New Source Review

Workshop Manual

Prevention of Significant Deterioration

and

Nonattainment Area 

Permitting

D R A F T 

OCTOBER 1990 

New Source Review 

Workshop Manual 

Prevention of Significant Deterioration

and

Nonattainment Area 

Permitting
D R A F T 

OCTOBER 1990 

TABLE OF CONTENTS

Page 

PART I - PREVENTION OF SIGNIFICANT DETERIORATION (PSD) REVIEW 

Chapter A - Applicability 

I. Introduction. . . . . . . . . . . . . . . . . . . . . . . . A.1 

II. New Source PSD Applicability Determination. . . . . . . . . A.3 

A. Definition of Source. . . . . . . . . . . . . . . . . A.3 

B. Potential to Emit . . . . . . . . . . . . . . . . . . A.5 

1. Basic Requirements. . . . . . . . . . . . . . . A.5 

2. Enforceability of Limits. . . . . . . . . . . . A.5 

3. Fugitive Emissions. . . . . . . . . . . . . . . A.9 

4. Secondary Emissions . . . . . . . . . . . . . . A.16 

5. Regulated Pollutants. . . . . . . . . . . . . . A.18 

6. Methods for Determining Potential to Emit . . . A.19 

C. Emissions Thresholds for PSD Applicability. . . . . . A.22 

1. Major Sources . . . . . . . . . . . . . . . . . A.22 

2. Significant Emissions . . . . . . . . . . . . . A.24 

D. Local Air Quality Considerations. . . . . . . . . . . A.25 

E. Summary of Major New Source Applicability . . . . . . A.26 

F. New Source Applicability Example. . . . . . . . . . . A.28 

III. Major Modification Applicability. . . . . . . . . . . . . . A.33 

A. Activities That Are Not Modifications . . . . . . . . A.34 

B. Emissions Netting . . . . . . . . . . . . . . . . . . A.34 

1. Accumulation of Emissions . . . . . . . . . . . A.36 

2. Contemporaneous Emissions Changes . . . . . . . A.37 

3. Creditable Contemporaneous Emissions Changes. . A.38 

4. Creditable Amount . . . . . . . . . . . . . . . A.40 

5. Suggested Emissions Netting Procedure . . . . . A.44 

6. Netting Example . . . . . . . . . . . . . . . . A.51 

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IV. General Exemptions. . . . . . . . . . . . . . . . . . . . . A.56 

A. Sources and Modifications After August 7, 1980. . . . A.56 

B. Sources Constructed Prior to August 7, 1980 . . . . . A.56 

Chapter B - Best Available Control Technology 

I. Purpose . . . . . . . . . . . . . . . . . . . . . . . . . . B.1 

II. Introduction. . . . . . . . . . . . . . . . . . . . . . . . B.4 

III. BACT Applicability. . . . . . . . . . . . . . . . . . . . . B.4 

IV. A Step by Step Summary of the Top-Down Process. . . . . . . B.5 

A. STEP 1--Identify All Control Technologies . . . . . . B.7 

B. STEP 2--Eliminate Technically Infeasible Options. . . B.7 

C. STEP 3--Rank Remaining Control Technologies by Control 

Effectiveness. . . . . . . . . . . . . . . . . . . . B.7 

D. STEP 4--Evaluate Most Effective Controls and Document 

Results . . . . . . . . . . . . . . . . . . . . . . . B.8 

E. STEP 5--Select BACT . . . . . . . . . . . . . . . . . B.9 

V. Top-Down Analysis: Detailed Procedures. . . . . . . . . . . B.10 

A. Identify Alternatives Emission Control Techniques . . B.10 

1. Demonstrated and Transferable Technologies. . . B.11 

2. Innovated Technologies. . . . . . . . . . . . . B.12 

3. Consideration of Inherently Lower Polluting 

Processes . . . . . . . . . . . . . . . . . . . B.13 

4. Example . . . . . . . . . . . . . . . . . . . . B.14 

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B. Technical Feasibility Analysis. . . . . . . . . . . . B.17 

C. Ranking the Technically Feasible Alternatives to 

Establish a Control Hierarchy . . . . . . . . . . . . B.22 

1. Choice of Units of Emissions Performance to Compare 

Levels Amongst Control Options. . . . . . . . . 

2. Control Techniques With a Wide Range of 

Emissions Performance Levels. . . . . . . . . . 

3. Establishment of the Control Options Hierarchy. 

D. The BACT Selection Process. . . . . . . . . . . . . . 

1. Energy Impacts Analysis . . . . . . . . . . . . 

2. Cost/Economic Impacts Analysis. . . . . . . . . 

a. Estimating Control Costs. . . . . . . . . 

b. Cost Effectiveness . . . . . . . . . . . 

c. Determining an Adverse Economic Impact. . 

3. Environmental Impacts Analysis. . . . . . . . . 

a. Examples (Environmental Impacts). . . . . 

b. Consideration of Emissions of Toxic 

and Hazardous Pollutants. . . . . . . . . 

E. Selecting BACT. . . . . . . . . . . . . . . . . . . . 

F. Other considerations. . . . . . . . . . . . . . . . . 

VI. Enforceability of BACT. . . . . . . . . . . . . . . . . . . 

VII. Example BACT Analyses for Gas Turbines. . . . . . . . . . . 

A. Example 1--Simple Cycle Gas Turbines Firing Natural 

Gas . . . . . . . . . . . . . . . . . . . . . . . . . 

1. Project Summary . . . . . . . . . . . . . . . . 

2. BACT Analysis Summary . . . . . . . . . . . . . 

a. Control Technology Options. . . . . . . . 

b. Technical Feasibility Considerations. . . 

c. Control Technology Hierarchy. . . . . . . 

B.22 

B.23 

B.25 

B.26 

B.29 

B.31 

B.32 

B.36 

B.44 

B.46 

B.48 

B.50 

B.53 

B.54 

B.56 

B.57 

B.58 

B.58 

B.58 

B.58 

B.61 

B.62 

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d. Impacts Analysis Summary. . . . . . . . . B.65 

e. Toxics Assessment . . . . . . . . . . . . B.65 

f. Rationale for Proposed BACT . . . . . . . B.68 

B. Example 2--Combined Cycle Gas Turbines Firing 

Natural Gas . . . . . . . . . . . . . . . . . . . . . B.69 

C. Example 3--Combined Cycle Gas Turbine Firing Distillate 

 Oil . . . . . . . . . . . . . . . . . . . . . . . . . B.73 

D. Other Considerations. . . . . . . . . . . . . . . . . B.74 

Chapter C - The Air Quality Analysis 

I. Introduction. . . . . . . . . . . . . . . . . . . . . . . . C.1 

II. National Ambient Air Quality Standards and PSD Increments . C.3 

A. Class I, II and III Areas and Increments. . . . . . . C.3 

B. Establishing the Baseline Date. . . . . . . . . . . . C.6 

C. Establishing the Baseline Area. . . . . . . . . . . . C.9 

D. Redefining Baseline Areas (Area Redesignation). . . . C.9 

E. Increment Consumption and Expansion . . . . . . . . . C.10 

F. Baseline Date and Baseline Area Concepts -- Examples. C.12 

III. Ambient Data Requirements . . . . . . . . . . . . . . . . . C.16 

A. Pre-Application Air Quality Monitoring. . . . . . . . C.16 

B. Post-Construction Air Quality Monitoring. . . . . . . C.21 

C. Meteorological Monitoring . . . . . . . . . . . . . . C.22 

IV. Dispersion Modeling Analysis. . . . . . . . . . . . . . . . C.24 

A. Overview of the Dispersion Modeling Analysis. . . . . C.24 

B. Determining the Impact Area . . . . . . . . . . . . . C.26 

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C. Developing the Emissions Inventories. . . . . . . . . C.31 

1. The NAAQS Inventory . . . . . . . . . . . . . . C.32 

2. The Increment Inventory . . . . . . . . . . . . C.35 

3. Noncriteria Pollutants Inventory. . . . . . . . C.37 

D. Model Selection . . . . . . . . . . . . . . . . . . . C.37 

1. Meteorological Data . . . . . . . . . . . . . . C.39 

2. Receptor Network. . . . . . . . . . . . . . . . C.39 

3. Good Engineering Practice (GEP) Stack Height. . C.42 

4. Source Data . . . . . . . . . . . . . . . . . . C.44 

E. The Compliance Demonstration. . . . . . . . . . . . . C.51 

V. Air Quality Analysis--Example . . . . . . . . . . . . . . . C.54 

A. Determining the Impact Air. . . . . . . . . . . . . . C.54 

B. Developing the Emissions Inventories. . . . . . . . . C.58 

1. The NAAQS Inventory . . . . . . . . . . . . . . C.59 

2. The Increment Inventory . . . . . . . . . . . . C.62 

C. The Full Impact Analysis. . . . . . . . . . . . . . . C.66 

1. NAAQS Analysis. . . . . . . . . . . . . . . . . C.67 

2. PSD Increment Analysis. . . . . . . . . . . . . C.69 

VI. Bibliography. . . . . . . . . . . . . . . . . . . . . . . . C.71 

Chapter D - Additional Impacts Analysis 

I. Introduction . . . . . . . . . . . . . . . . . . . . . . . . D.1 

II. Elements of the Additional Impacts Analysis. . . . . . . . . D.3 

A. Growth Analysis. . . . . . . . . . . . . . . . . . . . D.3 

B. Soils and Vegetation Analysis. . . . . . . . . . . . . D.4 

C. Visibility Impairment Analysis . . . . . . . . . . . . D.4 

1. Screening Procedures: Level 1 . . . . . . . . . D.5 

2. Screening Procedures: Level 2 . . . . . . . . . D.5 

3. Screening Procedures: Level 3 . . . . . . . . . D.6 

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D. Conclusions. . . . . . . . . . . . . . . . . . . . . . D.6 

III. Additional Impacts Analysis Example. . . . . . . . . . . . . D.7 

A. Example Background Information . . . . . . . . . . . . D.7 

B. Growth Analysis. . . . . . . . . . . . . . . . . . . . D.9 

1. Work Force . . . . . . . . . . . . . . . . . . . D.9 

2. Housing. . . . . . . . . . . . . . . . . . . . . D.9 

3. Industry . . . . . . . . . . . . . . . . . . . . D.9 

C. Soils and Vegetation . . . . . . . . . . . . . . . . . D.10 

D. Visibility Analysis. . . . . . . . . . . . . . . . . . D.13 

E. Example Conclusions. . . . . . . . . . . . . . . . . . D.13 

IV. Bibliography . . . . . . . . . . . . . . . . . . . . . . . . D.15 

Chapter E - Class I Area Impact Analysis 

I. Introduction . . . . . . . . . . . . . . . . . . . . . . . . E.1 

II. Class I Areas and Their Protection . . . . . . . . . . . . . E.2 

A. Class I Increments . . . . . . . . . . . . . . . . . . E.8 

B. Air Quality Related Values (AQRV's). . . . . . . . . . E.10 

C. Federal Land Manager . . . . . . . . . . . . . . . . . E.12 

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III. Mandatory Federal Class I Area Impact Analysis and Review. . E.16 

A. Source Applicability . . . . . . . . . . . . . . . . . E.16 

B. Pre-Application Stage. . . . . . . . . . . . . . . . . E.17 

C. Preparation of Permit Application . . . . . . . . . . E.18 

D. Permit Application Review . . . . . . . . . . . . . . E.19 

IV. Visibility Impact Analysis and Review . . . . . . . . . . . E.22 

A. Visibility Analysis . . . . . . . . . . . . . . . . . E.22 

B. Procedural Requirements . . . . . . . . . . . . . . . E.23 

V. Bibliography. . . . . . . . . . . . . . . . . . . . . . . . E.24 

PART II - NONATTAINMENT AREAS 

Chapter F - Nonattainment Area Applicability 

I. Introduction. . . . . . . . . . . . . . . . . . . . . . . . F.1 

II. Definition of Source. . . . . . . . . . . . . . . . . . . . F.2 

A. "Plantwide" Stationary Source Definition. . . . . . . F.2 

B. "Dual Source" Definition of Stationary Source . . . . F.3 

III. Pollutants Eligible for Review and Applicability 

Thresholds. . . . . . . . . . . . . . . . . . . . . . . . F.7 

A. Pollutants Eligible for Review (Geographic 

Considerations) . . . . . . . . . . . . . . . . . . F.7 

B. Major Source Threshold. . . . . . . . . . . . . . . . F.7 

C. Major Modification Thresholds . . . . . . . . . . . . F.8 

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IV. Nonattainment Applicability Example . . . . . . . . . . . . F.9 

