1

Fellner, Christian

From: Wayland, Robertj

Sent: Friday, May 23, 2014 3:37 PM

To: Higgins, Cortney

Cc: Culligan, Kevin

Subject: Chapter 9 of the RIA

Attachments: EO 12866 Chapter_9_Modifications_and_Reconstructions_0523.docx

Cortney ‐ 

  

Attached please find the revised RIA Chapter 9 for the mods/recon standards.  I will be sending the revised

preamble shortly once Kevin reviews/clears it.  Also, we're planning to send you another version on Tuesday

morning that will have some NGCC language in it ‐ you will see a comment balloon in the version Kevin sends

later today that indicates what's being added and where.

  

bob

Robert J. Wayland, Ph.D.

Leader, Energy Strategies Group

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Mail Code D243‐01

Research Triangle Park, North Carolina 27709

 

Office:  (919) 541‐1045

Cell:     (919) 306‐2290

Fax:     (919) 541‐5450

 

Email:  wayland.robertj@epa.gov

 

**************************************

DRAFT/Deliberative Document ‐ FOIA EXEMPT

**************************************
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

9-1 

CHAPTER 9: BENEFITS, COSTS, AND ECONOMIC IMPACTS OF STANDARDS OF 

PERFORMANCE FOR RECONSTRUCTED AND MODIFIED ELECTRIC UTILITY 

GENERATING UNITS

9.1 Introduction 

The U.S. Environmental Protection Agency (EPA) is proposing emission limits for carbon 

dioxide (CO2) emitted from reconstructed and modified electric utility generating units (EGUs) 

under section 111(b) of the Clean Air Act (CAA). This chapter presents the proposed standards 

of performance for reconstructed and modified EGUs, as well as the expected economic impacts 

of the proposed standards. Based on historical information that has been reported to the EPA, the 

EPA anticipates few, if any, covered units will trigger the reconstruction or modification 

provisions in the period of analysis (through 2025). As a result, we do not anticipate any 

significant costs or benefits associated with this proposal. However, because there have been a 

few units that have notified EPA of modifications in the past, in this chapter we present an 

illustrative analysis of the costs and benefits for a hypothetical unit if it were to trigger the 

modification provision. We also discuss how the costs and benefits for compliance with the 

proposed standards may vary as a result of interactions with the CAA 111(d) emission guidelines 

for existing sources. This chapter also presents the relevant executive order and statutory 

requirements related to this proposal. 

9.2 Legal Basis for this Rulemaking 

Section 111 of the CAA requires performance standards for air pollutant emissions from 

categories of stationary sources that may reasonably contribute to the endangerment of public 

health or welfare. In April 2007, the Supreme Court ruled in Massachusetts v. EPA that 

greenhouse gases (GHGs) meet the definition of an “air pollutant” under the CAA. This ruling 

clarified that the authorities and requirements of the CAA apply to GHGs. The EPA issued a 

final determination that GHG emissions endanger both the public health and the public welfare 

of current and future generations in the Endangerment and Cause or Contribute Findings for 

Greenhouse Gases Under Section 202(a) of the CAA (74 FR 66,496; Dec. 15, 2009). 
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9-2 

On September 20, 2013, the EPA announced its first steps under President Obama’s 

Climate Action Plan to reduce CO2 emissions from power plants by proposing standards for new 

power plants built in the future (79 FR 1430, January 8, 2014). Specifically, under the authority 

of CAA section 111(b), the EPA proposed standards for emissions of CO2 from new utility 

boilers and integrated gasification combined cycle (IGCC) units, and for natural gas-fired 

stationary combustion turbines. This action proposes standards to address CO2 emissions from 

reconstructed and modified power plants under the authority of CAA section 111(b). 

9.3 Background for the Proposed EGU Reconstructed and Modified Source GHG 

Standards 

9.3.1 Definition of Affected Sources 

This action proposes emission limits for EGUs that undergo reconstruction or 

modification. This rulemaking does not address GHG emissions from new sources or existing 

sources that do not undertake reconstruction or modification. (Analysis of the impact of emission 

guidelines for existing sources is presented in the preceding chapters.) The EPA is proposing that 

an existing unit that becomes subject to requirements under section 111(d) will continue to be 

subject to those requirements even after it becomes a modified or reconstructed source. Under 

this interpretation, the modified or reconstructed source would be subject to both the section 

111(d) requirements that it had previously been subject to and the modified or reconstructed 

source standard under 111(b) that it became subject to as a modified or reconstructed source. 

9.3.1.1 Reconstructed Sources 

Under the EPA’s CAA section 111 standards of performance for new stationary sources, 

reconstructed sources are defined, in general, as existing sources that replace components to such 

an extent that the capital costs of the new components exceed 50 percent of the capital costs of 

an entirely new facility, and for which compliance with standards of performance for new 

sources is technologically and economically feasible. As described in the preamble, 

determinations regarding reconstructed status are made on a case-by-case basis, based on 

information submitted regarding the planned project.
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9-3 

9.3.1.2 Modified Sources 

A modification is any physical or operational change to a source that increases the source’s 

maximum achievable hourly rate of emissions (i.e., lbs/MWh). The EPA, through regulations, 

has determined that certain types of changes (such as pollution control projects) are exempt from 

consideration as a modification (40 CFR 60.2, 60.14(e)). 

9.3.2 Emission Limits 

This action proposes standards of performance for reconstructed utility boilers and IGCC 

units based on current best-performing generating technology (e.g., use of the highest 

demonstrated steam temperatures and pressures) as the best system of emission reductions 

(BSER). This action also proposes standards of performance for reconstructed natural gas-fired 

stationary combustion turbines based on modern, efficient natural gas combined cycle (NGCC) 

technology as the BSER. The proposed emission limits are calculated on a 12-month rolling 

average basis. The proposed emission limits for these units are shown in table 9-1. All existing 

sources that reconstruct after becoming subject to an approved CAA 111(d) state plan will 

remain in the plan and remain subject to regulatory requirements in the plan in addition to its 

regulatory requirements as a reconstructed unit. 

