

Mean Incremental First Cost ($) 2,603 4,629 10,060 18,184 22,242 27,410 43,835

Mean Operating Cost Savings ($) 427 728 1,009 1,416 1,725 1,938 2,138

8.6.17 Results for Design Line 13 A

Table 8.6.14 summarizes results of the PBP analysis for the representative unit from design line 13, a 2,000

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 125

- kV

BIL. The average efficienc y of the baseline units selected during the LCC analysis was 98.66 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $23,567; the installation cost was $4,562.

Table 8.6.14 Results of Payback Period Analysis: Representative Unit, Design Line

13 A

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 14.9 15.8 19.3 15.7 16.1 30.9 30.9

Median Payback (Years) 10.5 12.6 15.9 15.4 15.7 29.3 29.3

Transformers having Well Defined Payback (%) 94.62% 99.24% 99.81% 100.00% 100.00% 100.00% 100.00%

Transformers having Undefined Payback (%) 5.38% 0.76% 0.19% 0.00% 0.00% 0.00% 0.00%

Mean Incremental First Cost ($) 1,139 2,023 3,373 6,307 8,549 19,052 19,052

Mean Operating Cost Savings ($) 107 169 222 432 572 686 686

8.6.18 Results for Design Line 13B

Table 8.6.14 summarizes results of the PBP analysis for the representative unit from design line 13, a 2,000

- kVA, medium

- voltage, dry

- type, three

- phase transformer with a 125

- kV

BIL. The average efficiency of the baseline units selected during the LCC analysis was 99.18 percent. The customer equipment cost before installation, which includes the manufacturer selling price, distributor markup, contractor markup, and sales tax, was $60,907; the inst allation cost was $8,485.

Table 8.6.15 Results of Payback Period Analysis: Representative Unit, Design Line

13B

Candidate Standard Level

1 2 3 4 5 6 7

Mean Payback (Years) 11.6 10.3 13.1 17.9 14.9 17.3 17.3

Median Payback (Years) 7.0 9.0 11.6 16.1 14.5 16.8 16.8

Transformers having Well Defined Payback (%) 88.90% 99.68% 99.90% 99.93% 100.00% 100.00% 100.00%dt_nopr_tsd_chp8_092311 DRAFT 8

- 53 Transformers having Undefined Payback (%) 11.10% 0.32% 0.10% 0.07% 0.00% 0.00% 0.00%

Mean Incremental First Cost ($) 2,776 7,515 13,333 21,788 26,857 38,839 38,839

Mean Operating Cost Savings ($) 385 873 1,198 1,427 1,950 2,421 2,421

Error! Reference source not found. illustrates the full PBP results from the Monte Carlo simulation as a histogram for one example design line and CSL. The LCC spreadsheet tool can be used to generate s imilar histograms for all design lines and each CSL.

Figure 8.6.1 Distribution of Payback Period Results for Design Line 2, Candidate Standard Level 2

8.7 REBUTTABLE PRESUMPTI ON

The rebuttable presumption is a simplified method of determining the economic justification of a proposed ene rgy efficiency standard. In evaluating the rebuttable presumption, DOE estimates the additional cost of purchasing a more efficient, standard

- compliant equipment

, then compares that cost to the value of the energy savings during the first year of operation as determined by the applicable test procedure. The rebuttable presumption that such a standard level is economically justified is satisfied i f the additional first cost is less than three times the

v alue of the energy savings ( when the rebuttable payback period is less than three years).

The payback period for the rebuttable presumption differs from payback periods presented in earlier parts of this chapter in two important ways

.dt_nopr_tsd_chp8_092311 DRAFT 8

- 54 **•** The rebuttable presumption payback period uses test procedure loading levels to evaluate losses, rather than DOE’s estimate of in

- service loading conditions.

**•** T he payback period considers only the value of energy savings , not total operating

costs . In the case of distribution transformers, however, DOE estimates that the

cha nge in operating costs is due solely to energy savings.

There are three key inputs to calculation of the payback period for the rebuttable presumption : (1) average efficiency

, (2) average installed cost

, and (3) the cost of electricity. Given the average efficiency of a transformer, DOE calculated the losses on the transformer assuming the loading conditions from the test procedure. Multiplying the losses times the cost of electricity provided the operating cost . Then, dividing incremental operating costs into incremental installed cost provided the estimate of the rebuttable payback period.