Chapter G - Nonattainment Area Requirement 

I. Introduction. . . . . . . . . . . . . . . . . . . . . . . . G.1 

II. Lowest Achievable EMission Rate (LAER). . . . . . . . . . . G.2 

III. Emissions Reductions "Offsets". . . . . . . . . . . . . . . G.5 

A. Criteria for Evaluating Emissions Offsets . . . . . . G.6 

B. Available Sources of Offsets. . . . . . . . . . . . . G.7 

C. Calculation of Offset Baseline. . . . . . . . . . . . G.7 

D. Enforceability of Proposed Offsets. . . . . . . . . . G.8 

IV. Other Requirements. . . . . . . . . . . . . . . . . . . . . G.9 

PART III - EFFECTIVE PERMIT WRITING 

Chapter H - Elements of an Effective Permit 

I. Introduction. . . . . . . . . . . . . . . . . . . . . . . . H.1 

II. Typical Permit Elements . . . . . . . . . . . . . . . . . . H.3 

A. Legal Authority . . . . . . . . . . . . . . . . . . . H.3 

B. Technical Specifications. . . . . . . . . . . . . . . H.5 

C. Emissions Compliance Demonstrations . . . . . . . . . H.6 

D. Definition of Excess Emissions. . . . . . . . . . . . H.7 

E. Administrative Procedures . . . . . . . . . . . . . . H.8 

F. Other Conditions. . . . . . . . . . . . . . . . . . . H.9 

III. Summary . . . . . . . . . . . . . . . . . . . . . . . . . . H.9 

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Chapter I - Permit Drafting 

I. Recommended Permit Drafting Steps . . . . . . . . . . . . . I.1 

II. Permit Worksheets and File Documentation. . . . . . . . . . I.5 

III. Summary . . . . . . . . . . . . . . . . . . . . . . . . . . I.5 

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TABLES 

A.1. PSD Source Categories With 100 tpy Major Source 

Thresholds. . . . . . . . . . . . . . . . . . . . . . . . A.11 

A-2. NSPS and National Emissions Standards for Hazardous Air 

Pollutants Proposed Prior to August 7, 1980 . . . . . . . A.12 

A-3. Suggested References for Estimating Fugitive Emissions. . . A.17 

A-4. Significant Emission Rates of Pollutants Regulated Under 

the Clean Air Act . . . . . . . . . . . . . . . . . . . . A.20 

A-5. Procedures for Determining the Net Emissions Change at a 

Source. . . . . . . . . . . . . . . . . . . . . . . . . . A.45 

B-1 Key Steps in the "Top-Down" BACT Process. . . . . . . . . . B.6 

B-2 Sample BACT Control Hierarchy . . . . . . . . . . . . . . . B.27 

B-3 Sample Summary of Top-Down BACT Impact Analysis Results . . B.28 

B-4 Example Control System Design Parameters. . . . . . . . . . B.34 

B-5 Example 1 -- Combustion Turbine Design Parameters . . . . . B.59 

B-6 Example 1 -- Summary of Potential NOx Control Technology 

 Options . . . . . . . . . . . . . . . . . . . . . . . . . B.60 

B-7 Example 1 -- Control Technology Hierarchy . . . . . . . . . B.63 

B-8 Example 1 -- Summary of Top-Down BACT Impact Analysis 

Results for NOx . . . . . . . . . . . . . . . . . . . . . B.66 

B-9 Example 2 -- Combustion Turbine Design Parameters . . . . . B.70 

B-10 Example 2 -- Summary of Top-Down BACT Impact Analysis 

 Results . . . . . . . . . . . . . . . . . . . . . . . . . B.71 

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TABLES - Continued 

B-11 Example of a Capital Cost Estimate for an Electrostatic 

Precipitator. . . . . . . . . . . . . . . . . . . . . . . b.5 

B-12 Example of a Annual Cost Estimate for an Electrostatic 

Precipitator Applied to a Coal-Fired Boiler . . . . . . . b.9 

C-1. National Ambient Air Quality Standards. . . . . . . . . . . C.4 

C-2. PSD Increments. . . . . . . . . . . . . . . . . . . . . . . C.7 

C-3. Significant Monitoring Concentrations . . . . . . . . . . . C.17 

C-4. Significance Levels for Air Quality Impacts in Class II 

Areas . . . . . . . . . . . . . . . . . . . . . . . . . . C.28 

C-5. Point Source Model Input Data (Emissions) for NAAQS 

Compliance Demonstrations . . . . . . . . . . . . . . . . C.46 

C-6. Existing Baseline Dates for SO2, TSP, and NO2 for Example 

PSD Increment Analysis. . . . . . . . . . . . . . . . . . C.64 

E.1. Mandatory Class I Areas . . . . . . . . . . . . . . . . . . E.3 

E.2. Class I Increments. . . . . . . . . . . . . . . . . . . . . E.9 

E-3. Examples of Air Quality-Related Values and Potential Air 

Pollution Caused Changes. . . . . . . . . . . . . . . . . E.11 

E-4. Federal Land Manager. . . . . . . . . . . . . . . . . . . . E.14 

E-5. USDA Forest Service Regional Offices and States They Serve. E.15 

H-1. Suggested Minimum Contents of Air Emission Permits. . . . . H.4 

H-2. Guidelines for Writing Effective Specific Conditions in 

NSR Permits . . . . . . . . . . . . . . . . . . . . . . . H.10 

I-1. Five Steps to Permit Drafting . . . . . . . . . . . . . . . I.2 

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FIGURES 

A-1. Creditable Reductions in Actual Emissions . . . . . . . . . A.43 

A-2. Establishing "Old" and "New" Representative Actual SO2 

Emissions . . . . . . . . . . . . . . . . . . . . . . . . A.50 

B-1 Least-Cost Envelope . . . . . . . . . . . . . . . . . . . . B.42 

B-2 Least-Cost Envelope for Example 1 . . . . . . . . . . . . . B.67 

B-3 Least-Cost Envelope for Example 2 . . . . . . . . . . . . . B.72 

B-4 Elements of Total Capital Cost. . . . . . . . . . . . . . . b.2 

B-5 Elements of Total Annual Cost . . . . . . . . . . . . . . . b.6 

C-1. Establishing the Baseline Area. . . . . . . . . . . . . . . C.13 

C-2. Redefining the Baseline Area. . . . . . . . . . . . . . . . C.15 

C-3. Basic Steps in the Air Quality Analysis (NAAQS and PSD 

Increments) . . . . . . . . . . . . . . . . . . . . . . . C.27 

C-4. Determining the Impact Area . . . . . . . . . . . . . . . . C.29 

C-5. Defining the Emissions Inventory Screening Area . . . . . . C.33 

C-6. Examples of Polar and Cartesian Grid Networks . . . . . . . C.41 

C-7. Counties Within 100 Kilometers of Proposed Source . . . . . C.57 

C-8. Point Sources Within 100 Kilometers of Proposed Source. . . C.60 

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APPENDICES 

A. Definition of Selected Terms a.1 

B. Estimating Control Costs . . b.1 

C. Potential to Emit . . . . . . . . . . . . . . . . . . . . . c.1 

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D R A F T 

OCTOBER 1990 

PREFACE 

This document was developed for use in conjunction with new source 

review workshops and training, and to guide permitting officials in the 

implementation of the new source review (NSR) program. It is not intended to 

be an official statement of policy and standards and does not establish 

binding regulatory requirements; such requirements are contained in the 

regulations and approved state implementation plans. Rather, the manual is 

designed to (1) describe in general terms and examples the requirements of the 

new source regulations and pre-existing policy; and (2) provide suggested 

methods of meeting these requirements, which are illustrated by examples. 

Should there be any apparent inconsistency between this manual and the 

regulations (including any policy decisions made pursuant to those 

regulations), such regulations and policy shall govern. This document can be 

used to assist those people who may be unfamiliar with the NSR program (and 

its implementation) to gain a working understanding of the program. 

The focus of this manual is the prevention of significant deterioration 

(PSD) portion of the NSR program found in the Federal Regulations at 

40 CFR 52.21. It does not necessarily describe the specific requirements in 

those areas where the PSD program is conducted under a state implementation 

plan (SIP) which has been developed and approved in accordance with 40 CFR 

51.166. The reader is cautioned to keep this in mind when using this manual 

for general program guidance. In most cases, portions of an approved SIP that 

are different from those described in this manual will be more restrictive. 

Consequently, it is suggested that the reader also obtain program information 

from a State or local agency to determine all requirements that may apply in a 

area. 

The examples presented in this manual are presented for illustration 

purposes only. They are fictitious and are designed to impart a basic 

understanding of the NSR regulations and requirements. 

A number of terms and acronyms used in this manual have specific 

meanings within the context of the NSR program. Since this manual is intended 

for use by those persons generally familiar with NSR these terms are used 

throughout this document, often without definition. To aid users of the 

document who are unfamiliar with these terms, general definitions of these 

terms can be found in Appendix A. The specific regulatory definitions for 

most of the terms can be found in 40 CFR 52.21. Should there be any apparent 

inconsistency between the definitions contained in Appendix A and the 

regulatory definitions or requirements found in Part 40 of the Code of Federal 

Regulations (including any policy decisions made pursuant to those 

regulations), the regulations and policy decisions shall govern. 
D R A F T 

OCTOBER 1990 

MANUAL ORGANIZATION 

The manual is organized into three parts. Part I contains five chapters 

(Chapters A - E) covering the PSD program requirements. Chapter A describes 

the PSD applicability criteria and process used to determine if a proposed new 

or modified stationary source is required to obtain a PSD permit. Chapter B 

discusses the process by which best available control technology (BACT) is 

determined for new or modified emissions units. Chapter C discusses the PSD 

air quality analysis used to demonstrate that the proposed construction will 

not cause or contribute to a violation of any applicable National Ambient Air 

Quality Standard or PSD increment. Chapter D discusses the PSD additional 

impacts analyses which assess the impact of air, ground, and water pollution 

on soils, vegetation, and visibility caused by an increase in emissions at the 

subject source. Chapter E identifies class I areas, describes the procedures 

involved in preparing and reviewing a permit application for a proposed source 

with potential class I area air quality impacts. 

Part II of the manual (Chapters F and G) covers the nonattainment area 

(NAA) permit program requirements for new major sources and major 

modifications. Chapter F describes the NAA applicability criteria for new or 

modified stationary sources locating in a nonattainment area. Chapter G 

provides a basic overview of the NAA preconstruction review requirements. 

Part III (Chapters H and I) covers the major source permit itself. 

Chapter H discusses the elements of an effective and enforceable permit. 

Chapter I discusses permit drafting. 

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D R A F T 

OCTOBER 1990 

INTRODUCTION AND OVERVIEW 

Major stationary sources of air pollution and major modifications to 

major stationary sources are required by the Clean Air Act to a obtain an air 

pollution permit before commencing construction. The process is called new 

source review (NSR) and is required whether the major source or modification 

is planned for an area where the national ambient air quality standards 

(NAAQS) are exceeded (nonattainment areas) or an area where air quality is 

acceptable (attainment and unclassifiable areas). Permits for sources in 

attainment areas are referred to as prevention of significant air quality 

deterioration (PSD) permits; while permits for sources located in 

nonattainment areas are referred to as NAA permits. The entire program, 

including both PSD and NAA permit reviews, is referred to as the NSR program. 

The PSD and NAA requirements are pollutant specific. For example, a 

facility may emit many air pollutants, however, depending on the magnitude of 

the emissions of each pollutant, only one or a few may be subject to the PSD 

or NAA permit requirements. Also, a source may have to obtain both PSD and 

NAA permits if the source is in an area where one or more of the pollutants is 

designated nonattainment. 

On August 7, 1977, Congress substantially amended the Clean Air Act and 

outlined a rather detailed PSD program. On June 19, 1978, EPA revised the PSD 

regulations to comply with the 1977 Amendments. The June 1978 regulations 

were challenged in a lengthy judicial review process. As a result of the 

judicial process on August 7, 1980, EPA extensively revised both the PSD and 

NAA regulations. Five sets of regulations resulted from those revisions. 

These regulations and subsequent modifications represent the current NSR 

regulatory requirements. 

The first set of regulations, 40 CFR 51.166, specifies the minimum 

requirements that a PSD air quality permit program under Part C of the Act 

must contain in order to warrant approval by EPA as a revision to a State 

implementation plan (SIP). The second set, 40 CFR 52.21, delineates the 

federal PSD permit program, which currently applies as part of the SIP, in 

approximately one third of States that have not submitted a PSD program 

meeting the requirements of 40 CFR 51.166. In other words, roughly two thirds 

of the States are implementing their own PSD program which has been approved 

by EPA as meeting the minimal requirements for such a program, while the 

remaining States have been delegated the authority to implement the federal 

PSD program. 

The basic goals of the PSD regulations are: (1) to ensure that economic 

growth will occur in harmony with the preservation of existing clean air 

resources to prevent the development of any new nonattainment problems; (2) to 

protect the public health and welfare from any adverse effect which might 

occur even at air pollution levels better than the national ambient air 

quality standards (NAAQS); and (3) to preserve, protect, and enhance the air 

quality in areas of special natural recreational, scenic, or historic value, 

such as national parks and wilderness areas. The primary provisions of the 

3
D R A F T 

OCTOBER 1990 

PSD regulations require that new major stationary sources and major 

modifications be carefully reviewed prior to construction to ensure compliance 

with the NAAQS, the applicable PSD air quality increments, and the requirement 

to apply the BACT on the project's emissions of air pollutants. 

The third set, 40 CFR 51.165(a) and (b), specifies the elements of an 

approvable State permit program for preconstruction review for nonattainment 

purposes under Part D of the Act. A major new source or major modification 

which would locate in an area designated as nonattainment and subject to a NAA 

permit must meet stringent conditions designed to ensure that the new source's 

emissions will be controlled to the greatest degree possible; that more than 

equivalent offsetting emissions reductions ("emission offsets") will be 

obtained from existing sources; and that there will be progress toward 

achievement of the NAAQS. 

The forth and fifth sets, 40 CFR Part 51, Appendix S (Offset Ruling) and 

40 CFR 52.24 (construction moratorium) respectively, can apply in certain 

circumstances where a nonattainment area SIP has not been fully approved by 

EPA as meeting the requirements of Part D of the Act. 

Briefly, the requirements of the PSD regulations apply to new major 

stationary sources and major modifications. A "major stationary source" is 

any source type belonging to a list of 28 source categories which emits or has 

the potential to emit 100 tons per year or more of any pollutant subject to 

regulation under the Act, or any other source type which emits or has the 

potential to emit such pollutants in amounts equal to or greater than 250 tons 

per year. A stationary source generally includes all pollutant-emitting 

activities which belong to the same industrial grouping, are located on 

contiguous or adjacent properties, and are under common control. 

A "major modification" is generally a physical change or a change in the 

method of operation of a major stationary source which would result in a 

contemporaneous significant net emissions increase in the emissions of any 

regulated pollutant. In determining if a proposed increase would cause a 

significant net increase to occur, several detailed calculations must be 

performed. 

If a source or modification thus qualifies as major, its prospective 

location or existing location must also qualify as a PSD area, in order for 

PSD review to apply. A PSD area is one formally designated by the state as 

"attainment" or "unclassifiable" for any pollutant for which a national 

ambient air quality standard exists. 

No source or modification subject to PSD review may be constructed 

without a permit. To obtain a PSD permit an applicant must: 

1. apply the best available control technology (BACT); 

A BACT analysis is done on a case-by-case basis, and 

considers energy, environmental, and economic impacts in 

determining the maximum degree of reduction achievable for the 

proposed source or modification. In no event can the 

4
D R A F T 

OCTOBER 1990 

determination of BACT result in an emission limitation which would 

not meet any applicable standard of performance under 40 CFR Parts 

60 and 61. 

2. conduct an ambient air quality analysis; 

Each PSD source or modification must perform an air quality 

analysis to demonstrate that its new pollutant emissions would not 

violate either the applicable NAAQS or the applicable PSD 

increment. 

3. analyze impacts to soils, vegetation, and visibility; 

An applicant is required to analyze whether its proposed 

emissions increases would impair visibility, or impact on soils or 

vegetation. Not only must the applicant look at the direct effect 

of source emissions on these resources, but it also must consider 

the impacts from general commercial, residential, industrial, and 

other growth associated with the proposed source or modification. 

4. not adversely impact a Class I area; and 

If the reviewing authority receives a PSD permit application 

for a source that could impact a Class I area, it notifies the 

Federal Land Manager and the federal official charged with direct 

responsibility for managing these lands. These officials are 

responsible for protecting the air quality-related values in 

Class I areas and for consulting with the reviewing authority to 

determine whether any proposed construction will adversely affect such 

values. If the Federal Land Manager demonstrates that emissions from a 

proposed source or modification would impair air quality-related values, 

even though the emissions levels would not cause a violation of the 

allowable air quality increment, the Federal Land Manager may recommend 

that the reviewing authority deny the permit. 

5. undergo adequate public participation by applicant. 

Specific public notice requirements and a public comment 

period are required before the PSD review agency takes final 

action on a PSD application. 

5
D R A F T 

OCTOBER 1990 

CHAPTER A 

PSD APPLICABILITY 

I. INTRODUCTION 

An applicability determination, as discussed in this section, is the 

process of determining whether a preconstruction review should be conducted 

by, and a permit issued to, a proposed new source or a modification of an 

existing source by the reviewing authority, pursuant to prevention of 

significant deterioration (PSD) requirements. 

There are three basic criteria in determining PSD applicability. The 

first and primary criterion is whether the proposed project is sufficiently 

large (in terms of its emissions) to be a "major" stationary source or "major" 

modification. Source size is defined in terms of "potential to emit," which 

is its capability at maximum design capacity to emit a pollutant, except as 

constrained by federally-enforceable conditions (which include the effect of 

installed air pollution control equipment and restrictions on the hours of 

operation, or the type or amount of material combusted, stored or processed). 

A new source is major if it has the potential to emit any pollutant 

regulated under the Act in amounts equal to or exceeding specified major 

source thresholds [100 or 250 tons per year (tpy)] which are predicated on the 

source's industrial category. A major modification is a physical change or 

change in the method of operation at an existing major source that causes a 

significant "net emissions increase" at that source of any pollutant regulated 

under the Act. 

The second criterion for PSD applicability is that a new major source 

would locate, or the modified source is located, in a PSD area. A PSD area is 

one formally designated, pursuant to section 107 of the ACT and 40 CFR 81, by 

a State as "attainment" or "unclassifiable" for any criteria pollutant, i.e., 

an air pollutant for which a national ambient air quality standard exists. 

The third criterion is that the pollutants emitted in, or increased by, 

"significant" amounts by the project are subject to PSD. A source's location 

can be attainment or unclassified for some pollutants and simultaneously 

nonattainment for others. If the project would emit only pollutants for which 

the area has been designated nonattainment, PSD would not apply. 

The purposes of a PSD applicability determination are therefore: 

(1) to determine whether a proposed new source is a "major stationary 

source," or if a proposed modification to an existing source is a 

"major modification;" 

(2) to determine if proposed conditions and restrictions, which will 

limit emissions from a new source or an existing source that is 

proposing modification to a level that avoids preconstruction 

review requirements, are legitimate and federally-enforceable; and 

A.1
D R A F T 

OCTOBER 1990 

(3) to determine for a major new source or a major modification to an 

existing source which pollutants are subject to preconstruction 

review. 

