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CHAPTER 2. ANALYTICAL FRAMEWORK

TABLE OF CONTENTS

2.1 INTRODUCTION ........................................................................................................... 2-1

2.2 BACKGROUND ............................................................................................................. 2-4

2.3 MARKET AND TECHNOLOGY ASSESSMENT ...................................................... 2-11

2.4 SCREENING ANALYSIS ............................................................................................ 2-11

2.5 ENGINEERING ANALYSIS ........................................................................................ 2-12

2.6 MARKUPS AND INSTALLATION COST ANALYSIS ............................................ 2-13

2.7 ENERGY USE ANALYSIS .......................................................................................... 2-13

2.8 LIFE-CYCLE COST AND PAYBACK PERIOD ANALYSIS ................................... 2-14

2.9 SHIPMENTS ANALYSIS ............................................................................................ 2-15

2.10 NATIONAL IMPACT ANALYSIS .............................................................................. 2-16

2.10.1 National Energy Savings Analysis..................................................................... 2-16

2.10.2 Net Present Value Analysis ............................................................................... 2-16

2.11 CUSTOMER SUBGROUP ANALYSIS ....................................................................... 2-17

2.12 MANUFACTURER IMPACT ANALYSIS.................................................................. 2-17

2.13 EMPLOYMENT IMPACT ANALYSIS ....................................................................... 2-18

2.14 UTILITY IMPACT ANALYSIS ................................................................................... 2-18

2.15 EMISSIONS ANALYSIS .............................................................................................. 2-19

2.15.1 Carbon Dioxide .................................................................................................. 2-19

2.15.2 Sulfur Dioxide .................................................................................................... 2-20

2.15.3 Nitrogen Oxides ................................................................................................. 2-21

2.15.4 Mercury .............................................................................................................. 2-21

2.15.5 Particulate Matter ............................................................................................... 2-21

2.16 MONETIZATION OF EMISSIONS REDUCTIONS................................................... 2-22

2.17 REGULATORY IMPACT ANALYSIS ....................................................................... 2-23

LIST OF FIGURES

Figure 2.1.1 Flow Diagram of Analyses for the Energy Conservation Standards 

Rulemaking Analysis Process ........................................................................ 2-2
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CHAPTER 2. ANALYTICAL FRAMEWORK

2.1 INTRODUCTION

Section 6295(o)(2)(A) of 42 United States Code (U.S.C.) requires the U.S. Department of 

Energy (DOE) to set forth energy conservation standards that are technologically feasible and 

economically justified, and would achieve the maximum improvement in energy efficiency. This 

chapter provides a description of the general analytical framework that DOE uses in developing 

such standards. The analytical framework is a description of the methodology, the analytical 

tools, and relationships among the various analyses that are part of this rulemaking. For example, 

the methodology that addresses the statutory requirement for economic justification includes 

analyses of life-cycle cost (LCC), economic impact on manufacturers and users, national 

benefits, impacts, if any, on utility companies, and impacts, if any, from lessening competition 

among manufacturers.

Figure 2.1.1 summarizes the stages and analytical components of the rulemaking process. 

The focus of this figure is the center column, which lists the analyses that DOE conducts. The 

figure shows how the analyses fit into the rulemaking process, and how they relate to each other. 

Key inputs are the types of data and information that the analyses require. Some key inputs exist 

in public databases; DOE collects other inputs from stakeholders or persons with special 

knowledge. Key outputs are analytical results that feed directly into the standards-setting 

process. Arrows connecting analyses show types of information that feed from one analysis to 

another. 
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Figure 2.1.1 Flow Diagram of Analyses for the Energy Conservation Standards 

Rulemaking Analysis Process 
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The analyses performed prior to the notice of proposed rulemaking (NOPR) stage as part 

of the preliminary analyses and described in the preliminary technical support document (TSD) 

are listed below. These analyses were revised for the NOPR based in part on comments received, 

and are reported in this NOPR TSD. The analyses were revised once again for the final rule 

based on any new comments or data received in response to the NOPR.

• A market and technology assessment to characterize the relevant equipment markets and 

existing technology options, including prototype designs. 

• A screening analysis to review each technology option and determine if it is 

technologically feasible; is practical to manufacture, install, and service; would adversely 

affect equipment utility or equipment availability; or would have adverse impacts on 

health and safety.

• An engineering analysis to develop cost-efficiency relationships that show the 

manufacturer’s cost of achieving increased efficiency. 

• An energy use analysis to determine the annual energy use in the field of the considered 

equipment as a function of efficiency level.

• An LCC and payback period (PBP) analysis to calculate, at the consumer level, the 

relationship between savings in operating costs compared to any increase in the installed 

cost for equipment at higher efficiency levels. 

• A shipments analysis to forecast equipment shipments, which then are used to calculate 

the national impacts of standards and future manufacturer cash flows. 

• A national impact analysis (NIA) to assess the impacts at the national level of potential 

energy conservation standards for each of the considered equipment, as measured by the 

net present value (NPV) of total consumer economic impacts and the national energy 

savings (NES). 

• A preliminary manufacturer impact analysis to assess the potential impacts of energy 

conservation standards on manufacturers, such as impacts on capital conversion 

expenditures, marketing costs, shipments, and research and development costs. 

The additional analyses DOE performed for the NOPR stage of the rulemaking analysis 

include those listed below. DOE further revised the analyses for the final rule based on 

comments received in response to the NOPR. 

• A consumer subgroup analysis to evaluate impacts of standards on particular consumer 

sub-populations, such as low-income households. 
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• A manufacturer impact analysis to estimate the financial impact of standards on 

manufacturers and to calculate impacts on competition, employment, and manufacturing 

capacity.

• An employment impact analysis to assess the indirect impacts of energy conservation 

standards on national employment. 

• A utility impact analysis to estimate the effects of energy conservation standards on 

installed electricity generation capacity and electricity generation. 

• An emissions analysis to provide estimates of the effects of energy conservation 

standards on emissions of carbon dioxide (CO2), nitrogen oxides (NOx), and mercury 

(Hg) and to evaluate the monetary benefits likely to result from the reduced emissions of 

CO2 and NOx. 

• A regulatory impact analysis to assess alternatives to energy conservation standards that 

could achieve substantially the same regulatory goal.

2.2 BACKGROUND

In a notice published on October 22, 1997 (62 FR 54809), DOE stated that it had 

determined that energy conservation standards were warranted for electric distribution 

transformers, relying in part on two reports by DOE’s Oak Ridge National Laboratory (ORNL). 