Tables 8.7.1 through 8. 7

. 3 show the inputs t o the calculation of the rebuttable presumption payback period. Table 8.7.1 shows the average transformer efficiency as a function of design line and standard level for CSL 1 through CSL 7 . This is the average efficiency as determined by the customer choice model from the LCC calculation. The customer choice model provides a range of transformer design efficiencies that depends on a distribution of customer choices with respect to the value that customers place on reducing transformer design losses.

Table 8.7. 2 show s the average installed cost of the transformer as a function of both design line

and CSL

. T he average marg inal cost of electricity is a function of transformer type : for liquid

immersed transformers it is estimated to be 0.67 $/kWh ; for dry

- type transformers

, 0.059 $/kWh

. The difference between the two marginal cost s of electricity reflects the fact that liquid

immersed transformers tend to be owned by utilities, which pay the wholesale (rather than retail) cost of electricity. Table 8.7 .3 show s the first

- year operating cost for the transformer , which is

the annual losses calculated based on the test proc edure assumptions times the average marginal cost of electricity.dt_nopr_tsd_chp8_092311 DRAFT 8

- 55 Table 8.7.1 Average Transformer Efficiency %

Design

Line Rated Capacity

kVA Candidate Standard Level

Base 1 2 3 4 5 6 7

1 50 99.08% 99.16% 99.22% 99.25% 99.31% 99.42% 99.50% 99.50%

2 25 98.91% 99.00% 99.07% 99.11% 99.18% 99.31% 99.41% 99.46%

3 500 99.42% 99.48% 99.51% 99.54% 99.57% 99.61% 99.69% 99.73%

4 150 99.08% 99.16% 99.22% 99.25% 99.31% 99.42% 99.50% 99.60%

5 1500 99.42% 99.48% 99.51% 99.54% 99.57% 99.61% 99.69% 99.69%

6 25 98.00% 98.23% 98.47% 98.60% 98.80% 98.93% 99.17% 99.44%

7 75 98.00% 98.23% 98.47% 98.60% 98.80% 98.93% 99.17% 99.44%

8 300 98.60% 98.80% 99.02% 99.14% 99.25% 99.32% 99.44% 99.58%

9 300 98.82% 98.99% 99.12% 99.28% 99.38% 99.50% 99.59% 99.59%

10 1500 99.22% 99.31% 99.40% 99.50% 99.53% 99.60% 99.67% 99.67%

11 300 98.67% 98.81% 98.94% 99.06% 99.13% 99.32% 99.50% 99.50%

12 1500 99.12% 99.21% 99.30% 99.39% 99.46% 99.53% 99.59% 99.65%

13A 300 98.63% 98.76% 98.85% 98.92% 99.10% 99.29% 99.48% 99.48%

13B 2000 99.15% 99.23% 99.31% 99.38% 99.43% 99.49% 99.58% 99.58%

Table 8.7.2 Average Transformer Installed Cost ($2010)