In order to perform a satisfactory applicability determination, numerous 

pieces of information must be compiled and evaluated. Certain information and 

analyses are common to applicability determinations for both new sources and 

modified sources; however, there are several major differences. Consequently, 

two detailed discussions follow in this section: PSD applicability 

determinations for major new sources and PSD applicability determinations for 

modifications of existing sources. The common elements will be covered in the 

discussion of new source applicability. They are the following: 

* defining the source; 

* determining the source's potential to emit; 

* determining which major source threshold the source is 

subject to; and 

* assessing the impact on applicability of the local air 

quality, i.e., the attainment designation, in conjunction 

with the pollutants emitted by the source. 

II. NEW SOURCE PSD APPLICABILITY DETERMINATIONS 

II.A. DEFINITION OF SOURCE 

For the purposes of PSD a stationary source is any building, structure, 

facility, or installation which emits or may emit any air pollutant subject to 

regulation under the Clean Air Act (the Act). "Building, structure, facility, 

or installation" means all the pollutant-emitting activities which belong to 

the same industrial grouping, are located on one or more contiguous or 

adjacent properties and are under common ownership or control. An emissions 

unit is any part of a stationary source that emits or has the potential to 

emit any pollutant subject to regulation under the Act. 

The term "same industrial grouping" refers to the "major groups" 

identified by two-digit codes in the Standard Industrial Classification (SIC) 

A.2
D R A F T 

OCTOBER 1990 

Manual, which is published by the Office of Management and Budget. The 1972 

edition of the SIC Manual, as amended in 1977, is cited in the current PSD 

regulations as the basis for classifying sources. Sources not found in that 

edition or the 1977 supplement may be classified according to the most current 

edition. 

For example a chemical complex under common ownership manufactures 

polyethylene, ethylene dichloride, vinyl chloride, and numerous 

other chlorinated organic compounds. Each product is made in 

separate processing equipment with each piece of equipment 

containing several emission units. All of the operations fall under 

SIC Major Group 28, "Chemicals and Allied Products;" therefore, the 

complex and all its associated emissions units constitute one 

source. 

In most cases, the property boundary and ownership are easily 

determined. A frequent question, however, particularly at large industrial 

complexes, is how to deal with multiple emissions units at a single location 

that do not fall under the same two-digit SIC code. In this situation the 

source is classified according to the primary activity at the site, which is 

determined by its principal product (or group of products) produced or 

distributed, or by the services it renders. Facilities that convey, store, or 

otherwise assist in the production of the principal product are called support 

facilities. 

For example, a coal mining operation may include a coal cleaning 

plant, which is located at the mine. If the sole purpose of the 

cleaning plant is to process the coal produced by the mine, then it 

is considered to be a support facility for the mining operation. 

If, however, the cleaning plant is collocated with a mine, but 

accepts more than half of its feedstock from other mines (indicating 

that the activities of the collocated mine are incidental) then coal 

cleaning would be the primary activity and the basis for the 

classification. 

Another common situation is the collocation of power plants with 

manufacturing operations. An example would be a silicon wafer and 

semiconductor manufacturing plant that generates its own steam and 

electricity with fossil fuel-fired boilers. The boilers would be 

considered part of the source because the power plant supports the 

primary activity of the facility. 

A.3
D R A F T 

OCTOBER 1990 

An emissions unit serving as a support facility for two or more primary 

activities (sources) is to be considered part of the primary activity that 

relies most heavily on its support. 

For example, a steam boiler jointly owned and operated by two 

sources would be included with the source that consumes the most 

steam. 

As a corollary to the examples immediately above, suppose a power 

plant, is co-owned by the semiconductor plant and a chemical 

manufacturing plant. The power plant provides 70 percent of its 

total output (in Btu's per hour) as steam and electricity to the 

semiconductor plant. It sells only steam to the chemical plant. In 

the case of co-generation, the support facility should be assigned 

to a primary activity based on pro rata fuel consumption that is 

required to produce the energy bought by each of the support 

facility's customers, since the emission rates in pounds per Btu are 

different for steam and electricity. In this example then, the 

power plant would be considered part of the semiconductor plant. 

It is important to note that if a new support facility would by itself 

be a major source based on its source category classification and potential to 

emit, it would be subject to PSD review even though the primary source, of 

which it is a part, is not major and therefore exempt from review. The 

conditions surrounding such a determination is discussed further in the 

section on major source thresholds (see Section II.C.). 

II.B. POTENTIAL TO EMIT 

II.B.1. BASIC REQUIREMENTS 

The potential to emit of a stationary source is of primary importance in 

establishing whether a new or modified source is major. Potential to emit is 

the maximum capacity of a stationary source to emit a pollutant under its 

physical and operational design. Any physical or operational limitation on 

the capacity of the source to emit a pollutant, provided the limitation or its 

effect on emissions is federally-enforceable, shall be treated as part of its 

design. Example limitations include: 

A.4
D R A F T 

OCTOBER 1990 

(1) Requirements to install and operate air pollution control 

equipment at prescribed efficiencies; 

(2) Restrictions on design capacity utilization [note that these 

types of limitations are not explicitly mentioned in the 

regulations, but in certain instances do meet the criteria 

for limiting potential to emit]; 

(3) Restrictions on hours of operation; and 

(4) Restrictions on the types or amount of material processed, 

combusted or stored. 

II.B.2. ENFORCEABILITY OF LIMITS 

For any limit or condition to be a legitimate restriction on potential 

to emit, that limit or condition must be federally-enforceable, which in turn 

requires practical enforceability (see Appendix A) [see U.S. v. LouisianaPacific Corporation, 682 F. Supp. 1122, Civil Action No. 86-A-1880 

(D. Colorado, March 22, 1988). Practical enforceability means the source

and/or enforcement authority must be able to show continual compliance (or 

noncompliance) with each limitation or requirement. In other words, adequate 

testing, monitoring, and record-keeping procedures must be included either in 

an applicable federally issued permit, or in the applicable federally approved 

SIP or the permit issued under same. 

For example, a permit that limits actual source emissions on an 

annual basis only (e.g., the facility is limited solely to 249 

tpy) cannot be considered in determining potential to emit. It 

contains none of the basic requirements and is therefore not 

capable of ensuring continual compliance, i.e., it is not 

enforceable as a practical matter. 

The term "federally-enforceable" refers to all limitations and 

conditions which are enforceable by the Administrator, including: 

! requirements developed pursuant to any new source 

performance standards (NSPS) or national emission standards 

for hazardous air pollutants (NESHAP), 

A.5
D R A F T 

OCTOBER 1990 

! requirements within any applicable federally-approved State 

implementation plan, and 

! any requirements contained in a permit issued pursuant to 

federal PSD regulations (40 CFR 52.21), or pursuant to PSD 

or operating permit provisions in a SIP which has been 

federally approved in accordance with 40 CFR 51 Subpart I. 

Federally-enforceable permit conditions that may be used to limit 

potential to emit can be expressed in a variety of terms and usually include a 

combination of two or more of the following four requirements in conjunction 

with appropriate record-keeping requirements for verification of compliance: 

(1) Installation and continuous operation and maintenance of air 

pollution controls, usually expressed as both a required 

abatement efficiency of the maximum uncontrolled emission 

rate and a maximum outlet concentration or hourly emission 

rate (flow rate x concentration); 

A typical example might be a 255 tpy limit on a stone crushing 

operation. The enforceable permit conditions could be a maximum 

emission rate of 58 lbs/hr, a maximum concentration of 0.1 grains 

per dry standard cubic foot (gr/dSCF) and a 

67,000 dSCFM based on nameplate capacity and 

In addition, the permit should also stipulate 

overall reduction of particulate matter (PM) 

basis via capture hoods and a baghouse. 

(2) Capacity limitations; 

maximum flow rate of 

8760 hours per year. 

a minimum 90 percent 

emissions on an hourly 

The stone crusher decides to limit its potential to emit to 

180 tpy by limiting the feed rate to 70 percent of the 

nameplate capacity. One of the enforceable limits becomes a 

stone feed rate 

capacity with a 

or device for 

Another approach 

lbs/hr. A 

concentration of 

(tons/hr.) based on 70 percent of nameplate 

federally-enforceable requirement for a method 

measuring the feed rate on an hourly basis. 

is to limit the PM emissions rate to 41 

third alternative is to retain a maximum 

0.1 gr./dSCF, but limit the maximum exhaust 

rate to 47,000 dSCFM due to the decrease in feed rate. In all

these cases, the 90 percent overall reduction of particulate 

matter (PM) emissions on an hourly basis via capture hoods and 

baghouse would also be maintained. 

In another example, the potential to emit of a boiler with a 

design input capacity of 200 million Btu/hour is limited to a 

100-million-Btu/hr fuel input rate by the permit, which 

A.6
D R A F T 

OCTOBER 1990 

requires that the boiler's heat input not exceed 50 percent of 

its rated capacity. The permit would further require that 

compliance be demonstrated with a continuously recording fuel 

meter and concurrent monitoring and recording of fuel heating 

value to show that the fuel input does not exceed 100-millionBtu/hr. 

(3) Restrictions on hours of operation, including seasonal 

operation; and 

In the stone crusher example, the operator may choose to limit 

the hours of operation per year to keep the potential to emit 

below the major source threshold of 250 tpy. For example, 

using the same maximum concentration and flow rate and minimum 

overall control efficiency limitations as in (1) above, a 

restriction on the number of 8-hour shifts to two, i.e., 16 

hours per day would reduce the potential uncontrolled 

emissions by 33 percent to 170 tpy. 

In another example, a citrus dryer that only operates during 

the growing season could have its potential to emit limited by 

a permit restriction on the hours of operation, and further, 

by prohibiting the dryer from operating between March and 

November. 

(4) Limitations on raw materials used (including fuel combusted) 

and stored. 

An example of this type of limit would be a maximum 1 percent 

sulfur content in the coal feed for a power plant. Another 

would be a condition that a surface coater only use waterbased or higher solids coatings with a maximum VOC content of 

2.0 pounds VOC per gallon solids deposited on the substrate 

with requisite limits on coating usage (gallons/hr or 

gallons/yr on a 12-month rolling time period). 

In addition to limits in major source construction permits or federally 

approved SIP limits for major sources, terms and conditions contained in State 

operating permits will be considered federally-enforceable under the following 

conditions: 

(1) the State's operating permit program is approved by EPA and 

incorporated into the applicable SIP under section 110 of the 

Act; 

(2) the operating permits are legally binding on the source under 

the SIP and the SIP specifically provides that permits that 

A.7
D R A F T 

OCTOBER 1990 

are not legally binding may be deemed not "federallyenforceable;" 

(3) all emissions limitations, controls, and other requirements 

imposed by such permits are no less stringent than any 

counterpart limitations and requirements in the SIP, or in 

standards established under sections 111 and 112 of the ACT; 

(4) the limitations, controls and requirements in the operating 

permits are permanent, quantifiable, and otherwise enforceable 

as a practical matter; and 

(5) the permits are issued subject to public participation, i.e., 

timely notice, opportunity for public comment, etc. 

(See also, 54 FR 27281, June 28, 1989.) 

A minor (i.e., a non-major) source construction permit issued to a source 

by a State may be used to determine the potential to emit if: 

! the State program under which the permit was issued has been 

approved by EPA as meeting the requirements of 

40 C.F.R. Parts 51.160 through 51.164, and 

A.8
D R A F T 

OCTOBER 1990 

! the provisions of the permit are federally-enforceable and enforceable as 

a practical matter. 

Note, however, that a permit condition that temporarily restricts 

production to a level at which the source does not intend to operate for any 

extensive time is not valid if it appears to be intended to circumvent the 

preconstruction review requirements for major source by making the source 

temporarily minor. Such permit limits cannot be used in the determination of 

potential to emit. Another situation that should receive careful scrutiny is the 

construction of a manufacturing facility with a physical capacity far greater 

than the limits specified in a permit condition. See also 54 FR 27280, which 

specifically discusses "sham" minor source permits. 

An example is construction of an electric power generating unit, 

which is proposed to be operated as a peaking unit but which by its 

nature can only be economical if it is used as a base-load facility. 

Remember, if the permit or SIP requirements, conditions or limits on a 

source are not federally-enforceable (which includes enforceable as a practical 

matter), potential to emit is based on full capacity and year-round operation. 

For additional information on federally enforceability and limiting potential to 

emit see Appendix A. 

II.B.3. FUGITIVE EMISSIONS 

As defined in the federal PSD regulations, fugitive emissions are those 

"...which could not reasonably pass through a stack, chimney, vent, or other 

functionally equivalent opening." To the extent they are quantifiable, fugitive 

emissions are included in the potential to emit (and increases in same due to 

modification), if they occur at one of the following stationary sources: 

A.9
D R A F T 

OCTOBER 1990 

! Any belonging to one of the 28 named PSD source categories listed in 

Table A-1, which were explicitly identified in Section 169 of the 

Act as being subject to a 100-tpy emissions threshold for 

classification of major sources; 

! Any belonging to a stationary source category that as of August 7, 

1980, is regulated (effective date of proposal) by New Source 

Performance Standards (NSPS) pursuant to Section 111 of the Act 

(listed in Table A-2); and 

! Any belonging to a stationary source category that as of August 7, 

1980, is regulated (effective date of promulgation) by National 

Emissions Standards for Hazardous Air Pollutants (NESHAP) pursuant 

to Section 112 of the Act (listed in Table A-2). 

Note also that, if a source has been determined to be major, fugitive emissions, 

to the extent they are quantifiable, are considered in any subsequent analyses 

(e.g., air quality impact). 

Fugitive emissions may vary widely from source to source. Examples of 

common sources of fugitive emission include: 

! coal piles - particulate matter (PM); 

! road dust - PM; 

! quarries - PM; and 

! leaking valves and flanges at refineries and organic chemical 

processing equipment - volatile organic compounds (VOC). 

A.10
D R A F T 

OCTOBER 1990 

TABLE A-1. PSD SOURCE CATEGORIES WITH 

100 tpy MAJOR SOURCE THRESHOLDS 

4444444444444444444444444444444444444444444444444444444444444444444444444444 

1. Fossil fuel-fired steam electric plants of more than 250 million Btu/hr

heat input

2. Coal cleaning plants (with thermal dryers)

3. Kraft pulp mills

4. Portland cement plants

5. Primary zinc smelters

6. Iron and steel mill plants

7. Primary aluminum ore reduction plants

8. Primary copper smelters

9. Municipal incinerators capable of charging more than 250 tons of refuse

per day

10. Hydrofluoric acid plants

11. Sulfuric acid plants

12. Nitric acid plants

13. Petroleum refineries

14. Lime plants

15. Phosphate rock processing plants

16. Coke oven batteries

17. Sulfur recovery plants

18. Carbon black plants (furnace plants)

19. Primary lead smelters

20. Fuel conversion plants

21. Sintering plants

22. Secondary metal production plants

23. Chemical process plants

24. Fossil fuel boilers (or combinations thereof) totaling more than 250

million Btu/hr heat input

25. Petroleum storage and transfer units with a total storage capacity

exceeding 300,000 barrels

26. Taconite ore processing plants

27. Glass fiber processing plants

28. Charcoal production plants

4444444444444444444444444444444444444444444444444444444444444444444444444444U

A.11
D R A F T 

OCTOBER 1990 

TABLE A-2. NEW SOURCE PERFORMANCE STANDARDS PROPOSED AND 

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 

PROMULGATED PRIOR TO August 7, 1980 

New Source Performance Standards 40 CFR 60 

______________________________________________________________________________ 

Source Subpart Affected Facility Proposed 

Date 

______________________________________________________________________________ 

Phosphate rock NN Grinding, drying and 09/21/79 

plants calcining facilities 

______________________________________________________________________________ 

Ammonium sulfate Pp Ammonium sulfate dryer 02/04/80 

manufacture 

______________________________________________________________________________ 

National Emission Standards for Hazardous Air Pollutants 40 CFR 61 

Pollutant Subpart Affected Facility Promulgated 

Date 

______________________________________________________________________________ 

Beryllium C Extraction plants, 04/06/73 

ceramic plants, 

foundries, incinerators, 

propellant plants, 

machining operations 

______________________________________________________________________________ 

Beryllium, rocket D Rocket motor firing 04/06/73 

motor firing 

______________________________________________________________________________ 

Mercury E Ore processing, 04/06/73 

chloralkali manufacturing, 

sludge incinerators 

______________________________________________________________________________ 

Vinyl chloride F Ethylene dichloride 10/21/76 

manufacture via 02 HC1, 

vinyl chloride manufacture, 

polyvinyl chloride manufacture 

______________________________________________________________________________ 

Asbestos M Asbestos mills; roadway 04/06/73 

surfacing (asbestos tailings); 

demolition; spraying, fabri 

cation, waste disposal and 

insulting 

Manufacture of shotgun 06/19/78

shells, renovation,

fabrication, asphalt concrete,

products containing asbestos

A.12
D R A F T 

OCTOBER 1990 

TABLE A-2. NEW SOURCE PERFORMANCE STANDARDS PROPOSED AND 

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS PROMULGATED PRIOR TO August 7, 1980 