These reports —Determination Analysis of Energy Conservation Standards for Distribution 

Transformers, ORNL-6847 (1996) and Supplement to the “Determination Analysis,” ORNL6847 (1997)—are available on the DOE docket at: 

http://www.regulations.gov/#!docketDetail;D=EERE-2006-STD-0099. In 2000, DOE issued its 

Framework Document for Distribution Transformer Energy Conservation Standards 

Rulemaking, describing its proposed approach for developing standards for distribution 

transformers, and held a public meeting to discuss the Framework Document. The document is 

available on the above-referenced DOE website. Stakeholders also submitted written comments 

on the document, addressing a range of issues. 

Subsequently, DOE issued draft reports as to certain of the key analyses contemplated by 

the Framework Document.a

 

a Copies of all the draft analyses published before the ANOPR are available on DOE’s website: 

 It received comments from stakeholders on these draft reports and, 

on July 29, 2004, published an advance notice of proposed rulemaking (ANOPR) for distribution 

transformer standards. 69 FR 45376. DOE then held a webcast on material it had published 

relating to the ANOPR, followed by a public meeting on the ANOPR on September 28, 2004. In 

http://www.regulations.gov/#!docketDetail;D=EERE-2006-STD-0099.. 
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August 2005, DOE issued a draft of certain of the analyses on which it planned to base the 

standards for liquid-immersed and medium-voltage, dry-type distribution transformers, along 

with documents that supported the draft analyses.b

 DOE did this to enable stakeholders to 

review the analyses and make recommendations as to standard levels.

On April 27, 2006, DOE published its Final Rule on Test Procedures for Distribution 

Transformers. The rule: (1) established the procedure for sampling and testing distribution 

transformers so that manufacturers can make representations as to their efficiency, as well as 

establish that they comply with Federal standards; and (2) contained enforcement provisions, 

outlining the procedure the Department would follow should it initiate an enforcement action 

against a manufacturer. 71 FR 24972 (codified at 10 CFR 431.198). 

On August 4, 2006, DOE published a NOPR in which it proposed energy conservation 

standards for distribution transformers (the 2006 NOPR). 71 FR 44355. Concurrently, DOE also 

issued a technical support document (TSD) that incorporated the analyses it had performed for 

the proposed rule, including several spreadsheets that remain available on DOE’s website.c

 

Some commenters asserted that DOE’s proposed standards might adversely affect 

replacement of distribution transformers in certain space-constrained (e.g., vault) installations. In 

response, DOE issued a notice of data availability and request for comments on this and another 

issue. 72 FR 6186 (Feb. 9, 2007) (the NODA). In the NODA, DOE sought comment on whether 

it should include in the LCC analysis potential costs related to size constraints of distribution 

transformers installed in vaults. DOE also outlined different approaches as to how it might 

account for additional installation costs for these space-constrained applications and requested 

comments on linking energy efficiency levels for three-phase liquid-immersed units with those 

of single-phase units. Finally, DOE addressed how it was inclined to consider a final standard 

that is based on energy efficiency levels derived from trial standard level (TSL) 2 and TSL 3 for 

three-phase units and TSLs 2, 3 and 4 for single-phase units. 72 FR 6189. Based on comments on 

the 2006 NOPR, and the NODA, DOE created new TSLs to address the treatment of three-phase 

units and single-phase units. In October 2007, DOE published a final rule that created the current 

energy conservation standards for liquid-immersed and medium-voltage dry-type distribution 

transformers. 72 FR 58190 (October 12, 2007) (the 2007 Final Rule) (codified at 10 CFR 

431.196(b)-(c)).

 

b Copies of the four draft NOPR analyses published in August 2005 are available on DOE’s website: 

http://www.regulations.gov/#!docketDetail;D=EERE-2006-STD-0099. 

c The spreadsheets developed for this rulemaking proceeding are available at: 

http://www.regulations.gov/#!docketDetail;D=EERE-2006-STD-0099. 
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The above paragraphs summarize development of the 2007 Final Rule. The preamble to 

the rule included additional, detailed background information on the history of that rulemaking. 

72 FR 58194-96. 

After the publication of the 2007 Final Rule, certain parties filed petitions for review in 

the United States Courts of Appeals for the Second and Ninth Circuits, challenging the rule. 

Several additional parties were permitted to intervene in support of these petitions. (All of these 

parties are referred to below collectively as “petitioners.”) The petitioners alleged that, in 

developing its energy conservation standards for distribution transformers, DOE did not comply 

with certain applicable provisions of EPCA and of the National Environmental Policy Act 

(NEPA), as amended (42 U.S.C. 4321 et seq.) DOE and the petitioners subsequently entered into 

a settlement agreement to resolve the petitions. The settlement agreement outlined an expedited 

timeline for the Department to determine whether to amend the energy conservation standards 

for liquid-immersed and medium-voltage dry-type distribution transformers. Under the original 

settlement agreement, DOE was required to publish by October 1, 2011, either a determination 

that the standards for these distribution transformers do not need to be amended or a NOPR that 

includes any new proposed standards and that meets all applicable requirements of EPCA and 

NEPA. Under an amended settlement agreement, the October 1, 2011, deadline for a DOE 

determination or proposed rule was extended to February 1, 2012. If DOE finds that amended 

standards are warranted, DOE agreed to publish a final rule containing such amended standards 

by October 1, 2012. 

On March 2, 2011, DOE published in the Federal Register a notice of public meeting and 

availability of its preliminary TSD for the Distribution Transformer Energy Conservation 

Standards Rulemaking, wherein DOE discussed and received comments on issues such as 

equipment classes of distribution transformers that DOE would analyze in consideration of 

amending the energy conservation standards for distribution transformers, the analytical 

framework, models and tools it is using to evaluate potential standards, the results of its 

preliminary analysis, and potential standard levels. 76 FR 11396. The notice is available on the 

above-referenced DOE website. To expedite the rulemaking process, DOE began at the 

preliminary analysis stage because it believes that many of the same methodologies and data 

sources that were used during the 2007 rulemaking rule remain valid. On April 5, 2011, DOE 

held a public meeting to discuss the preliminary TSD. Representatives of manufacturers, trade 

associations, electric utilities, energy conservation organizations, Federal regulators, and other 

interested parties attended this meeting. In addition, other interested parties submitted written 

comments about the TSD addressing a range of issues. These comments are discussed in the 

various sections of the NOPR and final rule. 
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On July 29, 2011, DOE published in the Federal Register a notice of intent to establish a 

subcommittee under the Energy Efficiency and Renewable Energy Advisory Committee 

(ERAC), in accordance with the Federal Advisory Committee Act and the Negotiated 

Rulemaking Act, to negotiate proposed Federal standards for the energy efficiency of mediumvoltage dry-type and liquid immersed distribution transformers. 76 FR 45471. Stakeholders 

strongly supported a consensual rulemaking effort. DOE believed that, in this case, a negotiated 

rulemaking would result in a better informed NOPR and would minimize any potential negative 

impact of the NOPR. On August 12, 2011, DOE published in the Federal Register a similar 

notice of intent to negotiate proposed Federal standards for the energy efficiency of low-voltage 

dry-type distribution transformers. 76 FR 50148. The purpose of the subcommittee was to 

discuss and, if possible, reach consensus on a proposed rule for the energy efficiency of 

distribution transformers. 