Table 9-1. Proposed Emission Limits - Reconstructions 

Subcategory Emission Limit 

Reconstructed Utility Boilers and IGCC Units (heat input rating > 2,000 MMBtu/h) 

1,900 lb CO2/MWhnet 

Reconstructed Utility Boilers and IGCC Units (heat input rating <= 2,000 MMBtu/h) 

2,100 lb CO2/MWhnet 

Reconstructed Natural Gas-Fired Stationary Combustion Turbines (heat input rating > 

850 MMBtu/h) 

1,000 lb CO2/MWhgross 

Reconstructed Natural Gas-Fired Stationary Combustion Turbines (heat input rating <= 

850 MMBtu/h) 

1,100 lb CO2/MWhgross 
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9-4 

This action proposes that modified utility boilers and IGCC units must meet one of two 

alternative requirements, depending on the timing of the modification.1

 Sources that modify prior 

to becoming subject to an approved section 111(d) state plan would be required to meet a unitspecific numerical emission standard that is based on the source’s best demonstrated historical 

performance. Specifically, a modified utility boiler or IGCC unit would be required to maintain 

an emission rate that is two percent less than the unit’s best demonstrated annual performance 

during the years from 2002 to the year the modification occurs (or the emission limitation 

applicable to a corresponding reconstructed source, whichever is less stringent). The EPA has 

determined that this standard can be met through a combination of best operating practices and 

equipment upgrades. In co-proposed alternative #2, existing utility boilers and IGCC units that 

modify after becoming subject to requirements under an approved 111(d) plan would be required 

to meet a unit-specific emission limitation that is determined from a third party assessment to 

identify energy efficiency improvement opportunities for the affected source.2

 All existing 

sources that are subject to requirements under an approved section 111(d) plan would remain 

subject to those requirements after modifying. 

For affected modified natural gas-fired stationary combustion turbines not subject to a 

111(d) plan, this action proposes standards of performance based on efficient NGCC technology 

as the BSER. The EPA is also proposing that affected stationary combustion turbines that are 

subject to an approved section 111(d) plan must remain in the plan. The proposed emission limits 

for modified sources (for co-proposed alternative #2) are shown in Table 9-2. 

 

1

 Units triggering both the modification and reconstruction provisions would be subject to the reconstructed source 

standards. 

2

 In co-proposed alternative #1, units would be required to meet the same 111(b) standard both before and after 

participation in a state 111(d) program. 
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9-5 

Table 9-2. Proposed Emission Limits - Modifications 

 Subcategory Emission Limit 

Not Subject to State 

CAA 111(d) Plan 

Modified Utility Boilers and IGCC Units 

(heat input rating > 2,000 MMBtu/h) 

2% less than unit’s best demonstrated 

annual performance 

NO LOWER THAN 

1,900 lb CO2/MWh-net 

Modified Utility Boilers and IGCC Units 

(heat input rating <= 2,000 MMBtu/h) 

2% less than unit’s best demonstrated 

annual performance 

NO LOWER THAN 

2,100 lb CO2/MWh-net 

Modified Natural Gas-Fired Stationary 

Combustion Turbines (heat input rating > 

850 MMBtu/h) 

1,000 lb CO2/MWh-gross 

Modified Natural Gas-Fired Stationary 

Combustion Turbines (heat input rating <= 

850 MMBtu/h ) 

1,100 lb CO2/MWh-gross 

After Becoming 

Subject to State CAA 

111(d) Plan 

Modified Utility Boilers and IGCC Units 

Unit-specific emission limit determined 

by the expected performance after 

implementation of identified energy 

efficiency improvement opportunities 

AND 

111(d) requirements 

Modified Natural Gas-Fired Stationary 

Combustion Turbines (heat input rating > 

850 MMBtu/h) 

1,000 lb CO2/MWh-gross 

AND 

111(d) requirements 

Modified Natural Gas-Fired Stationary 

Combustion Turbines (heat input rating <= 

850 MMBtu/h ) 

1,100 lb CO2/MWh-gross 

AND 

111(d) requirements 

Note: The proposed emission limits are calculated on a 12-month rolling average basis. 

9.4 Impacts of the Proposed Reconstructed and Modified Source Standards 

9.4.1 Reconstructed Sources 

Historically, we are only aware of one EGU that has notified the EPA that it has 

reconstructed under the reconstruction provision of section 111(b). As a result, we anticipate that 
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9-6 

few, if any, EGUs will undertake reconstruction through 2025. For this reason, the proposed 

standards will not result in any significant emission reductions, costs, or quantified benefits in 

the period of analysis. Likewise, the Agency does not anticipate any impacts on the price of 

electricity or energy supply. The proposed rule is not expected to raise any reliability resource 

adequacy concerns, since reserve margins will not be impacted and the rule does not impose any 

additional requirements on existing facilities not triggering the reconstruction provision. There 

are no macroeconomic or employment impacts expected as a result of these proposed standards. 

Due to the extremely limited data available on reconstructions, it is not possible to conduct 

a representative illustrative analysis of what costs and benefits might result from this proposal in 

the unlikely case that a unit were to reconstruct. 

9.4.2 Modified Sources 

Historically, few EGUs have notified the EPA that they have modified under the 

modification provision of section 111(b). The EPA’s current regulations define an NSPS 

“modification” as a physical or operational change that increases the source’s maximum 

achievable hourly rate of emissions, but specifically exempt from that definition projects that 

entail the installation of pollution control equipment or systems. The EPA expects that most of 

the actions EGUs are likely to take in the foreseeable future that would be classified as 

“modifications” would qualify as pollution control projects. In many cases, those projects would 

involve the installation of add-on control equipment needed to meet CAA requirements for 

criteria and air toxics air pollutants. Any associated CO2 emissions increases would generally be 

small and would occur as a chemical byproduct of the operation of the control equipment. In 

other cases, those projects would involve equipment changes to improve fuel efficiency to meet 

state requirements for implementation of the future CAA section 111(d) rulemaking for existing 

sources and would have the effect of increasing a source’s maximum achievable hourly emission 

rate (lb CO2/hr), even while decreasing its actual output based emission rate (lb CO2/MWh). 

Because all of these actions would be treated as pollution control projects under the EPA’s 

current NSPS regulations, they would be specifically exempted from the definition of 

modification. 
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9-7 

Based on this information, we anticipate that few, if any, EGUs will take actions that 

would be considered modifications during the period of analysis. For this reason, the proposed 

standards will result in minimal emission reductions, costs, or quantified benefits by 2025. 