New Source Performance Standards 40 CFR 60 

))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))Q 

Source Subpart Affected Facility Proposed 

Date 

)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))) 

Fossil-fuel fired D Utility and industrial 08/17/71

steam generators for (coal, oil, gas, wood,

which construction lignite)

is commenced after

08/17/71 and before

09/19/78

___________________________________________________________________________

Elect. utility steam Da Utility boilers (solid, 09/19/78

generating units for liquid, and gaseous fuels)

which construction 

is commenced after 

09/18/78

_____________________________________________________________________________

Municipal incineratorsE Incinerators 08/17/71

($50 tons/day)

_____________________________________________________________________________

Portland cement plantsF Kiln, clinker cooler 08/17/71

_____________________________________________________________________________

Nitric acid plants G Process equipment 08/17/71

_____________________________________________________________________________

Sulfuric acid plants H Process equipment 08/17/71

_____________________________________________________________________________

Asphalt concrete I Process equipment 06/11/73

plants

_____________________________________________________________________________

Petroleum refineries J Fuel gas combustion devices 06/11/73

Claus sulfur recovery 

_____________________________________________________________________________ 

Storage vessels for K Gasoline, crude oil, and 06/11/73 

petroleum liquids distillate storage tanks 

construction after $40,000 gallons capacity 

06/11/73 and prior 

to 05/19/78 

_____________________________________________________________________________

Storage vessels for Ka Gasoline, crude oil, and 05/18/78

petroleum liquids distillate storage tanks

construction after $40,000 gallons capacity,

05/18/78 vapor pressure $1.5

_____________________________________________________________________________

Secondary lead L Blast and reverberatory 06/11/73

smelters and furnaces, pot furnaces

refineries

__________________________________________________________________________

A.13
D R A F T 

OCTOBER 1990 

TABLE A-2. NEW SOURCE PERFORMANCE STANDARDS PROPOSED AND 

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS PROMULGATED PRIOR TO August 7, 1980 

New Source Performance Standards 40 CFR 60 

))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))Q 

Source Subpart Affected Facility Proposed 

Date 

)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))) 

Secondary brass M Reverberatory and electric 06/11/73 

and bronze ingot furnaces and blast furnaces 

production plants 

_____________________________________________________________________________ 

Iron and steel mills N Basic oxygen process furnaces 06/11/73 

(BOPF) 

Primary emission sources 

_____________________________________________________________________________ 

Sewage treatment O Sludge incinerators 06/11/73 

plants 

_____________________________________________________________________________ 

Primary copper P Roaster, smelting furnace, 10/16/74 

smelters converter dryers 

_____________________________________________________________________________ 

Primary zinc Q Roaster sintering machine 10/16/74 

smelters 

_____________________________________________________________________________ 

Primary lead R Sintering machine, electric 10/16/74 

smelters smelting furnace, converter 

Blast or reverberatory furnace, 

sintering machine discharge end 

_____________________________________________________________________________ 

Primary aluminum S Pot lines and anode bake 10/23/74 

reduction plants plants 

Primary aluminum Pot lines and anode bake 04/11/79 

reduction plants plants 

111(d) 

_____________________________________________________________________________ 

Phosphate fertilizer T Wet process phosphoric 10/22/74 

industry U Superphosphoric acid 

V Diammonium phosphate 

W Triple superphosphate products 

X Granular triple superphosphate 

products 

_____________________________________________________________________________ 

Coal preparation Y Air tables and thermal dryers 10/24/74 

plants 

_____________________________________________________________________________ 

Ferroalloy Z Specific furnaces 10/21/74 

production facilities 

___________________________________________________________________________

A.14
D R A F T 

OCTOBER 1990 

TABLE A-2. NEW SOURCE PERFORMANCE STANDARDS PROPOSED AND 

NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR 

POLLUTANTS PROMULGATED PRIOR TO August 7, 1980 

New Source Performance Standards 40 CFR 60 

))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))Q 

Source Subpart Affected Facility Proposed 

Date 

)))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))))) 

Steel plants: AA Electric arc furnaces 10/21/74 

electric arc furnaces 

_____________________________________________________________________________ 

Kraft pulp mills BB Digesters, lime kiln 09/24/76 

recovery furnace, washer, 

evaporator, strippers, 

smelt and BLO tanks 

Recovery furnace, lime, 

kiln, smelt tank 

_____________________________________________________________________________ 

Glass manufacturing CC Glass melting furnace 06/15/79 

plants 

_____________________________________________________________________________ 

Grain elevators DD Truck loading and unloading 01/13/77 

stations, barge or ship 

loading and unloading stations 

railcar loading and unloading 

stations, and grain handling 

operations 

_____________________________________________________________________________ 

Stationary gas GG Each gas turbine 10/03/77 

turbines 

_____________________________________________________________________________ 

Lime manufacturing HH Rotary kiln, hydrator 05/03/77 

plants 

_____________________________________________________________________________ 

Degreasers (organic JJ Cold cleaner, vapor 06/11/80 

solvent cleaners) degreaser, conveyorized 

degreaser 

_____________________________________________________________________________ 

Lead acid battery KK Lead oxide production grid 01/14/80 

manufacturing plants casting, paste mixing, threeprocess operation and lead 

reclamation 

_____________________________________________________________________________ 

Automobile and MM Prime, guide coat, and 10/05/79 

light-duty truck top coat operations at 

surface coating assembly plants 

operations 

_____________________________________________________________________________

A.15
D R A F T 

OCTOBER 1990 

Due to the variability even among similar sources, fugitive emissions 

should be quantified through a source-specific engineering analysis. 

Suggested (but by no means all of the useful) references for fugitive 

emissions data and associated analytic techniques are listed in Table A-3. 

Remember, if emissions can be "reasonably" captured and vented through a 

stack they are not considered "fugitive" under EPA regulations. In such 

cases, these emissions, to the extent they are quantifiable, would count 

toward the potential to emit regardless of source or facility type. 

For example, the emissions from a rock crushing operation that 

could reasonably be equipped with a capture hood are not 

considered fugitive and would be included in the source's 

potential to emit. 

As another example, VOC emissions, even if in relatively small 

quantities, coming from leaking valves inside a large furniture 

finishing plant, are typically captured and exhausted through the 

building ventilation system. They are, therefore, measurable and 

should be included in the potential to emit. 

As a counter example, however, it may be unreasonable to expect 

that relatively small quantities of VOC emissions, caused by 

leaking valves at outside storage tanks of the large furniture 

finishing operation, could be captured and vented to a stack. 

II.B.4. SECONDARY EMISSIONS 

Secondary emissions are not considered in the potential emissions 

accounting procedure. Secondary emissions are those emissions which, although 

associated with a source, are not emitted from the source itself. Secondary 

emissions occur from any facility that is not a part of the source being 

reviewed, but which would not be constructed or increase its emissions except 

as a result of the construction or operation of the major stationary source or 

major modification. Secondary emissions do not include any emissions from any 

off-site facility which would be constructed or increase its emissions for 

some reason other than the construction or operation of the major stationary 

source or major modification. 

A.16
D R A F T 

OCTOBER 1990 

TABLE A-3. SUGGESTED REFERENCES FOR ESTIMATING FUGITIVE EMISSIONS 

4444444444444444444444444444444444444444444444444444444444444444444444444444 

1. Emission Factors and Frequency of Leak Occurrence for Fittings in 

Refinery Process Units. Radian Corporation. EPA-600/2-79-044. 

February 1979. 

2. Protocols for Generating Unit - Specific Emission Estimates for 

Equipment Leaks of VOC and VHAP. U.S. Environmental Protection Agency. 

EPA-450/3-88-0100. 

3. Improving Air Quality: Guidance for Estimating Fugitive Emissions From 

Equipment. Chemical Manufacturers Association. January 1989. 

4. Compilation of Air Pollutant Emission Factors, 3rd ed. U.S. 

Environmental Protection Agency. AP-42 (including Supplements 1-8). 

May 1978. 

5. Technical Guidance for Control of Industrial Process Fugitive 

Particulate Emissions. Pedco Environmental, Inc. EPA-450/3-77-010. 

March 1977. 

6. Fugitive Emissions From Integrated Iron and Steel Plants. Midwest 

Research Institute, Inc. EPA-600/2-78-050. March 1978. 

7. Survey of Fugitive Dust from Coal Mines. Pedco Environmental, Inc. 

EPA-908/1-78-003. February 1978. 

8. Workbook on Estimation of Emissions and Dispersion Modeling for Fugitive 

Particulate Sources. Utility Air Regulatory Group. September 1981. 

9. Improved Emission factors for Fugitive Dust from Weston Surface Coal 

Mining Sources, Volumes I and II. U.S. Environmental Protection Agency. 

EPA-600/7-84-048. 

10. Control of Open Fugitive Dust Sources. Midwest Research Institute. 

EPA-450/3-88-008. September 1988. 

4444444444444444444444444444444444444444444444444444444444444444444444444444U 

A.17
D R A F T 

OCTOBER 1990 

An example is the emissions from an existing quarry owned by one 

company that doubles its production to supply aggregate to a 

cement plant proposed for construction as a major source on 

adjacent property by another company. The quarry's increase in 

emissions would be secondary emissions which the cement plant's 

ambient impacts analysis must consider. 

Secondary emissions do not include any emissions which come directly 

from a mobile source, such as emissions from the tailpipe of a motor vehicle 

or from the propulsion unit of a train or a vessel. This exclusion is 

limited, however, to only those mobile sources that are regulated under Title 

II of the Act (see 43 FR 26403 - note #9). Most off-road vehicles are not 

regulated under Title II and are usually treated as area sources. [As a 

result of a court decision in NRDC v. EPA, 725 F.2d 761 (D.C. Circuit 1984), 

emissions from vessels at berth ("dockside") not to be included in the 

determination of secondary emissions but are considered primary emissions for 

applicability purposes.] 

Although secondary emissions are excluded from the potential emissions 

estimates used for applicability determinations, they must be considered in 

PSD analyses if PSD review is required. In order to be considered, however, 

secondary emissions must be specific, well-defined, quantifiable, and impact 

the same general area as the stationary source or modification undergoing 

review. 

II.B.5. REGULATED POLLUTANTS 

The potential to emit must be determined separately for each pollutant 

regulated by the Act and emitted by the new or modified source. Twenty-six 

compounds, 6 criteria and 20 noncriteria, are regulated as air pollutants by 

the Act as of December 31, 1989. They are listed in Table A-4. Note that EPA 

has designated PM-10 (particulate matter with an aerodynamic diameter less 

than 10 microns) as a criteria pollutant by promulgating NAAQS for this 

A.18
D R A F T 

OCTOBER 1990 

pollutant as a replacement for total PM. Thus, the determination of potential 

to emit for PM-10 emissions as well as total PM emissions (which are still 

regulated by many NSPS) is required in applicability determinations. Several 

halons and chlorofluorocarbon (CFC) compounds have been added to the list of 

regulated pollutants as a result of the ratification of the Montreal Protocol 

by the United States in January 1989. 

II.B.6. METHODS FOR DETERMINING POTENTIAL TO EMIT 

In determining a source's potential to emit, two parameters must be 

measured, calculated, or estimated in some way. They are: 

! the worst case uncontrolled emissions rate, which is based 

on the dirtiest fuels, and/or the highest emitting materials 

and operating conditions that the source is or will be 

permitted to use under federally-enforceable requirements, 

and 

! the efficiency of the air pollution control system, if any, 

in use or contemplated for the worst case conditions, where 

the use of such equipment is federally-enforceable. 

A.19
D R A F T 

OCTOBER 1990 

TABLE A-4. SIGNIFICANT EMISSION RATES OF POLLUTANTS 

REGULATED UNDER THE CLEAN AIR ACT 

4444444444444444444444444444444444444444444444444444444444444444444444444444 

Pollutant Emissions rate (tons/year) 

_____________________________________________________________________________ 

Pollutants listed at 40 CFR 52.21(b)(23) 

* Carbon monoxide 

* Nitrogen oxidesa 

* Sulfur dioxideb 

* Particulate matter (PM/PM-10) 

* Ozone (VOC) 

* Lead 

Asbestos 

Beryllium 

Mercury 

Vinyl chloride 

Fluorides 

Sulfuric acid mist 

Hydrogen sulfide (H2S) 

Total Reduced sulfur compounds 

(including H2S) 

100 

40 

40 

25/15 

40 (of VOC's) 

0.6

0.007

0.0004

0.1

1

3

7

10

10

4444444444444444444444444444444444444444444444444444444444444444444444444444 

* Criteria Pollutants a Nitrogen dioxide is the compound regulated as a criteria pollutant; 

however, significant emissions are based on the sum of all oxides of 

nitrogen. b Sulfur dioxide is the measured surrogate for the criteria pollutant 

sulfur oxides. Sulfur oxides have been made subject to regulation 

explicitly through the proposal of 40 CFR 60 Subpart J as of 

August 17, 1989. 

A.20
D R A F T 

OCTOBER 1990 

TABLE A-4. (Concluded) SIGNIFICANT EMISSION RATES OF POLLUTANTS 

REGULATED UNDER THE CLEAN AIR ACT 

4444444444444444444444444444444444444444444444444444444444444444444444444444 

Pollutant Emissions rate (tons/year) 

_____________________________________________________________________________ 

Other pollutants regulated by the Clean Air Act:cd 

Benzene | 

Arsenic | 

Radionuclides | Any emission rate 

Radon-222 | 

Polonium-210 | 

CFC's 11,12, 112, 114, 115 | 

Halons 1211, 1301, 2402 | 

4444444444444444444444444444444444444444444444444444444444444444444444444444 

Significant emission rates have not been promulgated for these pollutants, 

and until such time, any emissions by a new major sources or any increase 

in emissions at an existing major source due to modification, are 

"significant." d Regulations covering several pollutants such as cadmium, coke oven 

emissions, and municipal waste incinerator emissions have recently been 

proposed. Applicants should, therefore, verify what pollutants have been 

regulated under the Act at the time of application. 

A.21

c
D R A F T 

OCTOBER 1990 

Sources of the worst-case uncontrolled emissions and applicable control 

system efficiencies could be any of the following: 

! Emissions data from compliance tests or other source tests, 

! Equipment vendor emissions data and guarantees; 

! Emission limits and test data from EPA documents, including 

background information documents for new source performance 

standards, national emissions standards for hazardous air 

pollutants, and Section 111d standards for designated 

pollutants; 

! AP-42 emission factors (see Table A-3, Reference 2); 

! Emission factors from technical literature; and 

! State emission inventory questionnaires for comparable sources. 

The effect of other restrictions (federally-enforceable and practicallyenforceable) should also be factored into the results. The potential to emit 

of each pollutant, including fugitive emissions if applicable, is estimated 

for each individual emissions unit. The individual estimates are then summed 

by pollutant over all the emissions units at the stationary source. 

II.C. EMISSIONS THRESHOLDS FOR PSD APPLICABILITY 

II.C.1. MAJOR SOURCES 

A source is a "major stationary source" or "major emitting facility" if: 

(1) It can be classified in one of the 28 named source 

categories listed in Section 169 of the CAA (see Table A-1) 

and it emits or has the potential to emit 100 tpy or more of 

any pollutant regulated by the Act, or 

(2) it is any other stationary source that emits or has the 

potential to emit 250 tons per year or more of any pollutant 

regulated by the CAA. 

For example, one of the 28 PSD source categories subject to 

the 100-tpy threshold is fossil fuel-fired steam generators 

with a heat input greater than 250 million Btu/hr. 