The ERAC subcommittee for medium-voltage liquid-immersed and dry-type distribution 

transformers consisted of representatives of parties having a defined stake in the outcome of the 

proposed standards, listed below. 

• ABB Inc.

• AK Steel Corporation 

• American Council for an Energy-Efficient Economy

• American Public Power Association

• Appliance Standards Awareness Project

• ATI-Allegheny Ludlum

• Baltimore Gas and Electric 

• Cooper Power Systems 

• Earthjustice

• Edison Electric Institute

• Fayetteville Public Works Commission

• Federal Pacific Company

• Howard Industries Inc.

• LakeView Metals

• Efficiency and Renewables Advisory Committee member

• Metglas, Inc.

• National Electrical Manufacturers Association

• National Resources Defense Council

• National Rural Electric Cooperative Association

• Northwest Power and Conservation Council 

• Pacific Gas and Electric Company
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• Progress Energy

• Prolec GE

• U.S. Department of Energy 

The ERAC subcommittee for medium-voltage liquid-immersed and dry-type distribution 

transformers held meetings on September 15 through 16, 2011, October 12 through 13, 2011, 

November 8 through 9, 2011, and November 30 through December 1, 2011; the ERAC 

subcommittee also held public webinars on November 17 and December 14. During the course 

of the September 15, 2011, meeting, the subcommittee agreed to its rules of procedure, ratified 

its schedule of the remaining meetings, and defined the procedural meaning of consensus. The 

subcommittee defined consensus as unanimous agreement from all present subcommittee 

members. Subcommittee members were allowed to abstain from voting for an efficiency level; 

their votes counted neither toward nor against the consensus. 

DOE presented its draft engineering, life-cycle cost and national impacts analysis and 

results during meetings held September 15 through 16, 2011. During the meetings of October 12 

through 13, 2011, DOE presented its revised analysis and heard from subcommittee members on 

a number of topics. During the meetings on November 8 through 9, 2011, DOE presented its 

revised analysis, including life-cycle cost sensitivities based on exclusion ZDMH and amorphous 

steel as core materials. During the meetings on November 30 through December 1, 2011, DOE 

presented its revised analysis based on 2011 core-material prices. 

At the conclusion of the final meeting, subcommittee members presented their efficiency 

level recommendations. For medium-voltage, liquid-immersed distribution transformers, the 

energy efficiency Advocates, represented by the Appliance Standards Awareness Project 

(ASAP), recommended efficiency level (also referred to as “EL”) 2 for all design lines (also 

referred to as “DLs”). The National Electrical Manufacturers Association (NEMA) and AK Steel 

recommended EL 1 for all DLs except for DL 2, for which no change from the current standard 

was recommended. Edison Electric Institute (EEI) and ATI Allegheny Ludlum recommended 

EL1 for DLs 1, 3, and 4 and no change from the current standard or a proposed standard of less 

than EL 1 for DLs 2 and 5. Therefore, the subcommittee did not arrive at consensus regarding 

proposed standard levels for medium-voltage, liquid-immersed distribution transformers. 

For medium-voltage, dry-type distribution transformers, the subcommittee arrived at consensus 

and recommended a proposed standard of EL2 for DLs 11 and 12, from which the proposed 

standards for DLs 9, 10, 13A, and 13B would be scaled. Transcripts of the subcommittee 

meetings and all data and materials presented at the subcommittee meetings are available via a 
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link under the DOE website at: 

http://www1.eere.energy.gov/buildings/appliance_standards/rulemaking.aspx/ruleid/44. 

The ERAC subcommittee held meetings on September 28, 2011, October 13-14, 2011, 

November 9, 2011, and December 1-2, 2011, for low-voltage distribution transformers. The 

ERAC subcommittee also held webinars on November 21, 2011, and December 20, 2011. 

During the course of the September 28, 2011, meeting, the subcommittee agreed to its rules of 

procedure, finalized the schedule of the remaining meetings, and defined the procedural meaning 

of consensus. The subcommittee defined consensus as unanimous agreement from all present 

subcommittee members. Subcommittee members were allowed to abstain from voting for an 

efficiency level; their votes counted neither toward nor against the consensus. 

The ERAC subcommittee for low-voltage distribution transformers consisted of 

representatives of parties having a defined stake in the outcome of the proposed standards. 

• AK Steel Corporation 

• American Council for an Energy-Efficient Economy

• Appliance Standards Awareness Project

• ATI-Allegheny Ludlum

• EarthJustice

• Eaton Corporation 

• Federal Pacific Company

• Lakeview Metals

• Efficiency and Renewables Advisory Committee member

• Metglas, Inc.

• National Electrical Manufacturers Association

• Natural Resources Defense Council

• ONYX Power

• Pacific Gas and Electric Company

• Schneider Electric

• U.S. Department of Energy 

DOE presented its draft engineering, life-cycle cost and national impacts analysis and 

results on September 28, 2011. During the meetings of October 14, 2011, DOE presented its 

revised analysis and heard from subcommittee members on various topics. During the meetings 

of November 9, 2011, DOE presented its revised analysis. During the meetings of December 1, 

2011, DOE presented its revised analysis based on 2011 core-material prices. 
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At the conclusion of the final meeting, subcommittee members presented their energy efficiency 

level recommendations. For low-voltage, dry-type distribution transformers, the Advocates, 

represented by ASAP, recommended EL4 for all DLs; NEMA recommended EL 2 for DLs 7 and 

8, and no change from the current standard for DL 6. EEI; AK Steel and ATI Allegheny Ludlum 

recommended EL 1 for DLs 7 and 8, and no change from the current standard for DL 6. The 

subcommittee did not arrive at consensus regarding a proposed standard for low-voltage, drytype distribution transformers. Transcripts of the subcommittee meetings and all data and 

materials presented at the subcommittee meetings are available at the DOE website at: 

http://www1.eere.energy.gov/buildings/appliance_standards/rulemaking.aspx/ruleid/44. 