Likewise, the Agency does not anticipate any impacts on the price of electricity or energy 

supplies. This proposed rule is not expected to raise any resource adequacyreliability concerns, 

since reserve margins will not be impacted and the rule does not impose any additional 

requirements on existing facilities not triggering the reconstruction provision. There are no 

macroeconomic or employment impacts expected as a result of these proposed standards. 

9.4.2.1 Illustrative Analysis – Emission Reductions 

In the unlikely event that a unit were to trigger the modification provision, the proposed 

standards would result in some costs and benefits. Based on available data, we conducted an 

analysis of a hypothetical unit to illustrate the potential costs and benefits of the proposed 

standards. The hypothetical plant presented in this section is a coal-fired boiler3 and is assumed 

to be in compliance with all on-the-books federal regulations. In the illustrative analysis, costs 

and benefits are presented for compliance in 2025. Section 111(b) standards are subject to review 

every eight years. While we do not know when the hypothetical plant would choose to undertake 

a modification, it is necessary to select a year of analysis in order to value the climate benefits 

and health co-benefits resulting from these proposed standards. We have selected 2025 to 

approximate the end of the eight year period. All estimates are presented in 2011 dollars. 

The hypothetical unit used in this analysis is a 33 percent efficient 500 MW bituminous coalfired unit operating at 78 percent capacity. The assumptions for capacity and efficiency were 

 

3

 IGCC and NGCC units are significantly less likely to trigger the modification provision due to the way in which 

these units are constructed. Simple-cycle combustion turbines (CT) have lower fuel efficiencies and produce a 

significantly higher cost of electricity (cost per kWh) at higher capacity factors and consequently are typically 

utilized at levels well below the proposed threshold covered sources (1/3 of potential electric output). 

Historically,Instead, these units are have most often been built to ensure reserve margins are met during peak 

periods (typically in the summer), and in some instances are able to generate additional revenues by selling 

capacity into power markets. Thus, in practice, EPA expects that potential CT units would not meet the 

applicability threshold in this proposed action and would not be subject to any standard. The EPA has received 

comments regarding more recent integration of CT units and renewables and is taking comment on the treatment 

of these units.
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9-8 

based on the average projected coal fleet in IPM in 2020. The emission rate specifications are (1) 

SO2 = 0.30 lb/MMBtu (3.3% weight Illinois bituminous coal with 95% efficient scrubber), (2) 

NOX = 0.30 lb/MMBtu (low NOX burners plus overfire air and SNCR), and (3) PM = 0.024 

lb/MMBtu (8 lb/MMBtu ash with 99.7% control). In this analysis, we examine the costs and 

benefits that would occur if this unit were able to make a 4 percent, 6 percent, or 8 percent heat 

rate improvement as a result of measures implemented in order to comply with the proposed 

standards for modified sources. 

Costs. We assume the hypothetical unit will implement a range of energy efficiency 

improvements at an annual cost of $8.3 million.4 At this cost, we estimate the typical unit would 

be able to implement a set of efficiency improvement measures that would achieve a heat rate 

improvement of approximately 6 percent. A heat rate improvement of 6 percent is approximately 

equivalent to an absolute efficiency improvement of 2 percent. The actual efficiency 

improvement a unit can achieve for this cost will depend on its starting efficiency and operating 

capacity. Less efficient units may have more efficiency improvement options available and be 

able to achieve greater efficiency for the same cost. Relatively more efficient units may have 

fewer remaining cost-effective options to improve efficiency. Improvements in efficiency will 

result in fuel savings, which can offset the cost of implementing those improvements. Cost and 

fuel savings information is shown in Table 9-3. 

For units that modify prior to being part of a section 111(d) existing source program that 

choose to comply with a source-specific standard that is a 2 percent improvement from the 

previous best performance, costs will vary depending on the current and prior performance of 

that unit. For a unit that modifies after being covered by a section 111(d) program, it is possible 

that the energy assessment may not identify any further efficiency improvements that unit can 

 

4

 Calculated based on a total capital cost of $50 million ($100/kilowatt), financed over 15 years at a capital charge 

rate of 14.29%. The capital charge rate value and useful life are based on assumptions used when modeling the 

electricity sector in the Integrated Planning Model (IPM). Please see chapter 8 of EPA’s documentation for the 

IPM for more information on the assumed capital charge rate: http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v513/Chapter_8.pdf. See the See Technical Support Document – GHG Abatement Measures” for 

information about the cost of efficiency improvements. 
***E.O. 12866 Review – Draft – Do Not Cite, Quote or Release During Review*** 

9-9 

economically undertake considering the overall 111(d) program requirements. In those cases, 

there would be no additional costs to the unit as a result of this proposal. 

Table 9-3. Annualized Costs and Fuel Savings of Efficiency Improvements (millions 

of 2011$) 

4% Efficiency 

Improvement 

6% Efficiency 

Improvement 

8% Efficiency 

Improvement 

Annual Cost $8.3 $8.3 $8.3 

Fuel Savings $3.7 $5.6 $7.5 

Net Cost $4.5 $2.6 $0.78 

Emission Reductions. By improving the efficiency of its operations, the hypothetical unit 

would reduce emissions of CO2 and may reduce emissions of (SO2), nitrogen dioxide (NOx), and 

fine particulate matter (PM2.5), which would lead to lower ambient concentrations of PM2.5 and 

ozone. Table 9-4 shows the expected emission reductions from each level of efficiency 

improvement for the hypothetical unit. For a unit participating in a 111(d) plan, it is possible that 

the CO2 emission reductions could be offset by increases elsewhere in the system depending on 

the structure of that plan. Ancillary emission reductions may be offset if, as a result of these 

reductions, a unit is able to reduce operation of pollution control equipment and still meet outputbased standards for these pollutants or pollutants related to their control (such as the Mercury 

and Air Toxics Standards limit for SO2 to control hydrogen chloride). Additionally, if efficiency 

improvements lead to decreased operating costs, it may result in changes to the frequency of 

dispatch for the unit. In that case, the unit may run more often, offsetting some of the emission 

decreases. Furthermore, for units that choose to comply with a source-specific standard that is a 

2 percent improvement from the previous best performance, emission reductions will vary 

depending on the current and prior performance of that unit. Additionally, it is possible that the 

energy assessment for a unit participating in a 111(d) program may not identify any further fuel 

efficiency improvements that unit can economically undertake after implementing the overall 

111(d) program requirements. In those cases, there would be no additional emission reductions 

or control costs as a result of this proposal. 
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Table 9-4. Emission Reductions from Efficiency Improvements (tons/year) 

4% Efficiency Improvement 6% Efficiency Improvement 8% Efficiency Improvement 

CO2 132,790 199,184 265,579 

SO2 214 321 428 

NOx (Total) 214 321 428 

NOx (Ozone Season) 89 134 178 

PM2.5 17 26 34 

Notes: SO2, NOX, and PM2.5 in short tons, CO2 in metric tonnes. 