Consequently, a 300 million Btu/hr boiler that is designed and 

A.22
D R A F T 

OCTOBER 1990 

permitted to burn any fossil fuel, i.e., coal, oil, natural 

gas or lignite, that emits 100 tpy or more of any regulated 

pollutant, e.g., SO2, is a major stationary source. If, 

however, the boiler were designed and permitted to burn wood 

only, it would not be classified as one of the 28 PSD sources 

and would instead be subject to the 250 tpy threshold. 

A single, fossil fuel-fired boiler with a maximum heat input 

capacity of 300 million Btu/hr takes a federally-enforceable 

design limitation that restricts heat input to 240 million 

Btu/hr. Consequently, this source would not be classified 

within one of the 28 categories and would therefore be subject 

to the 250-tpy, rather than the 100-tpy, emissions threshold. 

A situation frequently occurs in which an emissions unit that is 

included in the 28 listed source categories (and so is subject to a 100 tpy 

threshold), is located within a parent source whose primary activity is not on 

the list (and is therefore subject to a 250 tpy threshold). A source which, 

when considered alone, would be major (and hence subject to PSD) cannot "hide" 

within a different and less restrictive source category in order to escape 

applicability. 

As an example, a proposed coal mining operation will use an on-site coal 

cleaning plant with a thermal dryer. The source will be defined as a coal 

mine because the cleaning plant will only treat coal from the mine. The 

mine's potential to emit (including emissions from the thermal dryer) is 

less than 250 tpy for every regulated pollutant; therefore, it is a 

"minor" source. The estimated emissions from the thermal dryer, however, 

will be 150 tpy particulate matter. Thermal dryers are included in the 

list of 28 source categories that are subject to the 100 tpy major source 

threshold. Consequently, the thermal dryer would be considered an 

emissions unit that by itself is a major source and therefore is subject 

to PSD review, even though the primary activity is not. 

Furthermore, when a "minor" source, i.e., one that does not meet the 

definition of "major," makes a physical change or change in the method of 

operation that is by itself a major source, that physical or operational 

change constitutes a major stationary source that is subject to PSD review. 

A.23
D R A F T 

OCTOBER 1990 

To illustrate, consider the following scenarios at an existing glass fiber 

processing plant, which proposes to add new equipment to increase production. 

Glass fiber processing plants are included in the list of 28 source categories 

that are subject to the 100-tpy major source threshold. The existing plant emits 

40 tpy particulate, which is both its potential to emit and permitted allowable 

rate. It also has a potential to emit all other pollutants in less than major 

quantities; therefore it is a minor source. 

Scenario 1 - The physical change will increase the source's 

potential to emit particulate matter by 50 tpy. Since the plant is 

a minor source and the increase is not major by itself, the change 

is not subject to PSD review. 

Scenario 2 - The physical change will increase the source's 

potential to emit particulate matter by 65 tpy. Since the plant is 

a minor source and the increase is not major by itself, neither is 

subject to PSD review. However, the source's potential to emit 

after the change will exceed the 100-tpy major source threshold, so 

future modifications will be scrutinized under the netting 

provisions (see section A.3.2). 

Scenario 3 - The physical change will increase the source's 

potential to emit particulate matter by 110 tpy. Since the existing 

plant is a minor source and the change by itself results in an 

emissions increase greater than the major source threshold, that 

change is subject to PSD review. Furthermore, the physical change 

makes the entire plant a major source, so future physical changes or 

changes in the method of operation will be scrutinized against the 

criteria for major modifications (see section II.A.3.2). 

II.C.2. SIGNIFICANT EMISSIONS 

A PSD review is triggered in certain instances when emissions associated 

with a new major source or emissions increases resulting from a major 

modification are "significant." "Significant" emissions thresholds are 

defined two ways. The first is in terms of emission rates (tons/year). 

Table A-4 listed the pollutants for which significant emissions rates have 

been established. 

Significant increases in emission rates are subject to PSD review in two 

circumstances: 

A.24
D R A F T 

OCTOBER 1990 

(1) For a new source which is major for at least one regulated attainment or 

noncriteria pollutant, i.e., is subject to PSD review, all pollutants 

for which the area is not classified as nonattainment and which are 

emitted in amounts equal to or greater than those specified in Table A-4 

are also subject to PSD review for its VOC emissions. 

For example, an automotive assembly plant is planned for an attainment area for 

all criteria pollutants. The plant has a potential to emit 350 tpy VOC, 50 tpy 

NOx, 60 tpy SO2,and 10 tpy PM including 5 tpy PM-10. The 350 tpy VOC exceeds 

the major source threshold, and therefore subjects the plant to PSD review. The 

"significant" emissions thresholds for NOx and SO2 are 40 tpy; therefore, the NOx 

and SO2 emissions, also, will be subject to PSD review. The PM and PM-10 

emissions will not exceed their significant emissions thresholds; therefore they 

are not subject to review. 

(2) For a modification to an existing major stationary source, if both the 

potential increase in emissions due to the modification itself, and the 

resulting net emissions increase of any regulated, attainment or 

noncriteria pollutants are equal to or greater than the respective 

pollutants' significant emissions rates listed in Table A-4, the 

modification is "major," and subject to PSD review. Modifications are 

discussed in detail in Section II.D. 

The second type of "significant" emissions threshold is defined as any 

emissions rate at a new major stationary source (or any net emissions increase 

associated with a modification to an existing major stationary source) that is 

constructed within 10 kilometers of a Class I area, and which would increase 

the 24-hour average concentration of any regulated pollutant in that area by 1 

μg/m3

 or greater. Exceedence of this threshold triggers PSD review. 

II.D. LOCAL AIR QUALITY CONSIDERATIONS FOR CRITERIA POLLUTANTS 

The air quality, i.e., attainment status, of the area of a proposed new 

source or modified existing source will impact the applicability determination 

in regard to the pollutants that are subject to PSD review. As previously 

stated, if a new source locates in an area designated attainment or 

unclassifiable for any criteria pollutant, PSD review will apply to any 

A.25
D R A F T 

OCTOBER 1990 

pollutant for which the potential to emit is major (or significant, if the 

source is major) so long as the area is not nonattainment for that pollutant. 

For example, a kraft pulp mill is proposed for an attainment area 

for SO2, and its potential to emit SO2 equals 55 tpy. Its 

potential to emit total reduced sulfur (TRS) a noncriteria 

pollutant, equals 295 tpy. Its potential to emit VOC will be 45 

tpy and PM/PM-10, 30/5 tpy; however, the area is designated 

nonattainment for ozone and PM. Applicability would be assessed 

as follows: 

The source would be major and subject to PSD review due to 

the noncriteria TRS emissions. 

The SO2 emissions would therefore be subject to PSD because 

they are significant and the area is attainment for SO2. 

The VOC emission and PM emissions would not be subject to 

PSD, even though their emissions are significant, because 

the area is designated nonattainment for those pollutants. 

The PM-10 emissions are neither major nor significant and 

would therefore not be subject to review. 

Similarly, if the modification of an existing major source, which is located 

in an attainment area for any criteria pollutant, results in a significant 

increase in potential to emit and a significant net emissions increase, the 

modification is subject to PSD, unless the location is designated as 

nonattainment for that pollutant. 

Note that if the source is major for a pollutant for which an area is 

designated nonattainment, all significant emissions or significant emissions 

increases of pollutants for which the area is attainment or unclassifiable are 

still subject to PSD review. 

II.E. SUMMARY OF MAJOR NEW SOURCE APPLICABILITY 

The elements and associated information necessary for determining PSD 

applicability to new sources are outlined as follows: 

A.26
D R A F T 

OCTOBER 1990 

Element 1 - Define the source 

! includes all related activities classified under the same 2-digit 

SIC Code number 

! must have the same owner or operator 

! must be located on contiguous or adjacent properties 

! includes all support facilities 

Element 2 - Define applicability thresholds for major source as a whole 

(primary activity) 

! 100 tpy for individual emissions units or groups of units 

that are included in the list of 28 source categories 

identified in Section 169 of the CAA 

! 250 tpy for all other sources 

Element 3 - Define project emissions (potential to emit) 

! Reflects federally-enforceable air pollution control efficiency, 

operating conditions, and permit limitations 

! Determined for each pollutant by each emissions unit 

! Summed by pollutant over all emissions units 

! Includes fugitive emissions for 28 listed source categories 

and sources subject to NSPS or NESHAPS as of August 7, 1980 

Element 4 - Assess local area attainment status 

! Area must be attainment or unclassifiable for at least one 

criteria pollutant for PSD to apply 

A.27
D R A F T 

OCTOBER 1990 

Element 5 - Determine if source is major by comparing its potential emissions 

to appropriate major source threshold 

! Major if any pollutant emitted by defined source exceeds 

thresholds, regardless of area designation, i.e., 

attainment, nonattainment, or noncriteria pollutants 

! Individual unit is major if classified as a source in one of 

the 28 regulated source categories and emissions exceed an 

applicable 100-tpy threshold 

Element 6 - Determine pollutants subject to PSD review 

! Each attainment area and noncriteria pollutant emitted in 

"significant" quantities 

! Any emissions or emissions increase from a major source that 

results in an increase of 1 μg/m3

 (24 hour average) or more 

in a Class I area if the major source is located or 

constructed within 10 kilometers of that Class I area. 

II.F. NEW SOURCE APPLICABILITY EXAMPLE 

The following example provided is for illustration only. The example source 

is fictitious and has been created to highlight many of the aspects of the PSD 

applicability process for a new source. 

In this example the proposed project is a new coal-fired electric plant. 

The plant will have two 600-MW lignite-fired boilers. The proposed location 

is near a separately-owned surface lignite mine, which will supply the fuel 

requirements of the power plant, and will therefore, have to increase its 

mining capacity with new equipment. The lignite coal will be mined and then 

transported to the power plant to be crushed, screened, stored, pulverized and 

fed to the boilers. The power plant has informed the lignite coal mine that 

the coal will not have to be cleaned, so the mine will not expand its coal 

cleaning capacity. The power plant will have on-site coal and limestone 

A.28
D R A F T 

OCTOBER 1990 

storage and handling facilities. In addition, a comparatively small auxiliary 

boiler will be installed to provide steam for the facility when the main 

boilers are inoperable. The area is designated attainment for all criteria 

pollutants. 

The applicant proposes pollution control devices for the two 600-MW 

boilers which include: 

- an electrostatic precipitator (ESP) for PM/PM-10 emissions control, 

- a limestone scrubber flue gas desulfurization (FGD) system for 

SO2 emissions control; 

- low-nitrogen oxide (NOx) burners and low-excess-air firing for 

NOx emissions control; and 

- controlled combustion for CO emissions control. 

The first step is to determine what constitutes the source (or sources). 

A source is defined as all pollutant-emitting activities associated with the 

same industrial grouping, located on contiguous or adjacent sites, and under 

common control or ownership. Industrial groupings are generally defined by 

two-digit SIC codes. The power plant is classified as SIC major group 49; the 

nearby mine is SIC major group 12. They are neither under the same SIC major 

group number nor have the same owners, so they constitute separate sources. 

The second step is to establish which major source thresholds are 

applicable in this case. The proposed power plant is a fossil fuel-fired 

steam electric plant with more than 250 million Btu/hr of heat input, making 

it a source included in one of the 28 PSD-listed categories. It is therefore 

subject to both the 100 ton per year criterion for any regulated pollutant 

used to determine whether a source is major and to the requirement that 

quantifiable fugitive emissions be included in determining potential to emit. 

A.29
D R A F T 

OCTOBER 1990 

The emissions units at the mine are neither classified within one of the 

28 PSD source categories nor regulated under Sections 111 or 112 of the Act. 

Therefore, the mine is compared against the 250 tpy major source threshold and 

fugitive emissions from the mining operations are exempt from consideration in 

determining whether the mine is a major stationary source. 

The third step is to define the project emissions. To arrive at the 

potential to emit of the proposed power plant, the applicant must consider all 

quantifiable stack and fugitive emissions of each regulated pollutant (i.e., 

SO2, NOx, PM, PM-10, CO, VOC, lead, and the noncriteria pollutants). 

Therefore, fugitive PM/PM-10 emissions from haul roads, disturbed areas, coal 

piles, and other sources must be included in calculating the power plant's 

potential to emit. 

All stack and fugitive emissions estimates have been obtained through 

detailed engineering analysis of each emissions unit using the best available 

data or estimating technique. Fugitive emissions are added to the emissions 

from the two main boilers and the auxiliary boiler in order to arrive at the 

total potential to emit of each regulated pollutant. The auxiliary boiler in 

this case is restricted by enforceable limits on operating hours proposed to 

be included in the source's PSD permit. If the auxiliary boiler were not 

limited in hours of operation, its contribution would be based on full, 

continuous operation, and the resulting potential emissions estimates would be 

higher. 

The potential to emit SO2, NOx, PM, CO, and sulfuric acid mist each 

exceeds 100 tons per year. From data collected at other lignite fired power 

plants it is known that emissions of lead, beryllium, mercury, fluorides, 

sulfuric acid mist and arsenic should also be quantified. It is known that 

fluoride compounds are contained in the coal in significant quantities; 

however, engineering analyses show fluoride removal in the proposed limestone 

scrubber will result in insignificant stack emissions. Similarly, liquid 

absorption, absorption of fly ash removed in the ESP, and removal of bottom 

A.30
D R A F T 

OCTOBER 1990 

ash have been shown to maintain emissions of lead and the other regulated 

noncriteria pollutants below significance levels. 

The only emissions at the existing mine, and consequently the only 

emissions increase that will occur from the expansion to serve the power 

plant, are fugitive PM/PM-10 emissions from mining operations. The mine's 

potential to emit, for PSD applicability purposes, is zero and the mine is not 

subject to a PSD review. The increase in fugitive emissions from the mine, 

however, will be classified as secondary emissions with respect to the power 

plant and, therefore, must be considered in the air quality analysis and 

additional impacts analysis for the proposed power plant if the power plant is 

subject to PSD review. 

The next step is to compare the potential emissions of the power plant 

to the 100 ton per year major source threshold. If the potential to emit of 

any regulated pollutant is 100 tons per year or more, the power plant is 

classified as a major stationary source for PSD purposes. In this case, the 

plant is classified as a major source because SO2, NOx, PM, CO, and sulfuric 

acid mist emissions each exceed 100 tons per year. (Note that emissions of 

any one of these pollutants classifies the source as major.) 

Once it has been determined that the proposed source is major, any 

regulated pollutant (for which the location of the source is not classified as 

nonattainment) with significant emissions is subject to a PSD review. The 

applicant quantified, through coal and captured fly ash analyses and through 

performance test results from existing sources burning equivalent coals, 

emissions of fluorides, beryllium, lead, mercury, and the other regulated 

noncriteria pollutants to determine if their emissions exceed the significance 

levels (see Table A-4.). Pollutants with less than significant emissions are 

not subject to PSD review requirements (assuming the proposed controls are 

accepted as BACT for SO2, or the application of BACT for SO2 results in 

equivalent or lower noncriteria pollutant emissions). 

A.31
D R A F T 

OCTOBER 1990 

Note that, because the proposed construction site is not within 10 

kilometers of a Class I area, the source's emissions are not subject to the 

Class I area significance criteria. 

A.32
D R A F T 

OCTOBER 1990 

III. MAJOR MODIFICATION APPLICABILITY 

A modification is subject to PSD review only if (1) the existing source 

that is modified is "major," and (2) the net emissions increase of any 

pollutant emitted by the source, as a result of the modification, is 

"significant," i.e., equal to or greater than the emissions rates given on 

Table A-4 (unless the source is located in a nonattainment area for that 

pollutant). Note also that any net emissions increase in a regulated 

pollutant at a major stationary source that is located within 10 kilometers of 

a Class I area, and which will cause an increase of 1 μg/m3

 (24 hour average) 

or more in the ambient concentration of that pollutant within that Class I 

area, is "significant". 

Typical examples of modifications include (but are not limited to) 

replacing a boiler at a chemical plant, construction of a new surface 

coating line at an assembly plant, and a switch from coal to gas requiring 

a physical change to the plant, e.g., new piping, etc. 