DOE published a Notice of Proposed Rulemaking on February 10, 2012, which proposed 

amended standards for all three transformer types. 77 FR 7282. Medium-voltage, dry-type 

distribution transformers were proposed at the negotiating committee’s consensus level. Liquidimmersed distribution transformers were proposed at TSL 1. Low-voltage, dry-type distribution 

transformers were proposed at TSL 1. In the NOPR, DOE sought comment on a number of 

issues related to the rulemaking until April 10, 2012. In response to several comments suggesting 

DOE should analyze new TSLs and equipment classes, DOE published a Notice of Public 

Meeting announcing the availability of additional NOPR analysis a public meeting to be held to 

discuss it. 77 FR 32916. 

Following publication of the NOPR, DOE received several comments expressing a desire 

to see some of the NOPR suggestions extended and analyzed for liquid-immersed distribution 

transformers. In response, DOE generated a supplementary NOPR analysis with three additional 

TSLs. The three TSLs presented were based on possible new equipment classes for polemounted distribution transformers, network/vault-based distribution transformers, and those with 

high basic impulse level (BIL) ratings. On June 4, 2012 DOE published a notice announcing the 

availability of this supplementary analysisd

 and of a public meeting to be held on June 20, 2012 

to present and receive feedback on it. DOE also generated an additional TSL in a June 18, 2012 

analysis published on DOE’s website. 

Following the public meeting, DOE received comment from a number of stakeholders on 

the supplementary NOPR analysis for liquid-immersed transformers. Although comment varied, 

DOE concluded that many stakeholders believed the new equipment classes presented within the 

supplementary analysis were not warranted at the standard levels under consideration in the 

NOPR. As a result, DOE adopted the liquid-immersed energy conservation levels of the NOPR 

in the final rule.

 

d 77 FR 32916
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2.3 MARKET AND TECHNOLOGY ASSESSMENT

When initiating a standards rulemaking, DOE develops information on the present and 

past industry structure and market characteristics for the equipment concerned. This activity 

assesses the industry and equipment both quantitatively and qualitatively based on publicly 

available information and encompasses the following: (1) manufacturer market share and 

characteristics, (2) existing regulatory and non-regulatory equipment efficiency improvement 

initiatives, and (3) trends in equipment characteristics and retail markets. This information serves 

as resource material throughout the rulemaking. 

DOE reviewed existing literature and interviewed manufacturers to get an overall picture 

of the industry serving the United States market. Industry publications and trade journals, 

government agencies, trade organizations, and equipment literature provided the bulk of the 

information, including: (1) manufacturers and their approximate market shares, (2) equipment 

characteristics, and (3) industry trends. The appropriate sections of the NOPR describe the 

analysis and resulting information leading up to the proposed trial standard levels, while 

supporting documentation is provided in the TSD. 

DOE categorizes covered equipment into separate equipment classes and formulates a 

separate energy conservation standard for each equipment class. The criteria for separation into 

different classes are type of energy used, capacity, and other performance-related features such 

as those that provide utility to the consumer or others deemed appropriate by the Secretary that 

would justify the establishment of a separate energy conservation standard. (42 U.S.C. 6295(q) 

and 6316(a)) 

As part of the market and technology assessment, DOE developed a list of technologies 

for consideration for improving the efficiency of distribution transformers. DOE typically uses 

information about existing and past technology options and prototype designs to determine 

which technologies manufacturers use to attain higher performance levels. In consultation with 

interested parties, DOE develops a list of technologies for consideration. Initially, these 

technologies encompass all those DOE believes are technologically feasible.

DOE developed its list of technologically feasible design options for distribution 

transformers from trade publications, technical papers, research conducted in support of previous 

rulemakings concerning these equipment, and through consultation with manufacturers of 

components and systems. Since many options for improving equipment efficiency are available 

in existing equipment, equipment literature and direct examination provided additional 

information. Chapter 3 of the TSD includes the detailed list of all technology options identified. 

2.4 SCREENING ANALYSIS

After DOE identified the technologies that could potentially improve the energy 

efficiency of distribution transformers, DOE conducted the screening analysis. The purpose of 
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the screening analysis is to evaluate these technologies to determine which options to consider 

further and which options to screen out.

The screening analysis examines whether various technologies (1) are technologically 

feasible; (2) are practicable to manufacture, install, and service; (3) have an adverse impact on 

equipment utility or availability; and (4) have adverse impacts on health and safety. In 

consultation with interested parties, DOE reviews the list to determine if the technologies 

described in chapter 3 of the TSD are practicable to manufacture, install, and service; would 

adversely affect equipment utility or availability; or would have adverse impacts on health and 

safety. In the engineering analysis, DOE further considers the efficiency enhancement options 

(i.e., technologies) that it did not screen out in the screening analysis. Chapter 4 of the TSD 

contains further detail on the criteria that DOE uses.

2.5 ENGINEERING ANALYSIS

The engineering analysis establishes the relationship between the manufacturing 

production cost and the efficiency of distribution transformers. This relationship serves as the 

basis for cost/benefit calculations in terms of individual consumers, manufacturers, and the 

Nation. Chapter 5 discusses equipment classes DOE analyzed, the representative baseline units, 

the efficiency levels analyzed, the methodology DOE used to develop the manufacturing 

production costs, and the cost-efficiency curves.

In the engineering analysis, DOE evaluates a range of equipment efficiency levels and 

their associated manufacturing costs. The purpose of the analysis is to estimate the incremental 

manufacturer selling prices (MSPs) for equipment that would result from increasing efficiency 

levels above the level of the baseline model in each equipment class. The engineering analysis 

considers technologies not eliminated in the screening analysis. The LCC analysis and NIA use 

the cost-efficiency relationships developed in the engineering analysis. 

DOE typically structures its engineering analysis around one of three methodologies: (1) 

the design-option approach, which calculates the incremental costs of adding specific design 

options to a baseline model; (2) the efficiency-level approach, which calculates the relative costs 

of achieving increases in energy efficiency levels without regard to the particular design options 

used to achieve such increases; and/or (3) the reverse-engineering or cost-assessment approach, 

which involves a “bottom-up” manufacturing cost assessment based on a detailed bill of 

materials derived from teardowns of the equipment being analyzed. 

For the final rule analysis, DOE primarily used the design-option approach to develop its 

relationships for cost and efficiency for distribution transformers. DOE developed a 

manufacturing cost model for distribution transformers based on reverse engineering of 

purchased equipment. DOE estimated costs for these efficiency improvements based on the 

manufacturing cost model, information from component vendors, and information obtained 
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through discussions with manufacturers. Chapter 5 of the TSD describes the methodology that 

DOE used to perform the efficiency level analysis and derive the cost-efficiency relationship. 