Benefits. Reducing CO2 and criteria pollutant emissions will result in both climate and human 

health benefits. The impacts of these pollutants on the environment and health are discussed in 

detail in Chapter 4 of this RIA. In sum, to estimate climate benefits the EPA uses the U.S. 

government’s global social cost of carbon (USG SCC) estimates—i.e, the monetary value of 

impacts associated with a marginal change in CO2 emissions in a given year. The EPA has 

applied the USG SCC estimates to the CO2 reductions described above for the hypothetical unit. 

The four USG SCC estimates are as follows: $15, $50, $74, and $153 per metric ton of CO2

emissions in the year 2025 (2011$). To estimate human health co-benefits for this hypothetical 

scenario, the EPA used benefit-per-ton estimates for PM2.5 and ozone precursors described in 

detail in Chapter 4 of this RIA. Table 9-5 shows the quantified per ton co-benefits for reductions 

in SO2, directly emitted PM2.5, and NOX emissions in 2025. 

Table 9-5. Summary of National Benefit-per-ton Estimates for EGUs in 2025 

 Discount Rate 

Pollutant 3% 7% 

SO2 $41,000 to $93,000 $37,000 to $84,000 

Directly emitted PM2.5 (EC+OC) $150,000 to $350,000 $140,000 to $310,000 

Directly emitted PM2.5 (crustal) $17,000 to $39,000 $15,000 to $35,000 

NOX (as PM2.5) $6,000 to $14,000 $5,400 to $12,000 

NOX (as Ozone)* $4,900 to $21,000 

* Ozone co-benefits occur in analysis year, so they are the same for all discount rates. 

Note: See Table 4-8 for discussion of the assumptions, and uncertainty for these estimates. 

To estimate the benefits associated with improving efficiency of operations, we determine the 

emission reductions for efficiency improvements in Table 9-4 and apply the 2025 social benefit 
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9-11 

values discussed in Chapter 4. Specifically, we multiply the reduction in CO2 emissions by the 

estimates of the SCC, multiply the reduction in SO2, NOX, and PM2.5 emissions by the PM2.5-

related BPT estimates, multiply the reductions in ozone season NOX emissions by the ozonerelated BPT estimate, and add those values to get a measure of 2025 benefits. Tables 9-6, 9-7, 

and 9-8 show the climate, human health, and combined benefits expected based on the estimated 

emission reductions that would occur. These benefits are subject to the same uncertainties 

discussed for emission reductions in the previous section. 

Table 9-6. Estimated Global Climate Benefits of Illustrative CO2 Reductions in 2025 

(millions of 2011$)* 

Discount Rate and Statistic 4% Efficiency 

Improvement

6% Efficiency 

Improvement

8% Efficiency 

Improvement

Metric tonnes of CO2 reduced 132,790 199,184 265,579 

5% (average) $2.0 $3.0 $4.0 

3% (average) $6.7 $10 $13 

2.5% (average) $9.8 $15 $20 

3% (95th percentile) $20 $30 $41 

* The SCC values are dollar-year and emissions-year specific. SCC values represent only a partial accounting of 

climate impacts. 

 
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9-12 

Table 9-7. Summary of Estimated Monetized Health Co-benefits of Illustrative Efficiency 

Improvements in 2025 (thousands of 2011$)* 

Pollutant 3% Discount Rate 7% Discount Rate 

4% Efficiency Improvement 

SO2 $8,900 to $20,000 $8,000 to $18,000

Directly emitted PM2.5 (EC+OC) $260 to $590 $240 to $530

Directly emitted PM2.5 (crustal) $230 to $510 $200 to $460

NOx (as PM2.5) $1,300 to $2,900 $1,200 to $2,600

NOx (as Ozone) $440 to $1,900 $440 to $1,900

Total $11,000 to $26,000 $10,000 to $23,000

6% Efficiency Improvement 

SO2 $13,000 to $30,000 $12,000 to $27,000

Directly emitted PM2.5 (EC+OC) $400 to $900 $360 to $810

Directly emitted PM2.5 (crustal) $350 to $780 $310 to $710

NOx (as PM2.5) $1,900 to $4,300 $1,700 to $3,900

NOx (as Ozone) $660 to $2,800 $660 to $2,800

Total $17,000 to $39,000 $15,000 to $35,000

8% Efficiency Improvement 

SO2 $18,000 to $40,000 $16,000 to $36,000

Directly emitted PM2.5 (EC+OC) $520 to $1,200 $470 to $1,100

Directly emitted PM2.5 (crustal) $450 to $1,000 $410 to $930

NOx (as PM2.5) $2,600 to $5,800 $2,300 to $5,200

NOx (as Ozone) $880 to $3,800 $880 to $3,800

Total $22,000 to $52,000 $20,000 to $47,000

* All estimates are rounded to two significant figures so numbers may not sum down columns. The estimated 

monetized co-benefits do not include climate benefits or health effects from direct exposure to NO2, SO2, and 

hazardous air pollutants (HAP); ecosystem effects; or visibility impairment. All fine particles are assumed to 

have equivalent health effects. The monetized co-benefits incorporate the conversion from precursor emissions to 

ambient fine particles and ozone. Co-benefits for PM2.5 and ozone are based on national benefit-per-ton 

estimates. Co-benefits for ozone are based on ozone season NOx emissions. Ozone co-benefits occur in analysis 

year, so they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone 

co-benefits and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et 

al. (2004) to Lepeule et al. (2012) with Levy et al. (2005)). Confidence intervals are unavailable for this analysis 

because of the benefit-per-ton methodology. In general, the 95th percentile confidence interval for monetized 