Design

Line Rated Capacity

kVA Candidate Standard Level

Base 1 2 3 4 5 6 7

1 50 $4,42 0 $2,472 $4,909 $4,909 $5,056 $5,403 $5,982 $5,982

2 25 $2,973 $3,312 $3,370 $3,393 $3,477 $3,931 $4,230 $4,539

3 500 $13,863 $14,352 $14,544 $15,207 $15,298 $15,654 $17,845 $21,703

4 150 $9,867 $10,634 $10,889 $10,889 $10,889 $10,918 $12,270 $15,409

5 1500 $34,372 $38,177 $40,101 $41,463 $41,935 $45,597 $66,539 $66,539

6 25 $1,906 $1,906 $2,018 $2,044 $2,323 $2,414 $2,687 $3,777

7 75 $4,161 $4,151 $4,141 $4,154 $4,485 $4,871 $5,258 $7,498

8 300 $8,879 $9,527 $9,791 $9,996 $12,074 $12,159 $12,170 $19,400

9 300 $13,874 $14,165 $14,627 $17,260 $18,265 $20,733 $25,986 $25,986

10 1500 $43,640 $44,767 $49,248 $58,272 $59,826 $64,447 $79,362 $79,362

11 300 $20,113 $21,363 $23,388 $24,606 $25,039 $27,326 $32,757 $32,757

12 1500 $51,660 $54,262 $56,288 $61,719 $69,844 $73,902 $79,069 $95,494

13A 300 $28,129 $29,268 $30,153 $31,503 $34,436 $36,678 $47,181 $47,181

13 B 2000 $69,392 $72,168 $76,907 $82,724 $91,180 $96,249 $108,231 $108,231dt_nopr_tsd_chp8_092311 DRAFT 8

- 56 Table 8.7.3 First

- Year Operating Cost for Rebuttable Presumption Based on DOE

Test Procedure ($2010)

Design

Line Rated Capacity

kVA Candidate Standard Level

Base 1 2 3 4 5 6 7

1 50 $288 $256 $233 $233 $218 $186 $161 $161

2 25 $175 $152 $144 $142 $136 $111 $100 $92

3 500 $1,624 $1,519 $1,494 $1,346 $1,323 $1,241 $998 $832

4 150 $767 $676 $605 $605 $605 $599 $492 $396

5 1500 $4,940 $4,620 $4,413 $4,194 $4,137 $3,765 $2,967 $2,967

6 25 $152 $152 $142 $138 $126 $115 $99 $85

7 75 $343 $327 $302 $296 $260 $251 $195 $146

8 300 $993 $844 $706 $649 $488 $446 $443 $322

9 300 $1,212 $1,050 $930 $725 $620 $501 $424 $424

10 1500 $3,638 $3,381 $2,870 $2,324 $2,160 $1,840 $1,493 $1,493

11 300 $1,354 $1,185 $1,065 $942 $889 $693 $513 $513

12 1500 $4,388 $3,738 $3,315 $2,902 $2,690 $2,254 $1,920 $1,600

13A 300 $1,374 $1,221 $1,145 $1,076 $929 $725 $532 $532

13B 2000 $5,322 $4,795 $4,291 $3,840 $3,535 $3,390 $2,676 $2,676

Table 8.7.4 shows the rebuttable payback period as a function of design line and standard

level. The data indicate the rebuttable presumption is for design line s 7 and 9. For design line 7 the rebuttable presumption payback is satisfied for all CSLs up to CSL 3; while for design line 9

it is satisfied for c andidate standard level 1 only.dt_nopr_tsd_chp8_092311 DRAFT 8

- 57 Table 8.7.4 Payback Period for Rebuttable Presumption

Design

Line Rated Capacity

kVA Candidate Standard Level

1 2 3 4 5 6 7

1 50 16.4 9.6 9.5 10.1 11.6 17.3 17.3

2 25 18.8 16.1 15.7 15.2 18.0 20.6 23.2

3 500 6.9 8.0 6.1 5.8 5.7 9.9 18.0

4 150 12.9 6.6 6.6 6.6 6.7 13.7 23.1

5 1500 13.5 14.0 11.7 11.5 10.7 18.3 18.3

6 25 NA ** 14.8 11.3 17.6 14.7 16.4 32.3

7 75 0.1 * 0.5 0.9 7.4 10.7 8.7 20.2

8 300 5.3 3.5 3.7 7.1 6.7 6.6 17.7

9 300 2.0 3.3 8.4 8.3 10.9 17.9 17.9

10 1500 7.2 10.4 13.2 12.4 13.4 19.9 19.9

11 300 10.7 15.2 12.1 11.5 12.1 17.1 17.1

12 1500 6.4 6.5 10.1 12.3 12.0 13.1 18.9

13A 300 10.8 11.8 14.7 15.4 14.4 25.9 25.9

13B 2000 9.2 9.2 10.8 14.7 15.3 16.0 16.0

* Values less than 3 indicate a rebuttable presumption that the standard level is economically justified. ** Not applicabledt_nopr_tsd_chp8_092311 DRAFT 8

- 58 REFERENCES

1. National Electrical Manufacturers Association NEMA Standards Publication TP 1

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

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Life

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Transformers BID #09

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- 59 15. Energy Information Administration

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operations/rpm/rpm

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