2.6 MARKUPS AND INSTALLATION COST ANALYSIS

DOE uses markups to convert the manufacturer selling prices estimated in the 

engineering analysis to customer prices, which are used in the LCC, PBP, national impact, and 

manufacturer impact analyses. DOE calculates a separate markup for the baseline component of 

equipment cost (baseline markup) and for the incremental increase in cost due to standards 

(incremental markup).

To develop markups, DOE identifies how the equipment is distributed from the 

manufacturer to the customer. After establishing appropriate distribution channels, DOE used 

data from the financial filings of manufacturers and distributors and other sources to determine 

how prices are marked up as the equipment passes from the manufacturer to the end customer. 

To develop installation costs, DOE identifies how the increase in equipment weight 

results in increased installation costs. After identifying this relationship, DOE used data from 

manufactures and utilities to determine how installation costs change with equipment weight. 

DOE also accounted for circumstances where installing a new transformer on an existing utility 

pole may not be possible due to increased transformer weight, and will require the installation of 

a new utility pole.

See chapter 6 of the TSD for details on the development of markups and installation 

costs. 

2.7 ENERGY USE ANALYSIS

The energy use analysis, which assesses the energy savings potential from higher 

efficiency levels, provides the basis for the energy savings values used in the LCC and 

subsequent analyses. The goal of the energy use analysis is to generate a range of energy use 

values that reflects actual equipment use in the field. The analysis uses information on use of 

actual equipment in the field to estimate the energy that would be used by new equipment at 

various efficiency levels. 

 Distribution transformers consume energy via both no-load losses and load losses. Noload losses, which are constant over time, occur whenever a transformer is energized by power 

lines. Load losses vary with the square of the load the transformer is serving. There are two types 

of distribution transformers: liquid-immersed and dry-type. Liquid-immersed transformers are 

owned primarily by electric utilities. Utilities pay marginal costs for the power used to generate 

electricity, costs that can vary by the hour. DOE therefore developed a statistical simulation 

model to estimate the hourly load characteristics of liquid-immersed transformers and to develop 
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a correlation between hourly loads and system loads. Dry-type transformers are owned by 

commercial and industrial (C&I) establishments, which are billed for electricity according to a 

tariff. For dry-type distribution transformers, DOE used empirical estimates of load 

characteristics to estimate monthly average (root mean square) loads and peak coincident loads. 

Chapter 7 of the TSD provides more detail about DOE’s approach for characterizing 

energy use of distribution transformers. 

2.8 LIFE-CYCLE COST AND PAYBACK PERIOD ANALYSIS 

New or amended energy conservation standards affect equipment’s operating expenses—

usually decreasing them—and consumer prices for the equipment—usually increasing them. 

DOE analyzed the net effect of standards on consumers by evaluating the net change in LCC. To 

evaluate the net change in LCC, DOE used the cost-efficiency relationship derived in the 

engineering analysis along with the energy costs derived from the energy use analysis. Inputs to 

the LCC calculation include the installed cost of equipment to the consumer (consumer purchase 

price plus installation cost), operating expenses (energy expenses and maintenance costs), the 

lifetime of the unit, and a discount rate. These inputs are described in detail in chapter 8 of the 

TSD.

Because the installed cost of equipment typically increases while operating cost typically 

decreases in response to new standards, there is a time in the life of equipment having higherthan-baseline efficiency when the operating-cost benefit (in dollars) since the time of purchase is 

equal to the incremental first cost of purchasing the higher-efficiency equipment. The length of 

time required for equipment to reach this cost-equivalence point is known as the payback period 

(PBP).

Recognizing that several inputs used to determine consumer LCC and PBP are either 

variable or uncertain, DOE conducted the LCC and PBP analyses by modeling both the 

uncertainty and variability in the inputs using Monte Carlo simulation and probability 

distributions. DOE developed an LCC and PBP spreadsheet model that incorporates both Monte 

Carlo simulation and probability distributions by using Microsoft Excel spreadsheets combined 

with Crystal Ball, a commercially available add-in program. 

For distribution transformers, it was necessary to determine the input values for a wide 

arrange of electricity costs that are seen by distribution transformer owners. DOE performed two 

electricity price analyses to determine the appropriate marginal prices for (1) liquid-immersed 

distribution transformers owned primarily by utility companies and (2) dry-type distribution 

transformers owned primarily by C&I building owners. For utility companies, the appropriate 

marginal price is the hourly system lambda or market-clearing price. For building owners, the 

electricity prices are derived from a tariff-based analysis. The two approaches are described in 

more detail below.
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For liquid-immersed transformers, DOE based its energy price analysis on hourly system 

load and system lambda data collected from FERC (for regions without wholesale markets) or on 

hourly system load and day-ahead market clearing price data. In both cases, these prices 

represent the operating cost to the utility of meeting the next increment of load at any given time. 

In any given hour, a utility’s marginal price can be higher or lower than its average price; in 

general the hourly price can be represented as a function of the system load level. 

In addition to the hourly energy cost, there is a capacity cost saving associated with 

improved transformer efficiency. If the efficiency of a utility’s transformers is increased, then 

the utility will require less generation and transmission capacity to serve its customers’ load. The 

size of the capacity savings is dependent on the total reduction in load over all the transformers 

owned by the utility during the hour of system peak. The reduction in system-coincident 

transformer peak load is determined by the joint probability distribution function between system 

and transformer loads. The cost of capacity is estimated using the 2010 annual auction clearing 

prices for regions with functioning capacity markets and using capacity cost factors from the 

Energy Information Agency's Updated Capital Estimates for Electricity Generating Plants, 2010, 

for the other regions. 

For C&I building owners of dry-type transformers, DOE used marginal prices derived 

from a detailed analysis of utility tariffs (Coughlin et al., 2006). The tariff data and calculation 

tools were first developed by DOE for use in the Commercial Unitary Air Conditioning 

rulemaking. (U.S. Department of Energy, July, 2004). 

For each of the CBECS 1992 and 1995 records used in the building sample, DOE used the 

monthly energy consumption and demand data, along with tariff data, to calculate a baseline 

electricity bill. To obtain marginal prices, two additional calculations were done. Because the 

electricity bill depends on both energy consumption and demand, separate marginal prices are 

needed to represent the effect of varying these two quantities independently. The monthly 

marginal energy consumption (or demand) price is calculated simply by decrementing the energy 

consumption (or demand) and recalculating the bill. The tariff data were collected in 2004. To 

update prices to the analysis year (2010), two other datasets were used: the report Average 

Regulated Retail Price of Electricity (Regulatory Research Associates, 2008) was used to 

estimate price increases between 2004 and 2007; and the Typical Bill and Average Price Reports 

(Edison Electric Institute, 2007–2010) was used to estimate price increases from 2007 to 2010. 