PM2.5 benefits ranges from approximately -90 percent to +180 percent of the central estimates based on Krewski 

et al. (2009) and Lepeule et al. (2012). Emissions of directly emitted particles are disaggregated into EC+OC or 

crustal components using the method discussed in Appendix 4A of this RIA. 
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Table 9-8. Combined IllustrativeEstimated Climate Benefits and Health Co-Benefits of Illustrative 

Efficiency Improvements in 2025 (millions of 2011$)* 

SCC Discount Rate 

Climate 

Benefits Only 

Climate Benefits and Health Co-Benefits 

(Discount Rate Applied to Health Co-Benefits) 

3% 7% 

4% Efficiency Improvement 132,790 metric tonnes CO2 

5% $2.0 $13 to $28 $12 to $25

3% $6.7 $18 to $33 $17 to $30

2.5% $9.8 $21 to $36 $20 to $33

3% (95th percentile) $20 $31 to $46 $30 to $44

6% Efficiency Improvement 199,184 metric tonnes CO2 

5% $3.0 $20 to $42 $18 to $38

3% $10 $27 to $49 $25 to $45

2.5% $15 $31 to $53 $30 to $50

3% (95th percentile) $30 $47 to $69 $45 to $66

8% Efficiency Improvement 265,579 metric tonnes CO2 

5% $4.0 $26 to $56 $24 to $51

3% $13 $35 to $65 $33 to $60

2.5% $20 $42 to $71 $40 to $67

3% (95th percentile) $41 $63 to $92 $61 to $88

*All estimates are rounded to two significant figures. Climate benefits are based on reductions in CO2 emissions. 

The estimated monetized co-benefits do not include climate benefits or health effects from direct exposure to 

NO2, SO2, and HAP; ecosystem effects; or visibility impairment. All fine particles are assumed to have 

equivalent health effects. The monetized co-benefits incorporate the conversion from precursor emissions to 

ambient fine particles and ozone. Co-benefits for PM2.5 and ozone are based on national benefit-per-ton 

estimates. Co-benefits for ozone are based on ozone season NOx emissions. Ozone co-benefits occur in analysis 

year, so they are the same for all discount rates. The health co-benefits reflect the sum of the PM2.5 and ozone 

co-benefits and reflect the range based on adult mortality functions (e.g., from Krewski et al. (2009) with Bell et 

al. (2004) to Lepeule et al. (2012) with Levy et al. (2005)). Confidence intervals are unavailable for this analysis 

because of the benefit-per-ton methodology. In general, the 95th percentile confidence interval for monetized 

PM2.5 benefits ranges from approximately -90 percent to +180 percent of the central estimates based on Krewski 

et al. (2009) and Lepeule et al. (2012). Emissions of directly emitted particles are disaggregated into EC+OC or 

crustal components using the method discussed in Appendix 4A of this RIA. 

Summary. In the unlikely event that a unit were to trigger the modification provision, the 

proposed standards would result in some costs and benefits. Based on the illustrative analysis of 

a hypothetical unit implementing efficiency measures in 2025 to comply with the proposed 
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9-14 

requirements, this proposal would result in a net benefit (benefits outweigh costs) for all levels of 

efficiency improvement and combinations of benefits. The net benefit would be even greater 

when potential fuel savings are taken into account. The actual costs, emission reductions, and 

benefits resulting from this proposal will vary based on the specifications of the modified unit, 

the efficiency improvements undertaken, the unit’s participation in a section 111(d) plan, and the 

influence of the control requirements it faces for non-CO2 pollutants. 

9.5 Statutory and Executive Order Requirements 

9.5.1 Executive Order 12866, Regulatory Planning and Review, and Executive Order 13563, 

Improving Regulation and Regulatory Review 

 Under Executive Order (EO) 12866 (58 FR 51,735, October 4, 1993), this action is a 

“significant regulatory action” because it “raises novel legal or policy issues arising out of legal 

mandates.” Accordingly, the EPA submitted this action to the Office of Management and Budget 

(OMB) for review under Executive Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and 

any changes made in response to OMB recommendations have been documented in the docket 

for this action. In addition, the EPA prepared an analysis of the potential costs and benefits 

associated with this action. This analysis is presented in the preceding sections of this chapter. 

In the period of analysis (through 2025) the EPA anticipates few, if any, sources will 

trigger either the modification or the reconstruction provisions proposed. Because there have 

been a few units that have notified the EPA of NSPS modifications in the past, we have 

conducted an illustrative analysis of the costs and benefits for a representative unit that is 

presented above. 

9.5.2 Paperwork Reduction Act 

This proposed action doesis not expected to impose an information collection burden under 

the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. Burden is defined at 5 

CFR 1320.3(b). As previously stated, the EPA expects few, if any, modified or reconstructed 

EGUs in the period of analysis. Specifically, the EPA believes it unlikely that fossil fuel-fired 

electric utility steam generating units (utility boilers and IGCC units) or stationary combustion 

turbines will take actions that would constitute modifications or reconstructions as defined under 
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the EPA’s NSPS regulations. Accordingly, this proposed action is not anticipated to impose any 

information collection burden over the 3-year period covered by the Information Collection 

Request (ICR) for this proposed rule. We have estimated, however, the information collection 

burden that would be imposed on an affected EGU if it was modified or reconstructed. The 

information collection requirements in this proposed rule have been submitted for approval to 

OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The information collection 

request prepared by the EPA has been assigned the EPA ICR number 2465.03.

 The EPA intends to codify the standards of performance in the same way for both this 

proposed action and the January 2014 proposal for new sources and is proposing the same 

recordkeeping and reporting requirements that were included in the January 2014 proposal.5

 (See 

79 FR at 1,498/3 – and 1,499/3.) Although not anticipated, if an EGU were to modify or 

reconstruct, this proposed action would impose minimal information collection burden on 

affected sources, beyond what those sources would already be subject to under the authorities of 

CAA parts 75 and 98. The OMB has previously approved the information collection 

requirements contained in the existing part 75 and 98 regulations (40 CFR part 75 and 40 CFR 

part 98) under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has 

assigned OMB control numbers 2060-0626 and 2060-0629, respectively. Apart from potential 

energy metering modifications to comply with net energy output based emission limits proposed 

in this action and certain reporting costs, which are mandatory for all owners/operators subject to 

CAA section 111 national emission standards, there would be no new information collection 

costs, as the information required by this proposed rule is already collected and reported by other 

regulatory programs. The recordkeeping and reporting requirements are specifically authorized 

by CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA pursuant to the 

recordkeeping and reporting requirements for which a claim of confidentiality is made is 

safeguarded according to agency policies set forth in 40 CFR part 2, subpart B. 