As discussed earlier, when a "minor" source, i.e., one that does not meet 

the definition of "major," makes a physical change or change in the method of 

operation that is by itself a major source, that physical or operational change 

constitutes a major stationary source that is subject to PSD review. Also, if 

an existing minor source becomes a major source as a result of a SIP relaxation, 

then it becomes subject to PSD requirements just as if construction had not yet 

commenced on the source or the modification. 

III.A. ACTIVITIES THAT ARE NOT MODIFICATIONS 

The regulations do not define "physical change" or "change in the method 

of operation" precisely; however, they exclude from those activities certain 

specific types of events described below. 

(1) Routine maintenance, repair and replacement. 

A.33
D R A F T 

OCTOBER 1990 

[Sources should discuss any project that will 

significantly increase actual emissions to the 

atmosphere with their respective permitting authority, 

as to whether that project is considered routine 

maintenance, repair or replacement.] 

(2) A fuel switch due to an order under the Energy Supply and 

Environmental Coordination Act of 1974 (or any superseding 

legislation) or due to a natural gas curtailment plan under the 

Federal Power Act. 

(3) A fuel switch due to an order or rule under section 125 of the 

CAA. 

(4) A switch at a steam generating unit to a fuel derived in whole or 

in part from municipal solid waste. 

(5) A switch to a fuel or raw material which (a) the source was 

capable of accommodating before January 6, 1975, so long as 

the switch would not be prohibited by any federallyenforceable permit condition established after that date 

under a federally approved SIP (including any PSD permit 

condition) or a federal PSD permit, or (b) the source is 

approved to make under a PSD permit. 

(6) Any increase in the hours or rate of operation of a source, 

so long as the increase would not be prohibited by any 

federally-enforceable permit condition established after 

January 6, 1975 under a federally approved SIP (including 

any PSD permit condition) or a federal PSD permit. 

(7) A change in the ownership of a stationary source. 

For more details see 40 CFR 52.21(b)(2)(iii). 

Notwithstanding the above, if a significant increase in actual emissions 

of a regulated pollutant occurs at an existing major source as a result of a 

physical change or change in the method of operation of that source, the "net 

emissions increase" of that pollutant must be determined. 

III.B. EMISSIONS NETTING 

Emissions netting is a term that refers to the process of considering 

certain previous and prospective emissions changes at an existing major source 

to determine if a "net emissions increase" of a pollutant will result from a 

A.34
D R A F T 

OCTOBER 1990 

proposed physical change or change in method of operation. If a net emissions 

increase is shown to result, PSD applies to each pollutant's emissions for 

which the net increase is "significant", as shown in Table A-4. 

The process used to determine whether there will be a net emissions 

increase will result uses the following equation: 

Net Emissions Change 

EQUALS 

Emissions increases associated with the proposed modification 

MINUS 

Source-wide creditable contemporaneous emissions decreases 

PLUS 

Source-wide creditable contemporaneous emissions increases 

Consideration of contemporaneous emissions changes is allowed only in cases 

involving existing major sources. In other words, minor sources are not 

eligible to net emissions changes. As discussed earlier, existing minor 

sources are subject to PSD review only when proposing to increase emissions by 

"major" (e.g., 100 or 250 tpy, as applicable) amounts, which, for PSD 

purposes, are considered and reviewed as a major new source. 

For example, an existing minor source (subject to the 100 tpy major source 

cutoff) is proposing a modification which involves the shutdown and 

removal of an old emissions unit (providing an actual contemporaneous 

reduction in NOx emissions of 75 tpy) and the construction of two new 

units with total potential NOx emissions of 110 tpy. Since the existing 

source is minor, the 75 tpy reduction is not considered for PSD 

applicability purposes. Consequently, PSD applies to the new units 

because the emissions increase of 110 tpy is itself "major". The new 

units are then subject to a PSD review for NOx and for any other regulated 

pollutant with a "significant" potential to emit. 

The consideration of contemporaneous emissions changes is also source 

specific. Netting must take place at the same stationary source; emissions 

reductions cannot be traded between stationary sources. 

A.35
D R A F T 

OCTOBER 1990 

III.B.1. ACCUMULATION OF EMISSIONS 

If the proposed emissions increase at a major source is by itself 

(without considering any decreases) less than "significant", EPA policy does 

not require consideration of previous contemporaneous small (i.e., less than 

significant) emissions increases at the source. In other words, the netting 

equation (the summation of contemporaneous emissions increases and decreases) 

is not triggered unless there will be a significant emissions increase from 

the proposed modification. 

For example, a major source experienced less than significant increases of 

NOx (30 tpy) and SO2 (15 tpy) 2 years ago, and a decrease of SO2 (50 tpy) 

3 years ago. The source now proposes to add a new process unit with an 

associated emissions increase of 35 tpy NOx and 80 tpy SO2. For SO2, the 

proposed 80 tpy increase from the modification by itself (before netting) 

is significant. The contemporaneous net emissions change is determined, 

by taking the algebraic sum of (-50) and (+15) and (+80), which equals +45 

tpy. Therefore, the proposed modification is a major modification and a 

PSD review for SO2 is required. However, the NOx increase from the 

proposed modification is by itself less than significant. Consequently, 

netting for PSD applicability purposes is not performed for NOx (even 

though the modification is major for SO2) and a PSD review is not needed 

for NOx. 

It is important to note that when any emissions decrease is claimed (including 

those associated with the proposed modification), all source-wide creditable 

and contemporaneous emissions increases and decreases of the pollutant subject 

to netting must be included in the PSD applicability determination. 

A deliberate decision to split an otherwise "significant" project into 

two or more smaller projects to avoid PSD review would be viewed as 

circumvention and would subject the entire project to enforcement action if 

construction on any of the small projects commences without a valid PSD 

permit. 

For example, an automobile and truck tire manufacturing plant, an existing major 

source, plans to increase its production of both types of tires by 

A.36
D R A F T 

OCTOBER 1990 

"debottlenecking" its production processes. For its passenger tire line,

the source applies for and is granted a "minor" modification permit for a

new extruder that will increase VOC emissions by 39 tons/yr. A few months

later, the source applies for a "minor" modification permit to construct

a new tread-end cementer on the same line which will increase VOC

emissions by 12 tons/yr. The EPA would likely consider these proposals as

an attempt to circumvent the regulations because the two proposals are

related in terms of an

overall project to increase source-wide production capacity. The 

important point in this example is that the two proposals are sufficiently

related that the PSD regulations would consider them a single project. 

Usually, at least two basic questions should be asked when evaluating 

the construction of multiple minor projects to determine if they should have 

been considered a single project. First, were the projects proposed over a 

relatively short period of time? Second, could the changes be considered as 

part of a single project? 

III.B.2. CONTEMPORANEOUS EMISSIONS CHANGES 

The PSD definition of a net emissions increase [40 CFR 52.21(b)(3)(i)] 

consists of two additive components as follows: 

(a) Any increases in actual emissions from a particular physical 

change or change in method of operation at a stationary source; 

and 

(b) Any other increase and decreases in actual emissions at the source 

that are contemporaneous with the particular change and are 

otherwise creditable. 

The first component narrowly includes only the emissions increases 

associated with a particular change at the source. The second component more 

broadly includes all contemporaneous, source-wide (occurring anywhere at the 

entire source), creditable emission increases and decreases. 

To be contemporaneous, changes in actual emissions must have occurred 

after January 6, 1975. The changes must also occur within a period beginning 

5 years before the date construction is expected to commence on the proposed 

A.37
D R A F T 

OCTOBER 1990 

modification (reviewing agencies may use the date construction is scheduled to 

commence provided that it is reasonable considering the time needed to issue a 

final permit) and ending when the emissions increase from the modification 

occurs. An increase resulting from a physical change at a source occurs when 

the new emissions unit becomes operational and begins to emit a pollutant. A 

replacement that requires a shakedown period becomes operational only after a 

reasonable shakedown period, not to exceed 180 days. Since the date 

construction actually will commence is unknown at the time the applicability 

determination takes place and is simply a scheduled date projected by the 

source, the contemporaneous period may shift if construction does not commence 

as scheduled. Many States have developed PSD regulations that allow different 

time frames for definitions of contemporaneous. Where approved by EPA, the 

time periods specified in these regulations govern the contemporaneous 

timeframe. 

III.B.3. CREDITABLE CONTEMPORANEOUS EMISSIONS CHANGES 

There are further restrictions on the contemporaneous emissions changes 

that can be credited in determining net increases. To be creditable, a 

contemporaneous reduction must be federally-enforceable on and after the date 

construction on the proposed modification begins. The actual reduction must 

take place before the date that the emissions increase from any of the new or 

modified emissions units occurs. In addition, the reviewing agency must 

ensure that the source has maintained any contemporaneous decrease which the 

source claims has occurred in the past. The source must either demonstrate 

that the decrease was federally-enforceable at the time the source claims it 

occurred, or it must otherwise demonstrate that the decrease was maintained 

until the present time and will continue until it becomes federallyenforceable. An emissions decrease cannot occur at, and therefore, cannot be 

credited from an emissions unit which was never constructed or operated, 

including units that received a PSD permit. 

Reductions must be of the same pollutant as the emissions increase from 

the proposed modification and must be qualitatively equivalent in their 

A.38
D R A F T 

OCTOBER 1990 

effects on public health and welfare to the effects attributable to the 

proposed increase. Current EPA policy is to assume that an emissions decrease 

will have approximately the same qualitative significance for public health 

and welfare as that attributed to an increase, unless the reviewing agency has 

reason to believe that the reduction in ambient concentrations from the 

emissions decrease will not be sufficient to prevent the proposed emissions 

increase from causing or contributing to a violation of any NAAQS or PSD 

increment. In such cases, the applicant must demonstrate that the proposed 

netting transaction will not cause or contribute to an air quality violation 

before the emissions reduction may be credited. Also, in situations where a 

State is implementing an air toxics program, proposed netting transactions may 

be subject to additional tests regarding the health and welfare equivalency 

demonstration. For example, a State may prohibit netting between certain 

groups of toxic subspecies or apply netting ratios greater than the normally 

required 1:1 between certain groups of toxic pollutants. 

A contemporaneous emissions increase occurs as the result of a physical 

change or change in the method of operation at the source and is creditable to 

the extent that the new emissions level exceeds the old emissions level. The 

"old" emissions level for an emissions unit equals the average rate (in tons 

per year) at which the unit actually emitted the pollutant during the 2-year 

period just prior to the physical or operational change which resulted in the 

emissions increase. In certain limited situations where the applicant 

adequately demonstrates that the prior 2 years is not representative of normal 

source operation, a different (2 year) time period may be used upon a 

determination by the reviewing agency that it is more representative of normal 

source operation. Normal source operations may be affected by strikes, 

retooling, major industrial accidents and other catastrophic occurrences. The 

"new" emissions levels for a new or modified emissions unit which has not 

begun normal operation is its potential to emit. 

An emissions increase or decrease is creditable only if the relevant 

reviewing authority has not relied on it in issuing a PSD permit for the 

source, and the permit is still in effect when the increase in actual 

A.39
D R A F T 

OCTOBER 1990 

emissions from the proposed modification occurs. A reviewing authority relies 

on an increase or decrease when, after taking the increase or decrease into 

account, it concludes that a proposed project would not cause or contribute to 

a violation of an increment or ambient standard. In other words, an emissions 

change at an emissions point which was considered in the issuance of a 

previous PSD permit for the source is not included in the source's "net 

emissions increase" calculation. This is done to avoid "double counting" of 

emissions changes. 

For example, an emissions increase or decrease already considered in a 

source's PSD permit (state or federal) can not be considered a 

contemporaneous increase or decrease since the increases or decrease was 

obviously relied upon for the purpose of issuing the permit. Otherwise 

the increase or decrease would not have been specified in the permit. In 

another example, a decrease in emissions from having previously switched 

to a less polluting fuel (e.g., oil to gas) at an existing emissions unit 

would not be creditable if the source had, in obtaining a PSD permit 

(which is still in effect) for a new emissions unit, modeled the source's 

ambient impact using the less polluting fuel. 

Changes in PM (PM/PM-10), SO2 and NOx emissions are a subset of 

creditable contemporaneous changes that also affect the available increment. 

For these pollutants, emissions changes which do not affect allowable PSD 

increment consumption are not creditable. 

III.B.4. CREDITABLE AMOUNT 

As mentioned above, only contemporaneous and creditable emissions 

changes are considered in determining the source-wide net emissions change. 

All contemporaneous and creditable emissions increases and decreases at the 

source must, however, be considered. The amount of each contemporaneous and 

A.40
D R A F T 

OCTOBER 1990 

creditable emissions increase or decrease involves determining old and new 

actual annual emissions levels for each affected emission unit. 

The following basic criteria should be used when quantifying the increase 

or decrease: 

< For proposed new or modified units which have not begun normal 

operations, the potential to emit must be used to determine the 

increase from the units. 

< For an existing unit, actual emissions just prior to either a 

physical or operational change are based on the lower of the 

actual or allowable emissions levels. This "old" emissions level 

equals the average rate (in tons per year) at which the unit 

actually emitted the pollutant during the 2-year period just prior 

to the change which resulted in the emissions increase. These 

emissions are calculated using the actual hours of operation, 

capacity, fuel combusted and other parameters which affected the 

unit's emissions over the 2-year averaging period. In certain 

limited circumstances, where sufficient representative operating 

data do not exist to determine historic actual emissions and the 

reviewing agency has reason to believe that the source is 

operating at or near its allowable emissions level, the reviewing 

agency may presume that source-specific allowable emissions [or a 

fraction thereof] are equivalent to (and therefore are used in 

place of) actual emissions at the unit. For determining the 

difference in emissions from the change at the unit, emissions 

after the change are the potential to emit from the units. 

< A source cannot receive emission reduction credit for reducing any 

portion of actual emissions which resulted because the source was 

operating out of compliance. 

< An emissions decrease cannot be credited from a unit that has not 

been constructed or operated. 

Examples of how to apply these creditability criteria for 

prospective emissions reductions is shown in Figure A-1. As shown 

in Case I of Figure A-1, the potential to emit for an existing 

emissions unit (which is based on the existing allowable emission 

rate) is greater than the actual emissions, which are based on 

actual operating data (e.g., type and amount of fuel combusted at 

the unit) for the past 2 years. The source proposes to switch to a 

lower sulfur fuel. The amount of the reduction in this case is the 

difference between the actual emissions and the revised allowable 

emissions. (Recall that 

A.41
D R A F T 

OCTOBER 1990 

for reductions to be creditable, the revised allowable emission rate must 

be ensured with federally-enforceable limits.) 

Figure A-1 also illustrates in Case II that the previous allowable 

emissions were much higher than the potential to emit. Common 

examples are PM sources permitted according to process weight tables 

contained in most SIPs. Since process weight tables apply to a 

range of source types, they often overpredict actual emission rates 

for individual sources. In such cases, as in the previous case, the 

only creditable contemporaneous reduction is the difference between 

the actual emissions and the revised allowable emission rate for the 

existing emissions unit. 

Case III in Figure A-1 illustrates a potential violation situation 

where the actual emissions level exceeds allowable limit. The 

creditable reduction in this case is the difference between what the 

emissions would have been from the unit had the source been in 

compliance with its old allowable limits (considering its actual 

operations) and its revised allowable emissions level. 

Consider a more specific example, where a source has an emissions 

unit with an annual allowable emissions rate of 200 tpy based on 

full capacity year-round operation and an hourly unit-specific 

allowable emission rate. The source is, however, out of compliance 

with the allowable hourly emission rate by a factor of two. 

Consequently, if the unit were to be operated year-round at full 

capacity it would emit 400 tpy. However, in this case, although the 

unit operated at full capacity, it was operated on the average 75 

percent of the time for the past 2 years. Consequently, for the 

past 2 years average actual emissions were 300 tpy. The unit is now 

to be shutdown. Assuming the reduction is otherwise creditable, 

the reduction from the shutdown is its allowable emissions prorated 

by its operating factor (200 tpy x .75 = 150 tpy). 