The LCC and PBP analysis is described in more detail in chapter 8 of the TSD.

2.9 SHIPMENTS ANALYSIS

Forecasts of equipment shipments are needed to calculate the potential effects of 

standards on national energy use, NPV, and future manufacturer cash flows. DOE generated both 

shipments and efficiency forecasts for each equipment class. The shipments forecast calculates 

the total number of distribution transformers shipped each year over a 30 year period, beginning 
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in 2016 and ending in 2045. To create this forecast, DOE combined current year shipments, 

discussed in the market assessment (chapter 3), with a compound annual growth rate for 

distribution transformers and generated unit shipment values through the analysis period. The 

efficiency forecast shows the distribution of shipments of distribution transformers by trial 

standard level (TSL), which determines the percentage of shipments affected by a standard. To 

develop its efficiency forecast, DOE first assessed present-day (2012) efficiency and then 

considered how the efficiency of new units might change by the first year of the analysis period 

(2016) and throughout the analysis period in the absence of new or amended Federal standards. 

Chapter 9 of the TSD provides additional details on the shipments analysis. 

2.10 NATIONAL IMPACT ANALYSIS

The national impact analysis estimates energy savings and assesses the NPV of consumer 

benefits at the national scale. The results can be used to identify the TSL that, for a given 

equipment class, yields the greatest energy savings while remaining cost effective. DOE 

estimated both NES and NPV for all candidate standard levels for each distribution transformer 

equipment class. To make the analysis more accessible and transparent to all interested parties, it 

is documented in a Microsoft Excel spreadsheet model that can be downloaded from the EERE 

website.

The NIA considers total installed cost (which includes manufacturer selling prices, 

distribution chain markups, sales taxes, and installation costs), operating expenses (energy, 

repair, and maintenance costs), equipment lifetime, and discount rate. However, where the LCC 

considers the savings and costs associated with standards for a set of representative units, the 

NIA considers the savings and costs associated with all units affected by standards during the 

entire analysis period. Chapter 10 provides additional details regarding the NIA. 

2.10.1 National Energy Savings Analysis 

The major inputs for determining the NES for equipment analyzed are annual unit energy 

consumption, shipments, lifetimes, and site-to-source conversion factors. DOE calculated 

national energy consumption for each year by multiplying unit energy consumption by the 

number of units in the installed base in that year. NES for a given year, then, is the difference in 

national energy consumption between the base case (without new efficiency standards) and each 

standards case. DOE estimated energy consumption and savings first in terms of site energy and 

then converted the savings into source energy. Cumulative energy savings are the sum of the 

NES estimates for each year.

2.10.2 Net Present Value Analysis

The inputs for determining net present value (NPV) of consumer benefits are: (1) total 

annual installed cost; (2) total annual savings in operating costs; (3) a discount factor; (4) present 
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value of costs; and (5) present value of savings. DOE calculated net savings each year as the 

difference between the base case and each standards case in total savings in operating costs and 

total increases in installed costs. DOE calculated savings over the life of equipment, accounting 

for differences in yearly electricity rates. DOE calculated NPV as the difference between the 

present value of operating cost savings and the present value of total installed costs. DOE used a 

discount factor based on real discount rates of 3% and 7% to discount future costs and savings to 

present values.

DOE calculated increases in total installed costs as the difference in total installed cost 

between the base case and standards case (i.e., once the standards take effect). Because the more 

efficient equipment bought in the standards case usually cost more than equipment bought in the 

base case, cost increases appear as negative values in the NPV.

DOE expressed savings in operating costs as decreases associated with the lower energy 

consumption of equipment bought in the standards case compared to the base case. Total savings 

in operating costs are the product of savings per unit and the number of units of each vintage that 

survive in a given year. 

2.11 CUSTOMER SUBGROUP ANALYSIS

The customer subgroup analysis evaluates economic impacts on selected groups of 

customers who might be adversely affected by a change in the national energy conservation 

standards for the considered equipment. DOE performed LCC subgroup analyses for utilities that 

have underground distribution systems that use vault-installed transformers. DOE evaluated the 

potential LCC impacts and PBPs for these customers using the LCC spreadsheet model. Chapter 

11 of the TSD provides more detail. 

2.12 MANUFACTURER IMPACT ANALYSIS 

DOE performed a manufacturer impact analysis (MIA) to estimate the financial impact of 

energy conservation standards on manufacturers of distribution transformers, and to calculate the 

impact of such standards on employment and manufacturing capacity. The MIA has both 

quantitative and qualitative aspects. The quantitative part of the MIA relies on the government 

regulatory impact model (GRIM), an industry-cash-flow model customized for this rulemaking. 

The GRIM inputs are information regarding the industry cost structure, shipments, and revenues. 

This includes information from many of the analyses described above, such as manufacturing 

costs and prices from the engineering analysis and shipments forecasts. The key GRIM output is 

the industry net present value (INPV). Different sets of assumptions (scenarios) will produce 

different results. The qualitative part of the MIA addresses factors such as equipment 

characteristics, characteristics of particular firms, and market and equipment trends, and includes 

assessment of the impacts of standards on subgroups of manufacturers. The complete MIA is 

described in chapter 12 of the TSD. 
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DOE conducted each MIA in this rulemaking in three phases. In Phase I, DOE created an 

industry profile to characterize the industry and identify important issues that require 

consideration. In Phase II, DOE prepared an industry cash-flow model and an interview 

questionnaire to guide subsequent discussions. In Phase III, DOE interviewed manufacturers and 

assessed the impacts of standards both quantitatively and qualitatively. DOE assessed industry 

and subgroup cash flow and NPV using the GRIM. DOE then assessed impacts on competition, 

manufacturing capacity, employment, and regulatory burden based on manufacturer interview 

feedback and discussions. 

2.13 EMPLOYMENT IMPACT ANALYSIS

The adoption of energy conservation standards can affect employment both directly and 

indirectly. Direct employment impacts are changes in the number of employees at the plants that 

produce the covered products, along with affiliated distribution and service companies. DOE will 

evaluate direct employment impacts in the MIA.

Indirect employment impacts may result from expenditures shifting between goods (the 

substitution effect) and changes in income and overall expenditure levels (the income effect) that 

occur due to standards. DOE defines indirect employment impacts from standards as net jobs 

eliminated or created in the general economy as a result of increased spending driven by 

increased product prices and reduced spending on energy. 