 

5

 The information collection requirements in the January 2014 proposal have been submitted for approval to the 

OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR document prepared by the EPA for 

the January 2014 proposal has been assigned the EPA ICR number 2465.02.
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Although, as stated above, the EPA expects few, if any, sources will trigger either the 

NSPS modification or reconstruction provisions that we are proposing, if an EGU were to 

modify or reconstruct during the three-year period covered by the ICR, it is likely that the EGU’s 

energy metering equipment would need to be modified to comply with proposed net energy 

output based CO2 emission limits. Specifically, the EPA estimates that it would take 

approximately three working months for a technician to retrofit existing energy metering 

equipment to meet the proposed net energy output requirements. In addition, after modifications 

are made that enable a facility to measure net energy output, each EGU’s Ddata Acquisition 

System (DAS) would need to be upgraded to accommodate reporting of net energy output rate 

based emissions. A modified or reconstructed EGU would be required to prepare a quarterly 

summary report, which includes reporting of emissions and downtime, every three months. The 

reporting burden for such a unit (averaged over the first three years after the effective date of the 

standards) is estimate to be $17,217 and 205 labor hours. Estimated cost burden is based on 2013 

Bureau of Labor Statistics (BLS) labor cost data. Average burden hours per response are 

estimated to be 47.3 hours and the average number of annual responses over the three-year ICR 

period is 4.33 per year. Burden is defined at 5 CFR 1320.3(b). 

An agency may not conduct or sponsor, and a person is not required to respond to, a 

collection of information unless it displays a currently valid OMB control number. The OMB 

control numbers for EPA’s regulations in 40 CFR are listed in 40 CFR part 9. 

To comment on the Agency’s need for this information, the accuracy of the provided 

burden estimates, and any suggested methods for minimizing respondent burden, the EPA has 

established a public docket for this rule, which includes the ICR, under Docket ID number EPAHQ-OAR-2013-0603. Submit any comments related to the ICR to the EPA and OMB. See the 

addresses section in the preamble for where to submit comments to the EPA. Send comments to 

OMB at the Office of Information and Regulatory Affairs, Office of Management and Budget, 

725 17th Street, NW, Washington, DC 20503, Attention: Desk Officer for the EPA. Since OMB 

is required to make a decision concerning the ICR between 30 and 60 days after publication in 

the Federal Register, a comment to OMB is best assured of having its full effect if OMB receives 

it by 30 days after publication in the Federal Register. The final rule will respond to any OMB or 

public comments on the information collection requirements contained in this proposal. The 
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information collection requirements in the January 2014 proposal have been submitted for 

approval to the OMB under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The ICR 

document prepared by the EPA for the January 2014 proposal has been assigned the EPA ICR 

number 2465.02. 

9.5.3 Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) generally requires an agency to prepare a regulatory 

flexibility analysis of any rule subject to notice and comment rulemaking requirements under the 

Administrative Procedure Act or any other statute, unless the agency certifies that the rule will 

not have a significant economic impact on a substantial number of small entities. Small entities 

include small businesses, small organizations, and small governmental jurisdictions. 

For purposes of assessing the impacts of this rule on small entities, small entity is defined 

as: 

1. A small business that is defined by the SBA’s regulations at 13 CFR 121.201 (for the 

electric power generation industry, the small business size standard is an ultimate 

parent entity with less than 750 employees). The NAICS codes for the affected 

industry are in Table 9-9 below.

2. A small governmental jurisdiction that is a government of a city, county, town, school 

district or special district with a population of less than 50,000; and 

3. A small organization that is any not-for-profit enterprise which is independently 

owned and operated and is not dominant in its field. 

Table 9-9. Potentially Regulated Categories and Entitiesa

Category NAICS Code Examples of Potentially Regulated Entities

Industry 221112 Fossil fuel electric power generating units

State/Local Government 221112b Fossil fuel electric power generating units owned by municipalities

a

 Include NAICS categories for source categories that own and operate electric power generating units (includes 

boilers and stationary combined cycle combustion turbines). 

b

 State or local government-owned and operated establishments are classified according to the activity in which they 

are engaged. 
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After considering the economic impacts of this proposed rule on small entities, we certify 

that this action will not have a significant economic impact on a substantial number of small 

entities. 

The EPA expects few, if any, modified utility boilers, IGCC units, or stationary 

combustion turbines in the period of analysis. An NSPS modification is defined as a physical or 

operational change that increases the source’s maximum achievable hourly rate of emissions. 

The EPA does not believe that there are likely to be EGUs that will take actions that would 

constitute modifications as defined under the EPA’s NSPS regulations. 

Because there have been a limited number of units that have notified the EPA of NSPS 

modifications in the past, the RIA for this proposed rule includes an illustrative analysis of the 

costs and benefits for a representative unit. 

Based on the analysis, the EPA estimates that this proposed rule could result in CO2

emission changes, quantified benefits, or costs for a hypothetical unit that triggered the 

modification provision. However, we do not anticipate this proposed rule would impose 

significant costs on those sources, including any that are owned by small entities. 

In addition, the EPA expects few, if any, The EPA expects few, if any, reconstructed fossil 

fuel-fired electric utility steam generating units (utility boilers and IGCC units) or stationary 

combustion turbines in the period of analysis. Reconstruction occurs when a single project 

replaces components or equipment in an existing facility and exceeds 50 percent of the fixed 

capital cost that would be required to construct a comparable entirely new facility. Due to the 

limited data available on reconstructions, it is not possible to conduct a representative illustrative 

analysis of what costs and benefits might result from this proposal in the unlikely case that a unit 

were to reconstruct. However, based on the low number of previous reconstructions and the 

BSER determination based on the most efficient available generating technology, we would 

expect this proposal to result in no significant CO2 emission changes, quantified benefits, or 

costs for NSPS reconstructions. 