A.42
Case I: Normal Existing Source

Creditable

Reduction

Potential to Emit Actual Revised Allowable

Equals Existing Emissions Emissions

Allowable Emissions

Case II: Existing Source Where Allowable Exceeds Potential

Creditable

Reduction

Existing Potential to Emit Actual Revised Allowable

Allowable at Maximum Capacity Emissions Emissions

Emissions

Case III: Existing Source in Violation of Permit

Creditable

Reduction

Existing Actual Revised Allowable

Allowable Emissions Emissions

Emissions (at 70% Capacity)

(at 70% Capacity)

Figure A-1. Creditable Reductions in Actual Emissions

A.43
D R A F T 

OCTOBER 1990 

III.B.5. SUGGESTED EMISSIONS NETTING PROCEDURE 

Through its review of many emissions netting transactions, EPA has found 

that, either because of confusion or misunderstanding, sources have used 

various netting procedures, some of which result in cases where projects 

should have been subjected to PSD but were not. Some of the most common 

errors include: 

< Not including contemporaneous emissions increases when considering 

decreases; 

< Improperly using allowable emissions instead of actual emissions 

level for the "old" emissions level for existing units; 

< Using prospective (proposed) unrelated emissions decreases to 

counterbalance proposed emission increases without also examining 

all previous contemporaneous emissions changes; 

< Not considering a contemporaneous increase creditable because the 

increase previously netted out of review by relying on a past 

decrease which was, but is no longer, contemporaneous. If 

contemporaneous and otherwise creditable, the increase must be 

considered in the netting calculus. 

< Not properly documenting all contemporaneous emissions changes; 

and 

< Not ensuring that emissions decreases are covered by federallyenforceable restrictions, which is a requirement for 

creditability. 

For the purpose of minimizing confusion and improper applicability 

determinations, the six-step procedure shown in Table A-5 and described below 

is recommended in applying the emissions netting equation. Already assumed in 

this procedure is that the existing source has been defined, its major source 

status has been confirmed and the air quality status in the area is attainment 

for at least one criteria pollutant. 

A.44
D R A F T 

OCTOBER 1990 

TABLE A-5. Procedures for Determining 

the Net Emissions Change at a Source 

______________________________________________________________________________ 

Determine the emissions increases (but not any decreases) from the 

proposed project. If increases are significant, proceed; if not, the 

sources is not subject to review. 

Determine the beginning and ending dates of the contemporaneous period 

as it relates to the proposed modification. 

Determine which emissions units at the source experienced (or will 

experience, including any proposed decreases resulting from the proposed 

project) a creditable increase or decrease in emissions during the 

contemporaneous period. 

Determine which emissions changes are creditable. 

Determine, on a pollutant-by-pollutant basis, the amount of each 

contemporaneous and creditable emissions increase and decrease. 

Sum all contemporaneous and creditable increases and decreases with the 

increase from the proposed modification to determine if a significant 

net emissions increase will occur. 

______________________________________________________________________

A.45
D R A F T 

OCTOBER 1990 

Step 1. Determine the emissions increases from the proposed project. 

First, only the emissions increases expected to result from the proposed 

project are examined. This includes emissions increases from the new 

and modified emissions units and any other plant-wide emissions 

increases (e.g., debottlenecking increases) that will occur as a result 

of the proposed modification. [Proposed emissions decreases occurring 

elsewhere at the source are not considered at this point. Emission 

decreases associated with a proposed project (such as a boiler 

replacement) are contemporaneous and may be considered along with other 

contemporaneous emissions changes at the source. However, they are not 

considered at this point in the analysis.] 

A PSD review applies only to those regulated pollutants with a 

significant emissions increase from the proposed modification. If the 

proposed project will not result in a significant emissions increase of 

any regulated pollutant, the project is exempt from PSD review and the 

PSD applicability process is completed. However, if this is not the 

case, each regulated pollutant to be emitted in a significant amount is 

subject to a PSD review unless the source can demonstrate (using steps 

2-6) that the sum of all other source-wide contemporaneous and 

creditable emissions increases and decreases would be less than 

significant. 

Step 2 Determine the beginning and ending dates of the contemporaneous

period as it relates to the proposed modification.

The period begins on the date 5 years (some States may have a different 

time period) before construction commences on the proposed modification. 

It ends on the date the emissions increase from the proposed 

modification occurs. 

Step 3 Determine which emissions units at the source have experienced an

increase or decrease in emissions during the contemporaneous

period.

Usually, creditable emissions increases are associated with a physical 

change or change in the method of operation at a source which did not 

require a PSD permit. For example, creditable emissions increases may 

come from the construction of a new unit, a fuel switch or an increase 

in operation that (a) would have otherwise been subject to PSD but 

instead netted out of review (per steps 1-6) or (b) resulted in a less 

than significant emissions increase (per step 1). 

Decreases are creditable reductions in actual emissions from an 

emissions unit that are, or can be made, federally-enforceable. A 

A.46
D R A F T 

OCTOBER 1990 

physical change or change in the method of operation is also associated 

with the types of decreases that are creditable. Specifically, in the 

case of an emissions decrease, once the decrease has been made 

federally-enforceable, any proposed increase above the federallyenforceable level must constitute a physical change or change in the 

method of operation at the source or the reduction is not considered 

creditable. For example, a source could only receive an emissions 

decrease for netting purposes from a unit that has been taken out of 

operation if, due to the imposition of federally-enforceable 

restrictions preventing the use of the unit, a proposal to reactivate 

the unit would constitute a physical change or change in the method of 

operation at the source. If operating the unit was not considered a 

physical or operational change, the unit could go back to its prior 

level of operation at any time, thereby producing only a "paper" 

reduction, which is not creditable. 

Step 4 Determine which emissions changes are creditable.

The following basic rules apply: 

1) A increase or decrease is creditable only if the relevant reviewing 

authority has not relied upon it in previously issuing a PSD permit and 

the permit is in effect when the increase from the proposed modification 

occurs. As stated earlier, a reviewing authority "relies" on an 

increase or decrease when, after taking the increase or decrease into 

account, it concludes in issuing a PSD permit that a project would not 

cause or contribute to a violation of a PSD increment or ambient 

standard. 

2) For pollutants with PSD increments (i.e., SO2, particulate matter and 

NOx), an increase or decrease in actual emissions which occurs before 

the baseline date in an area is creditable only if it would be 

considered in calculating how much of an increment remains available for 

the pollutant in question. An example of this situation is a 39 tpy NOx 

emissions increase resulting from a new heater at a major source in 

1987, prior to the NOx increment baseline date. Because these emissions 

do not affect the allowable PSD increment, they need not be considered 

in 1990 when the source proposes another unrelated project. The new 

emissions level for the heater (up to 39 tpy) would be adjusted downward 

to the old level (zero) in the accounting exercise. Likewise, decreases 

which occurred before the baseline date was triggered cannot be credited 

after the baseline date. Such reductions are included in the baseline 

concentration and are not considered in calculating PSD increment 

consumption. 

3) A decrease is creditable only to the extent that it is "federallyenforceable" from the moment that the actual construction begins on the 

proposed modification to the source. The decrease 

A.47
D R A F T 

OCTOBER 1990 

must occur before the proposed emissions increase occurs. An increase 

occurs when the emissions unit on which construction occurred becomes 

operational and begins to emit a particular pollutant. Any replacement 

unit that requires shakedown becomes operational only after a reasonable 

shakedown period not to exceed 180 days. 

4) A decrease is creditable only to the extent that it has the same 

health and welfare significance as the proposed increase from the 

source. 

5) A source cannot take credit for a decrease that it has had to make, 

or will have to make, in order to bring an emissions unit into 

compliance. 

6) A source cannot take credit for an emissions reduction from potential 

emissions from an emissions unit which was permitted but never built or 

operated. 

Step 5 Determine, on a pollutant-by-pollutant basis, the amount of each

contemporaneous and creditable emissions increase and decrease. 

An emissions increase is the amount by which the new level of "actual 

emissions" at the emissions unit exceeds the old level. The old level 

of "actual emissions" is that which prevailed just prior (i.e., prior 2 

year average) to the physical or operational change at that unit which 

caused the increase. The new level is that which prevails just after 

the change. In most cases, the old level is calculated from the unit's 

actual operating data from a 2 year period which directly preceded the 

physical change. The new "actual emissions" level us the lower of the 

unit's "potential" or "allowable" emissions after the change. In other 

words, a contemporaneous emission increase is calculated as the positive 

difference between an emissions unit's potential to emit just after a 

physical or operation change at that unit (not the unit's current actual 

emissions) and the unit's actual emissions just prior to the change. 

An emissions decrease is the amount by which the old level of actual 

emissions or the old level of allowable emissions, whichever is lower, 

exceeds the new level of "actual" emissions. Like emissions increases, 

the old level is calculated from the unit's actual operating data from a 

2 year period which preceded the decrease, and the new emissions level 

will be the lower of the unit's "potential" or "allowable" emissions 

after the change. 

A.48
D R A F T 

OCTOBER 1990 

Figure A-2 shows a example of how old and new actual SO2 emissions levels 

are established for an existing emissions unit at a source. The applicant 

met with the reviewing agency in January 1988, proposing to commence 

construction on a new emissions unit in mid-1988. The contemporaneous 

time frame in this case is from mid-1983 (using EPA's 5-year definition) 

to the expected date of the new boiler start-up, about January 1990. 

In mid-1984 an existing boiler switched to a low sulfur fuel oil. The 

applicant wishes to use the fuel switch as a netting credit. The time 

period for establishing the old SO2 emissions level for the fuel switch is 

the 2 year period preceding the change [mid-1982 to mid-1984, when 

emissions were 600 tpy (mid-1982 through mid-1983) and 500 tpy (mid-1982 

through mid-1983)]. The new SO2 emissions level, 300 tpy, is established 

by the new allowable emissions level (which will be made federallyenforceable). The old level of emissions is 550 tpy (the average of 600 

tpy and 500 tpy). Thus, if this is the only existing SO2 emissions unit 

at the source, a decrease of 250 tpy SO2 emissions (550 tpy minus 300 tpy) 

is creditable towards the emissions proposed for the new boiler. This 

example assumes that the reduction meets all other applicable criteria for 

a creditable emissions decrease. 

Step 6 Sum all contemporaneous and creditable increases and decreases

with the increase from the proposed modification to determine if a

significant net emissions increase will occur.

The proposed project is subject to PSD review for each regulated 

pollutant for which the sum of all creditable emissions increases and 

decreases results in a significant net emissions increase. 

If available, the applicant may consider proposing additional 

prospective and creditable emissions reductions sufficient to provide 

for a less than significant net emissions increase at the source and 

thus avoid PSD review. These reductions can be achieved through either 

application of emissions controls or placing restrictions on the 

operation of existing emissions units. These additional reductions 

would be added to the sum of all other creditable increases and 

decreases. As with all contemporaneous emissions reductions, these 

additional decreases must be based on actual emissions changes, 

federally-enforceable prior to the commencement of construction and 

occur before the new unit begins operation. They must also affect the 

allowable PSD increment, where applicable. 

A.49
0 

200 

400 

600 

800 

D R A F T 

OCTOBER 1990 

SO 2 Emissions Level (tons per year) 

800 

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1980 1981 1982 1983 1984 1985 1986 1987 1988 

"Old" allowable emissions: 700 tpy 

Representative "old" actual emissions level: 550 tpy 

(average actual emissions for mid-82 to mid-84) 

Creditable 

contemporaneous 

emissions 

decrease: 250 tpy 

Constructionto 

commence on 

proposed change 

Date of fuel switch 

Date of fuel switch 

"New" federally enforceable 

allowable emissions: 300 tpy 

600 

400 

200 

Emissions increase 

from proposed change 

0 

Contemporaneous timeframe 

Date 5 years prior to the construction of the proposed change 

Actual average emissions fromthe boiler for 

Allowable emissions fromthe boiler Actual emissions fromthe boiler the two years proir to the fuel switch in mid 1984 

Figure A-2. Establishing "Old" and "New" Representative Actual SO Emissions 

2 

A.50
D R A F T 

OCTOBER 1990 

III.B.6. NETTING EXAMPLE 

An existing source has informed the local air pollution control agency 

that they are planning to construct a new emissions unit "G". The existing 

source is a major source and the construction of unit G will constitute a 

modification to the source. Unit G will be capable of emitting 80 tons per 

year (tpy) of the pollutant after installation of controls. The PSD 

significant emissions level for the pollutant in question is 40 tpy. Existing 

emissions units "A" and "B" at the source are presently permitted at 150 tpy 

each. The applicant has proposed to limit the operation of units A and B, in 

order to net out of PSD review, to 7056 hours per year (42 weeks) by accepting 

federally-enforceable conditions. The applicant has calculated that there 

will be an emissions reduction of -29.2 tpy [150 - 150x(7056/8760)] per unit 

for a total reduction of 58.4 tpy. Thus, the net emissions increase, as 

calculated by the applicant, will be +21.6 tpy (80-58.36). The applicant 

proposes to net out of PSD review citing the +21.6 tpy increase as less than 

the applicable 40 tpy PSD significance level for the pollutant. 

The reviewing agency informed the source that 1) the emissions 

reductions being claimed from units A and B must be based on the prior actual 

emissions, not their allowable emissions and (2) because the increase from the 

modification will be greater than significant, all contemporaneous changes 

must be accounted for (not just proposed decreases) in order to determine the 

net emission change at the source. 

To verify if, indeed, the source will be able to net out of PSD review, 

the reviewing agency requested information on the other emissions points at 

the source, including their actual monthly emissions. For illustrative 

purposes, the actual annual emissions of the pollutant in question from the 

existing emissions points (in this example all emissions points are associated 

with an emissions unit) are given as follows: 

A.51
D R A F T 

OCTOBER 1990 

Actual Emissions (tpy) 

Year Unit A Unit B Unit C Unit D Unit E Unit F 

1983 70 130 60 85 50 0 

1984 75 130 75 75 60 0 

1985 80 150 65 80 65 0 

1986 110 90 0 0 70 0 

1987 115 85 0 0 75 75 

1988 105 75 0 0 65 70 

1989 90 90 0 0 60 65 

The applicant's response indicates that units A and B will not be 

physically modified. However, the information does show that the modification 

will result in the removal of a bottleneck at the plant and that the proposed 

modification will result in an increase in the operation of these units. 

The PSD baseline for the pollutant was triggered in 1978. The history 

of the emissions units at the source is as follows: 

Emissions 

Unit(s) History 

A and B Built in 1972 and still operational 

C and D Built in 1972 and retired from operation 01/86 

E Built in 1972 and still operational 

F PSD permitted unit; construction commenced 01/86 and the unit 

became operational on 01/87 

G New modification; construction scheduled to commence 01/90 and 

the unit is expected to be operational on 01/92 

The contemporaneous period extends from 01/85 (5 years prior to 01/90, 

the projected construction date of the modification) until 01/92 (the date the 

emissions increase from the modification). The net emissions change at the 

source can be formulated in terms of the sum of the unit-by-unit emissions 

changes which are creditable and contemporaneous with the planned 

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modification. Emission changes that are not associated with physical/ 

operational changes are not considered. 

In assessing the creditable contemporaneous changes the permit agency 

considered the following (all numbers are in tpy): 

< Potential to emit is used for a new unit. The new unit will 

receive a federally-enforceable permit restricting allowable 

emissions to 80 tpy, which then becomes its potential to emit. 

Therefore, the new unit represents an increase of +80. 

< Even though units A and B will not be modified, their emissions 

are expected to increase as a result of the modification and the 

anticipated increase must be included as part of the increase from 

the proposed modification. The emissions change for these units 

is based on their allowable emissions after the change minus their 

current actual emissions. Current actual emissions are based on 

the average emissions over the last 2 years. [Note that only the 

operations of exiting units A and B are expected to be affected by 

the modification.] The emissions changes at A and B are 

calculated as follows: 

Unit A's change = +23.3 

{new allowable [150x(7056/8760)] - old actual [(105+90)/2]} 

Unit B's change = +38.3 

{new allowable [150x(7056/8760)] - old actual [(75+90)/2]} 

The federally-enforceable restriction on the hours of operation for 

units A and B act to reduce the amount of the emissions increase at the 

units due to the modification. However, contrary to the applicant's 

analysis, the restrictions did not restrict the units' emissions 

sufficiently to prevent an actual emissions increase. 