The indirect employment impacts will be investigated in the employment impact analysis 

using the Pacific Northwest National Laboratory’s “Impact of Sector Energy Technologies” 

(ImSET) model.e

2.14 UTILITY IMPACT ANALYSIS

 The ImSET model was developed for DOE’s Office of Planning, Budget, and 

Analysis to estimate the employment and income effects of energy-saving technologies in 

buildings, industry, and transportation. Compared with simple economic multiplier approaches, 

ImSET allows for more complete and automated analysis of the economic impacts of energy 

conservation investments. Further detail is provided in chapter 13 of the TSD. 

To estimate the impacts of potential energy conservation standards for furnace fans on 

the electric utility industry, DOE will use a variant of the EIA’s National Energy Modeling 

 

e Roop, J. M., M. J. Scott, and R. W. Schultz, ‘‘ImSET: Impact of Sector Energy Technologies,’’ PNNL–15273. 

Pacific Northwest National Laboratory (2005). 
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System called NEMS-BT.f NEMS is a large, multi-sectoral, partial-equilibrium model of the 

U.S. energy sector that EIA has developed over several years, primarily for the purpose of 

preparing the AEO. NEMS produces a widely recognized forecast for the United States through 

2035 and is available to the public. 

The utility impact analysis is a comparison between the NEMS-BT model results for the 

base case and standard cases. Outputs of the utility impact analysis usually parallel results that 

appear in the latest AEO, with some additions. The utility impact analysis reports the changes in 

installed capacity and generation that result from each standard level by plant type. DOE will 

model the anticipated energy savings impacts from potential amended energy conservation 

standards using NEMS-BT to generate forecasts that deviate from the AEO Reference Case.

Further detail is provided in chapter 14 of the TSD. 

2.15 EMISSIONS ANALYSIS

 In the emissions analysis, DOE estimated the reduction in power sector emissions of 

carbon dioxide (CO2), nitrogen oxides (NOX), and mercury (Hg) using the NEMS-BT computer 

model. In the emissions analysis, NEMS-BT is run similarly to the AEO NEMS, except that 

distribution transformers energy use is reduced by the amount of energy saved (by fuel type) due 

to each considered standard level. The inputs of national energy savings come from the NIA 

spreadsheet model, while the output is the forecasted physical emissions. The net benefit of each 

considered standard level is the difference between the forecasted emissions estimated by 

NEMS-BT at that level and the AEO 2012 Reference Case. 

2.15.1 Carbon Dioxide 

In the absence of any Federal emissions control regulation of power plant emissions of 

CO2, a DOE standard is likely to result in reductions of these emissions. The CO2 emission 

reductions likely to result from a standard will be estimated using NEMS-BT and national energy 

savings estimates drawn from the NIA spreadsheet model. The net benefit of the standard is the 

difference between emissions estimated by NEMS-BT at each standard level considered and the 

AEO Reference Case. NEMS-BT tracks CO2 emissions using a detailed module that provides 

results with broad coverage of all sectors and inclusion of interactive effects. 

 

f For more information on NEMS, please refer to the U.S. Department of Energy, Energy Information 

Administration documentation. A useful summary is National Energy Modeling System: An Overview 2000, 

DOE/EIA-0581 (March 2000), available at: http://tonto.eia.doe.gov/ftproot/forecasting/05812000.pdf. EIA approves 

use of the name NEMS to describe only an official version of the model without any modification to code or data. 

Because this analysis entails some minor code modifications and the model is run under various policy scenarios 

that are variations on EIA assumptions, DOE refers to the model by the name NEMS-BT. (“BT” refers to DOE’s 

Building Technologies Program, under whose aegis this work is performed.)
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2.15.2 Sulfur Dioxide

SO2 emissions from affected electric generating units (EGUs) are subject to nationwide 

and regional emissions cap and trading programs. Title IV of the Clean Air Act sets an annual 

emissions cap on SO2 for affected EGUs in the 48 contiguous states and the District of Columbia 

(D.C.). SO2 emissions from 28 eastern states and D.C. were also limited under the Clean Air 

Interstate Rule (CAIR), which created an allowance-based trading program that that operates 

along with the Title IV program. 70 FR 25162 (May 12, 2005). CAIR was remanded to EPA by 

the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) but it remained in 

effect. On July 6, 2011 EPA issued a replacement for CAIR, the Cross-State Air Pollution Rule 

(CSAPR). 76 FR 48208 (August 8, 2011). The AEO 2012 NEMS used for this analysis assumes 

the implementation of CSAPR.g

The attainment of emissions caps is typically flexible among affected Electric Generating 

Units (EGUs) and is enforced through the use of emissions allowances and tradable permits. 

Under existing EPA regulations, any excess SO2 emissions allowances resulting from the lower 

electricity demand caused by the imposition of an efficiency standard could be used to permit 

offsetting increases in SO2 emissions by any regulated EGU. In past rulemakings, DOE 

recognized that there was uncertainty about the effects of efficiency standards on SO2 emissions 

covered by the existing cap-and-trade system, but it concluded that no reductions in power sector 

emissions would occur for SO2 as a result of standards.

Beginning in 2015, however, SO2 emissions will fall as a result of the Mercury and Air 

Toxics Standards (MATS) for power plants, which were announced by EPA on December 21, 

2011. 77 FR 9304 (Feb. 16, 2012). In the final MATS rule, EPA established a standard for 

hydrogen chloride as a surrogate for acid gas hazardous air pollutants (HAP), and also 

established a standard for SO2 (a non-HAP acid gas) as an alternative equivalent surrogate 

standard for acid gas HAP. The same controls are used to reduce HAP and non-HAP acid gas; 

thus, SO2 emissions will be reduced as a result of the control technologies installed on coal-fired 

power plants to comply with the MATS requirements for acid gas. AEO 2012 assumes that, in 

order to continue operating, coal plants must have either flue gas desulfurization or dry sorbent 

injection systems installed by 2015. Both technologies, which are used to reduce acid gas 

emissions, also reduce SO2 emissions. Under the MATS, NEMS shows a reduction in SO2

emissions when electricity demand decreases (e.g.

 

g On December 30, 2011, the D.C. Circuit stayed the new rules while a panel of judges reviews them, and told EPA 

to continue administering CAIR. See EME Homer City Generation, LP v. EPA, Order, No. 11-1302, Slip Op. at *2 

(D.C. Cir. Dec. 30, 2011). On August 21, 2012, the D.C. Circuit vacated CSAPR. See EME Homer City 

Generation, LP v. EPA, No. 11-1302, 2012 WL 3570721 at *24 (D.C. Cir. Aug. 21, 2012). The court ordered EPA 

to continue administering CAIR. AEO 2012 had been finalized prior to both these decisions, however. DOE 

understands that CAIR and CSAPR are similar with respect to their effect on emissions impacts of energy 

efficiency standards.