Nevertheless, the EPA is aware that there is substantial interest in the proposed rule among 

small entities (municipal and rural electric cooperatives). As summarized in section II.G. of the 
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preamble, the EPA has conducted an unprecedented amount of stakeholder outreach. As part of 

that outreach, agency officials participated in many meetings with individual utilities as well as 

meetings with electric utility associations. Specifically, the EPA Administrator, Gina McCarthy, 

participated in separate meetings with both the National Rural Electric Cooperative Association 

(NRECA) and the American Public Power Association (APPA). The meetings brought together 

leaders of the rural cooperatives and public power utilities from across the country. The 

Administrator discussed and exchanged information on the unique challenges, in particular the 

financial structure of NRECA and APPA member utilities. A detailed discussion of the 

stakeholder outreach is included in the preamble to the emission guidelines for existing affected 

electric utility generating units being proposed in a separate action. 

In addition, as described in the RFA section of the preamble to the proposed standards of 

performance for GHG emissions from new EGUs (79 FR 1499 and-1500, January 8, 2014), the 

EPA conducted outreach to representatives of small entities while formulating the provisions of 

the proposed standards. Although only new EGUs would be affected by those proposed 

standards, the outreach regarded planned actions for new, reconstructed, modified and existing 

sources. 

While formulating the provisions of the proposed rule, the EPA considered the input 

provided over the course of the stakeholder outreach. We invite comments on all aspects of this 

proposal and its impacts, including potential impacts on small entities. 

9.5.4 Unfunded Mandates Reform Act (UMRA) 

This proposed rule does not contain a federal mandate that may result in expenditures of 

$100 million or more for state, local, and tribal governments, in the aggregate, or the private 

sector in any one year. As previously stated, the EPA expects few, if any, modified or 

reconstructed fossil fuel-fired electric utility steam generating units (utility boilers and IGCC 

units) or stationary combustion turbines in the period of analysis. Accordingly, this proposed rule 

is not subject to the requirements of sections 202 or 205 of UMRA. 
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This proposed rule is also not subject to the requirements of section 203 of UMRA because 

it contains no regulatory requirements that might significantly or uniquely affect small 

governments. 

In light of the interest among governmental entities, the EPA initiated consultations with 

governmental entities while formulating the provisions of the proposed standards for newly 

constructed EGUs. This outreach regarded planned actions for new, reconstructed, modified and 

existing sources. As described in the UMRA discussion in the preamble to the proposed 

standards of performance for GHG emissions from new EGUs (79 FR 1500 and- 1501, January 

8, 2014), the EPA consulted with the following 10 national organizations representing state and 

local elected officials: 

 National Governors Association 

 National Conference of State Legislatures 

 Council of State Governments 

 National League of Cities 

 U.S. Conference of Mayors 

 National Association of Counties 

 International City/County Management Association 

 National Association of Towns and Townships 

 County Executives of America 

 Environmental Council of States 

On February 26, 2014, the EPA re-engaged with those governmental entities to provide a 

pre-proposal update on the emission guidelines for existing EGUs and emission standards for 

modified and reconstructed EGUs. 

While formulating the provisions of these proposed standards, the EPA also considered the 

input provided over the course of extensive stakeholder outreach conducted by the EPA (see 

section II.G. of the preamble for more information). 

9.5.5 Executive Order 13132, Federalism 

This proposed action does not have federalism implications. It would not have substantial 

direct effects on the States, on the relationship between the national government and the States, 

or on the distribution of power and responsibilities among the various levels of government, as 
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specified in EO 13132. This proposed action would not impose substantial direct compliance 

costs on state or local governments, nor would it preempt state law. Thus, EO 13132 does not 

apply to this action. 

However, as described in the Federalism discussion in the preamble to the proposed 

standards of performance for GHG emissions from new EGUs (79 FR 1501, January 8, 2014), 

the EPA consulted with state and local officials in the process of developing the proposed 

standards for newly constructed EGUs. This outreach regarded planned actions for new, 

reconstructed, modified and existing sources. The EPA engaged 10 national organizations 

representing state and local elected officials. The UMRA discussion in the preamble to the 

proposed standards of performance for GHG emissions from new EGUs (79 FR 1500 and- 1501, 

January 8, 2014) includes a description of the consultation. In addition, on February 26, 2014, 

the EPA re-engaged with those governmental entities to provide a pre-proposal update on the 

emission guidelines for existing EGUs and emission standards for modified and reconstructed 

EGUs. While formulating the provisions of these proposed standards, the EPA also considered 

the input provided over the course of the extensive stakeholder outreach conducted by the EPA 

(see section II.G. of the preamble). In the spirit of EO 13132, and consistent with the EPA policy 

to promote communications between the EPA and state and local governments, the EPA 

specifically solicits comment on this proposed action from state and local officials. 

9.5.6 Executive Order 13175, Consultation and Coordination with Indian Tribal Governments 

 This action does not have tribal implications, as specified in Executive Order 13175 (65 

FR 67249, November 9, 2000). It would neither impose substantial direct compliance costs on 

tribal governments, nor preempt Tribal law. This proposed rule would impose requirements on 

owners and operators of reconstructed and modified EGUs. The EPA is aware of three coal-fired 

EGUs located in Indian Country but is not aware of any EGUs owned or operated by tribal 

entities. The EPA notes that this proposal would only affect existing sources such as the three 

coal-fired EGUs located in Indian Country, if those EGUs were to take actions constituting 

modifications or reconstructions as defined under the EPA’s NSPS regulations. However, as 

previously stated, the EPA expects few, if any, modified or reconstructed EGUs in the period of 

analysis. Thus, Executive Order 13175 does not apply to this action. 
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Although Executive Order 13175 does not apply to this action, the EPA conducted 

outreach to tribal environmental staff and offered consultation with tribal officials in developing 

this action. Because the EPA is aware of tribal interest in carbon pollution standards for the 

power sector, prior to proposal of GHG standards for new power plants, the EPA offered 

consultation with tribal officials early in the process of developing the proposed regulation to 

permit them to have meaningful and timely input into its development. The EPA’s consultation 

regarded planned actions for new, reconstructed, modified, and existing sources. The 

Consultation and Coordination with Indian Tribal Governments discussion in the preamble to the 

proposed standards of performance for GHG emissions from new EGUs (79 FR 1501, January 8, 

2014) includes a description of that consultation. 