, as a result of energy efficiency standards). 

Emissions will be far below the cap that would be established by CSAPR, so it is unlikely that 

excess SO2 emissions allowances resulting from the lower electricity demand would be needed 
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or used to permit offsetting increases in SO2 emissions by any regulated EGU. Therefore, DOE 

believes that efficiency standards will reduce SO2 emissions in 2015 and beyond. 

2.15.3 Nitrogen Oxides

Under CAIR, there is a cap on NOX emissions in 28 eastern states and the District of 

Columbia. All these States and D.C. have elected to reduce their NOX emissions by participating 

in cap-and-trade programs for EGUs. Therefore, energy conservation standards for distribution 

transformers may have little or no physical effect on these emissions in the 28 eastern states and 

the D.C. for the same reasons that they may have little or no physical effect on NOX emissions. 

DOE used the NEMS-BT to estimate NOX emissions reductions from possible standards in the 

States where emissions are not capped.

2.15.4 Mercury

On February 16, 2012, EPA issued national emissions standards for hazardous air 

pollutants (NESHAPs) for mercury and certain other pollutants emitted from coal and oil-fired 

EGUs. 77 FR 9304. The NESHAPs do not include emissions caps and, as such, DOE’s energy 

conservation standards would likely reduce Hg emissions. 

2.15.5 Particulate Matter

DOE acknowledges that particulate matter (PM) exposure can impact human health. 

Power plant emissions can have either direct or indirect impacts on PM. A portion of the 

pollutants emitted by a power plant are in the form of particulates as they leave the smoke stack. 

These are direct, or primary, PM emissions. However, the great majority of PM emissions 

associated with power plants are in the form of secondary sulfates, which are produced at a 

significant distance from power plants by complex atmospheric chemical reactions that often 

involve the gaseous (non-particulate) emissions of power plants, mainly SO2 and NOX. The 

quantity of the secondary sulfates produced is determined by a very complex set of factors 

including the atmospheric quantities of SO2 and NOX, and other atmospheric constituents and 

conditions. Because these highly complex chemical reactions produce PM comprised of different 

constituents from different sources, EPA does not distinguish direct PM emissions from power 

plants from the secondary sulfate particulates in its ambient air quality requirements, PM 

monitoring of ambient air quality, or PM emissions inventories. For these reasons, it is not 

currently possible to determine how the standards would impact either direct or indirect PM 

emissions. Therefore, DOE is not planning to assess the impact of these standards on PM 

emissions. Further, as described previously, it is uncertain whether efficiency standards will 

result in a net decrease in power plant emissions of SO2, which are now largely regulated by cap 

and trade systems.
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2.16 MONETIZATION OF EMISSIONS REDUCTIONS 

DOE plans to consider the estimated monetary benefits likely to result from the reduced 

emissions of CO2 and NOX that are expected to result from each of the standard levels 

considered. 

In order to estimate the monetary value of benefits resulting from reduced emissions of 

CO2 emissions, DOE used in its analysis the most current Social Cost of Carbon (SCC) values 

developed and/or agreed to by interagency reviews. The SCC is intended to be a monetary 

measure of the incremental damage resulting from greenhouse gas (GHG) emissions, including, 

but not limited to, net agricultural productivity loss, human health effects, property damage from 

sea level rise, and changes in ecosystem services. Any effort to quantify and to monetize the 

harms associated with climate change will raise serious questions of science, economics, and 

ethics. But with full regard for the limits of both quantification and monetization, the SCC can be 

used to provide estimates of the social benefits of reductions in GHG emissions. 

At the time of this analysis, the most recent interagency estimates of the potential global 

benefits resulting from reduced CO2 emissions in 2011 were $4.9, $22.3, $36.5, and $67.6 per 

metric ton in 2011 dollars. For emissions reductions that occur in later years, these values grow 

in real terms over time. Additionally, the interagency group determined that a range of values 

from 7 percent to 23 percent should be used to adjust the global SCC to calculate domestic 

effects, although DOE will give preference to consideration of the global benefits of reducing 

CO2 emissions. To calculate a present value of the stream of monetary values, DOE will discount 

the values in each of the four cases using the discount rates that had been used to obtain the SCC 

values in each case.

DOE recognizes that scientific and economic knowledge continues to evolve rapidly as to 

the contribution of CO2 and other GHG to changes in the future global climate and the potential 

resulting damages to the world economy. Thus, these values are subject to change. 

DOE also estimates the potential monetary benefit of reduced NOX emissions resulting 

from the standard levels it considers. For NOX emissions, available estimates suggest a very wide 

range of monetary values, ranging from $450 to $4,623 per ton in 2011$).h In accordance with 

U.S. Office of Management and Budget (OMB) guidance, DOE conducts two calculations of the 

monetary benefits derived using each of the economic values used for NOx, one using a real 

discount rate of 3 percent and another using a real discount rate of 7 percent.i

DOE did not monetize estimates of Hg reduction in this rulemaking. DOE has decided to 

await further guidance regarding consistent valuation and reporting of Hg emissions before it 

once again monetizes Hg in its rulemakings. 

 

h

 For additional information, refer to U.S. Office of Management and Budget, Office of Information and Regulatory 

Affairs, 2006 Report to Congress on the Costs and Benefits of Federal Regulations and Unfunded Mandates on 

State, Local, and Tribal Entities, Washington, DC. i

OMB, Circular A-4: Regulatory Analysis (Sept. 17, 2003).
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Further detail on the emissions monetization is provided in chapter16 of the TSD. 

2.17 REGULATORY IMPACT ANALYSIS

DOE prepared a regulatory impact analysis (RIA) pursuant to Executive Order 12866, 

Regulatory Planning and Review, 58 FR 51735, October 4, 1993, which is subject to review by 

the Office of Information and Regulatory Affairs at the Office of Management and Budget. The 

RIA addresses the potential for non-regulatory approaches to supplant or augment energy 

conservation standards in order to improve the energy efficiency or reduce the energy 

consumption of the equipment covered under this rulemaking. 

DOE recognizes that voluntary or other non-regulatory efforts by manufacturers, utilities, 

and other interested parties can substantially affect energy efficiency or reduce energy 

consumption. DOE bases its assessment on the actual impacts of any such initiatives to date, but 

also considers information presented by interested parties regarding the impacts existing 

initiatives might have in the future. Further detail is provided in chapter 17 of the TSD.