During development of this proposed regulation, consultation letters were sent to 584 tribal 

leaders. The letters provided information regarding the EPA’s development of both the NSPS for 

modified and reconstructed EGUs and emission guidelines for existing EGUs and offered 

consultation. None have requested consultation. Tribes were invited to participate in the national 

informational webinar held August 27, 2013, and to which tribes were invited. In addition, a 

consultation/outreach meeting was held on September 9, 2013, with tribal representatives from 

some of the 584 tribes. The EPA also met with tribal environmental staff with the National 

Tribal Air Association, by teleconference, on July 25, 2013, and December 19, 2013. In those 

teleconferences, the EPA provided background information on the GHG emission guidelines to 

be developed and a summary of issues being explored by the Agency. Additional detail 

regarding this stakeholder outreach is included in the executive order discussion for the emission 

guidelines for existing affected electric utility generating units in Chapter 7 of this RIA. The 

EPA also held a series of listening sessions prior to proposal of GHG standards for new power 

plants. Tribes participated in a session on February 17, 2011, with state agencies, as well as in a 

separate session with tribes on April 20, 2011. 

The EPA will also hold additional meetings with tribal environmental staff during the 

public comment period, to inform them of the content of this proposal, and offer further 

consultation with tribal elected officials where it is appropriate. We specifically solicit additional 

comment from tribal officials on this proposed rule. 
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9.5.7 Executive Order 13045, Protection of Children from Environmental Health Risks and 

Safety Risks 

The EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying to those 

regulatory actions that concern health or safety risks, such that the analysis required under 

section 5-501 of the Order has the potential to influence the regulation. This action is not subject 

to EO 13045 because it is based solely on technology performance.

9.5.8 Executive Order 13211, Actions Concerning Regulations that Significantly Affect 

Energy Supply, Distribution, or Use 

This proposed action is not a “significant energy action” as defined in EO 13211 (66 FR 

28355, [May 22, 2001]), because it is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. As previously stated, the EPA expects few, if any, 

reconstructed or modified EGUs in the period of analysis andThis proposed action is not 

anticipated to have impacts on emissions, costs or energy supply decisions for the affected 

electric utility industry to be minimal as a result. 

9.5.9 National Technology Transfer and Advancement Act 

Section 12(d) of the NTTAA of 1995 (Public Law No. 104-113; 15 U.S.C. 272 note) 

directs the EPA to use voluntary consensus standards (VCS) in their regulatory and procurement 

activities unless to do so would be inconsistent with applicable law or otherwise impractical. 

VCS are technical standards (e.g., materials specifications, test methods, sampling procedures, 

business practices) developed or adopted by one or more voluntary consensus bodies. The 

NTTAA directs the EPA to provide Congress, through annual reports to the OMB, with 

explanations when an agency does not use available and applicable VCS. 

This proposed rulemaking involves technical standards. The EPA proposes to use the 

following standards in this proposed rule: 

 ASTM D388-12D5287-08 (Standard Classification of Coals by 

RankPractice for Automatic Sampling of Gaseous Fuels) 
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9-24 

 ASTM D396-13cD4057-06 (Standard Specification for Fuel OilsPractice 

for Manual Sampling of Petroleum and Petroleum Products) 

 ASTM D975-14D4177-95(2010) (Standard Specification for Diesel Fuel 

OilsPractice for Automatic Sampling of Petroleum and Petroleum Products)

 D3699-13b (Standard Specification for Kerosene) 

 D6751-12 (Standard Specification for Biodiesel Fuel Blend Stock [B100] 

for Middle Distillate Fuels) 

 ASTM D7467-13 (Standard Specification for Diesel Fuel Oil, Biodiesel 

Blend [B6 to B20]) 

 ANSI C12.20 (American National Standards for Electricity Meters – 0.2 

and 0.5 Accuracy Classes).

The EPA is proposing use of Appendices A, B, D, F and G to 40 CFR part 75. These 

Appendices contain standards that have already been reviewed under the NTTAA. The EPA 

welcomes comments on this aspect of the proposed rulemaking and, specifically, invites the 

public to identify potentially-applicable VCS and to explain why such standards should be used 

in this action.

9.5.10 Executive Order 12898: Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations 

 Executive Order 12898 (59 FR 7629, February 16, 1994) establishes federal executive 

policy on environmental justice. Its main provision directs federal agencies, to the greatest extent 

practicable and permitted by law, to make environmental justice part of their mission by 

identifying and addressing, as appropriate, disproportionately high and adverse human health or 

environmental effects of their programs, policies, and activities on minority populations and lowincome populations in the U.S. 

 This proposed rule limits GHG emissions from modified and reconstructed fossil fuelfired electric utility steam generating units (utility boilers and IGCC units) and stationary 

combustion turbines by establishing national emission standards for CO2. The EPA has 
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9-25 

determined that this proposed rule would not result in disproportionately high and adverse 

human health or environmental effects on minority, low-income, and indigenous populations 

because it does not affect the level of protection provided to human health or the 

environment. As previously stated, the EPA expects few, if any, modified or reconstructed fossil 

fuel-fired electric utility steam generating units (utility boilers and IGCC units) or stationary 

combustion turbines in the period of analysis. 

 
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9.6 References 

Bell, M.L., et al. 2004. “Ozone and Short-Term Mortality in 95 U.S. Urban Communities, 1987-

2000.” Journal of the American Medical Association, 292(19): p. 2372-8. 

Krewski D.; M. Jerrett; R.T. Burnett; R. Ma; E. Hughes; Y. Shi, et al. 2009. Extended Follow-Up 

and Spatial Analysis of the American Cancer Society Study Linking Particulate Air Pollution 

and Mortality. HEI Research Report, 140, Health Effects Institute, Boston, MA. 

Lepeule, J.; F. Laden; D. Dockery; J. Schwartz. 2012. “Chronic Exposure to Fine Particles and 

Mortality: An Extended Follow-Up of the Harvard Six Cities Study from 1974 to 2009.” 

Environmental Health Perspectives, July, 120(7):965-70. 

Levy, J.I.; S.M. Chemerynski and J.A. Sarnat. 2005. “Ozone Exposure and Mortality: An 

Empiric Bayes Metaregression Analysis.” Epidemiology, 16(4): pp. 458-68.