< The emissions increase from unit F was permitted under PSD. 

Therefore, having been "relied upon" in the issuance of a PSD 

permit which is still in effect, the permitted emissions increase 

is not creditable and cannot be used in the netting equation. 

< The operation of unit E is not projected to be affected by the 

proposed modification. It has not undergone any physical or 

operational change during the contemporaneous period which would 

otherwise trigger a creditable emissions change at the unit. 

Consequently, unit E's emissions are not considered for netting 

purposes by the reviewing agency. 

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< The retirement (a physical/operational change) of units C and D 

occurred within the contemporaneous period and may provide 

creditable decreases for the applicant. However, if the 

retirement of the units was relied upon in the issuance of the PSD 

permit for unit F (e.g, if the emissions of units C or D were 

modeled at zero in the PSD application) then the reductions would 

not be creditable. If they were not modeled as retired (zero 

emissions), then the reduction would be available as an emissions 

reduction. The reduction credit would be based on the last 2 

years of actual data prior to retirement. As with all reductions, 

to be creditable the retirement of the units must be made 

federally-enforceable prior to construction of the modification to 

and start-up of the source. Upon checking the PSD permit 

application for unit F, the reviewing agency determined that units 

C and D were not considered retired and their emissions were 

included in the ambient impact analysis for unit F. Consequently, 

the emissions reduction from the retirement of unit C and D 

(should the reductions be made federally-enforceable) was 

determined as followed: 

Unit C's change = -70 

{its new allowable [0] - its old actual [(75+65)/2]} 

Unit D's change = -77.5 

{its new allowable [0] - its old actual [(75+80)/2]} 

< The netting transaction would not cause or contribute to a 

violation of the applicable PSD increment or ambient standards. 

The applicant, however, is only willing to accept federally-enforceable 

conditions on the retirement of unit C. Unit D is to be kept as a standby 

unit and the applicant is unwilling to have its potential operation limited. 

Consequently, the reduction in emissions at unit D is not creditable. 

The net contemporaneous emissions change at the source is calculated by 

the reviewing agency as follows: 

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Emissions Change (tpy) 

+80.0 increase from unit G.

+23.3 increase at A from modification at source. 

+38.8 increase at B from modification at source.

-70.0 creditable decrease from retirement of unit C

+72.1 total contemporaneous net emissions increase at the source.

The +72.1 tpy net increase is greater than the +40 tpy PSD significance level; 

consequently the proposed modification is subject to PSD review for that 

pollutant. 

If the applicant is willing to agree to federally-enforceable conditions 

limiting the allowable emissions from unit D (but not necessarily requiring 

the unit's permanent retirement), a sufficient reduction may be available to 

net unit G out of a PSD review. For example, the applicant could agree to 

accept federally-enforceable conditions limiting the operation of unit D to 

672 hours a year (4 weeks), which (for illustrative purposes) equates to an 

allowable emissions of 15 tpy. The creditable reduction from the unit D would 

then amount to -62.5 tpy (-77.5 +15). This brings the total contemporaneous 

net emissions change for the proposed modification to +9.6 tpy (+72.1 - 62.5). 

The construction of Unit G would then not be considered a major modification 

subject to PSD review. It is important to note, however, that if unit D is 

permanently taken out of service after January 1991 and had not operated in 

the interim, the source would not be allowed an emissions reduction credit 

because there would have been no actual emissions decrease during the 

contemporaneous period. In addition, if the source later requests removal of 

restrictions on units which allowed unit G to net out of review, unit G then 

becomes subject to PSD review as though construction had not yet commenced. 

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IV. GENERAL EXEMPTIONS 

IV.A. SOURCES AND MODIFICATIONS AFTER AUGUST 7,1980 

Certain sources may be exempted from PSD review or certain PSD 

requirements. Nonprofit health or educational sources that would otherwise be 

subject to PSD review can be exempted if requested by the Governor of the 

State in which they are located. A portable, major stationary source that has 

previously received a PSD permit and is to be relocated is exempt from a 

second PSD review if (1) emissions at the new location will not exceed 

previously allowed emission rates, (2) the emissions at the new location are 

temporary, and (3) the source will not, because of its new location, adversely 

affect a Class I area or contribute to any known increment or national ambient 

air quality standard (NAAQS) violation. However, the source must provide 

reasonable advance notice to the reviewing authority. 

IV.B. SOURCES CONSTRUCTED PRIOR TO AUGUST 7,1980 

The 1980 PSD regulations do not apply to certain sources affected by 

previous PSD regulations. For example, sources for which construction began 

before August 7, 1977 are exempt from the 1980 PSD regulations and are instead 

reviewed for applicability under the PSD regulations as they existed before 

August 7, 1977. Several exemptions also exist for sources for which 

construction began after August 7, 1977, but before the August 7, 1980 

promulgation of the PSD regulations (45 FR 52676). These exemptions and the 

criteria associated nonapplicability are detailed in paragraph (i) of 

40 CFR 52.21. 

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CHAPTER B

BEST AVAILABLE CONTROL TECHNOLOGY

I. INTRODUCTION 

Any major stationary source or major modification subject to PSD must conduct 

an analysis to ensure the application of best available control 

technology (BACT). The requirement to conduct a BACT analysis and 

determination is set forth in section 165(a)(4) of the Clean Air Act (Act), in 

federal regulations at 40 CFR 52.21(j), in regulations setting forth the 

requirements for State implementation plan approval of a State PSD program at 

40 CFR 51.166(j), and in the SIP's of the various States at 40 CFR Part 52, 

Subpart A - Subpart FFF. The BACT requirement is defined as: 

"an emissions limitation (including a visible emission standard) based 

on the maximum degree of reduction for each pollutant subject to 

regulation under the Clean Air Act which would be emitted from any 

proposed major stationary source or major modification which the 

Administrator, on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, determines is 

achievable for such source or modification through application of 

production processes or available methods, systems, and techniques, 

including fuel cleaning or treatment or innovative fuel combustion 

techniques for control of such pollutant. In no event shall application 

of best available control technology result in emissions of any 

pollutant which would exceed the emissions allowed by any applicable 

standard under 40 CFR Parts 60 and 61. If the Administrator determines 

that technological or economic limitations on the application of 

measurement methodology to a particular emissions unit would make the 

imposition of an emissions standard infeasible, a design, equipment, 

work practice, operational standard, or combination thereof, may be 

prescribed instead to satisfy the requirement for the application of 

best available control technology. Such standard shall, to the degree 

possible, set forth the emissions reduction achievable by implementation 

of such design, equipment, work practice or operation, and shall provide 

for compliance by means which achieve equivalent results." 

During each BACT analysis, which is done on a case-by-case basis, the 

reviewing authority evaluates the energy, environmental, economic and other 

B.1
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OCTOBER 1990 

costs associated with each alternative technology, and the benefit of reduced 

emissions that the technology would bring. The reviewing authority then 

specifies an emissions limitation for the source that reflects the maximum 

degree of reduction achievable for each pollutant regulated under the Act. In 

no event can a technology be recommended which would not meet any applicable 

standard of performance under 40 CFR Parts 60 (New Source Performance 

Standards) and 61 (National Emission Standards for Hazardous Air Pollutants). 

In addition, if the reviewing authority determines that there is no 

economically reasonable or technologically feasible way to accurately measure 

the emissions, and hence to impose an enforceable emissions standard, it may 

require the source to use design, alternative equipment, work practices or 

operational standards to reduce emissions of the pollutant to the maximum 

extent. 

On December 1, 1987, the EPA Assistant Administrator for Air and 

Radiation issued a memorandum that implemented certain program initiatives 

designed to improve the effectiveness of the NSR programs within the confines 

of existing regulations and state implementation plans. Among these was the 

"top-down" method for determining best available control technology (BACT). 

In brief, the top-down process provides that all available control 

technologies be ranked in descending order of control effectiveness. The PSD 

applicant first examines the most stringent--or "top"--alternative. That 

alternative is established as BACT unless the applicant demonstrates, and the 

permitting authority in its informed judgment agrees, that technical 

considerations, or energy, environmental, or economic impacts justify a 

conclusion that the most stringent technology is not "achievable" in that 

case. If the most stringent technology is eliminated in this fashion, then 

the next most stringent alternative is considered, and so on. 

B.2
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OCTOBER 1990 

The purpose of this chapter is to provide a detailed description of the 

top-down method in order to assist permitting authorities and PSD applicants 

in conducting BACT analyses. 

B.3
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OCTOBER 1990 

II. BACT APPLICABILITY 

The BACT requirement applies to each individual new or modified affected 

emissions unit and pollutant emitting activity at which a net emissions 

increase would occur. Individual BACT determinations are performed for each 

pollutant subject to a PSD review emitted from the same emission unit. 

Consequently, the BACT determination must separately address, for each 

regulated pollutant with a significant emissions increase at the source, air 

pollution controls for each emissions unit or pollutant emitting activity 

subject to review. 

B.4
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III. A STEP BY STEP SUMMARY OF THE TOP-DOWN PROCESS 

Table B-1 shows the five basic steps of the top-down procedure, 

including some of the key elements associated with each of the individual 

steps. A brief description of each step follows. 

III.A. STEP 1--IDENTIFY ALL CONTROL TECHNOLOGIES 

The first step in a "top-down" analysis is to identify, for the 

emissions unit in question (the term "emissions unit" should be read to mean 

emissions unit, process or activity), all "available" control options. 

Available control options are those air pollution control technologies or 

techniques with a practical potential for application to the emissions unit 

and the regulated pollutant under evaluation. Air pollution control 

technologies and techniques include the application of production process or 

available methods, systems, and techniques, including fuel cleaning or 

treatment or innovative fuel combustion techniques for control of the affected 

pollutant. This includes technologies employed outside of the United States. 

As discussed later, in some circumstances inherently lower-polluting processes 

are appropriate for consideration as available control alternatives. The 

control alternatives should include not only existing controls for the source 

category in question, but also (through technology transfer) controls applied 

to similar source categories and gas streams, and innovative control 

technologies. Technologies required under lowest achievable emission rate 

(LAER) determinations are available for BACT purposes and must also be 

included as control alternatives and usually represent the top alternative. 

In the course of the BACT analysis, one or more of the options may be 

eliminated from consideration because they are demonstrated to be technically 

infeasible or have unacceptable energy, economic, and environmental impacts on 

a case-by-case (or site-specific) basis. However, at the outset, applicants 

B.5
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OCTOBER 1990 

TABLE B-1. - KEY STEPS IN THE "TOP-DOWN" BACT PROCESS 

STEP 1: IDENTIFY ALL CONTROL TECHNOLOGIES. 

- LIST is comprehensive (LAER included). 

STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS. 

- A demonstration of technical infeasibility should be clearly 

documented and should show, based on physical, chemical, and 

engineering principles, that technical difficulties would preclude 

the successful use of the control option on the emissions unit 

under review. 

STEP 3: RANK REMAINING CONTROL TECHNOLOGIES BY CONTROL EFFECTIVENESS. 

Should include: 

- control effectiveness (percent pollutant removed); 

- expected emission rate (tons per year); 

- expected emission reduction (tons per year); 

- energy impacts (BTU, kWh); 

- environmental impacts (other media and the emissions of toxic and 

hazardous air emissions); and 

- economic impacts (total cost effectiveness, incremental cost 

effectiveness). 

STEP 4: EVALUATE MOST EFFECTIVE CONTROLS AND DOCUMENT RESULTS. 

- Case-by-case consideration of energy, environmental, and economic 

impacts. 

- If top option is not selected as BACT, evaluate next most 

effective control option. 

STEP 5: SELECT BACT 

- Most effective option not rejected is BACT. 

B.6
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OCTOBER 1990 

should initially identify all control options with potential application to 

the emissions unit under review. 

III.B. STEP 2--ELIMINATE TECHNICALLY INFEASIBLE OPTIONS 

In the second step, the technical feasibility of the control options 

identified in step one is evaluated with respect to the source-specific (or 

emissions unit-specific) factors. A demonstration of technical infeasibility 

should be clearly documented and should show, based on physical, chemical, and 

engineering principles, that technical difficulties would preclude the 

successful use of the control option on the emissions unit under review. 

Technically infeasible control options are then eliminated from further 

consideration in the BACT analysis. 

For example, in cases where the level of control in a permit is not 

expected to be achieved in practice (e.g., a source has received a permit but 

the project was cancelled, or every operating source at that permitted level 

has been physically unable to achieve compliance with the limit), and 

supporting documentation showing why such limits are not technically feasible 

is provided, the level of control (but not necessarily the technology) may be 

eliminated from further consideration. However, a permit requiring the 

application of a certain technology or emission limit to be achieved for such 

technology usually is sufficient justification to assume the technical 

feasibility of that technology or emission limit. 

III.C. STEP 3--RANK REMAINING CONTROL TECHNOLOGIES BY CONTROL EFFECTIVENESS 

In step 3, all remaining control alternatives not eliminated in step 2 

are ranked and then listed in order of over all control effectiveness for the 

pollutant under review, with the most effective control alternative at the 

top. A list should be prepared for each pollutant and for each emissions unit 

(or grouping of similar units) subject to a BACT analysis. The list should 

present the array of control technology alternatives and should include the 

following types of information: 

B.7
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OCTOBER 1990 

! control efficiencies (percent pollutant removed); 

! expected emission rate (tons per year, pounds per hour); 

! expected emissions reduction (tons per year); 

! economic impacts (cost effectiveness); 

! environmental impacts (includes any significant or unusual other 

media impacts (e.g., water or solid waste), and, at a minimum, the 

impact of each control alternative on emissions of toxic or hazardous 

air contaminants); 

! energy impacts. 

However, an applicant proposing the top control alternative need not 

provide cost and other detailed information in regard to other control 

options. In such cases the applicant should document that the control option 

chosen is, indeed, the top, and review for collateral environmental impacts. 

III.D. STEP 4--EVALUATE MOST EFFECTIVE CONTROLS AND DOCUMENT RESULTS 

After the identification of available and technically feasible control 

technology options, the energy, environmental, and economic impacts are 

considered to arrive at the final level of control. At this point the 

analysis presents the associated impacts of the control option in the listing. 

For each option the applicant is responsible for presenting an objective 

evaluation of each impact. Both beneficial and adverse impacts should be 

discussed and, where possible, quantified. In general, the BACT analysis 

should focus on the direct impact of the control alternative. 

If the applicant accepts the top alternative in the listing as BACT, the 

applicant proceeds to consider whether impacts of unregulated air pollutants 

or impacts in other media would justify selection of an alternative control 

option. If there are no outstanding issues regarding collateral environmental 

impacts, the analysis is ended and the results proposed as BACT. In the event 

that the top candidate is shown to be inappropriate, due to energy, 

environmental, or economic impacts, the rationale for this finding should be 

B.8
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OCTOBER 1990 

documented for the public record. Then the next most stringent alternative in 

the listing becomes the new control candidate and is similarly evaluated. 

This process continues until the technology under consideration cannot be 

eliminated by any source-specific environmental, energy, or economic impacts 

which demonstrate that alternative to be inappropriate as BACT. 

III.E. STEP 5--SELECT BACT 

The most effective control option not eliminated in step 4 is proposed 

as BACT for the pollutant and emission unit under review. 

B.9
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OCTOBER 1990 

IV. TOP-DOWN ANALYSIS DETAILED PROCEDURE 

IV.A. IDENTIFY ALTERNATIVE EMISSION CONTROL TECHNIQUES (STEP 1) 

The objective in step 1 is to identify all control options with 

potential application to the source and pollutant under evaluation. Later, 

one or more of these options may be eliminated from consideration because they 

are determined to be technically infeasible or to have unacceptable energy, 

environmental or economic impacts. 

Each new or modified emission unit (or logical grouping of new or 

modified emission units) subject to PSD is required to undergo BACT review. 

BACT decisions should be made on the information presented in the BACT 

analysis, including the degree to which effective control alternatives were 

identified and evaluated. Potentially applicable control alternatives can be 

categorized in three ways. 

! Inherently Lower-Emitting Processes/Practices, including the use of 

materials and production processes and work practices that prevent 

emissions and result in lower "production-specific" emissions; and 

! Add-on Controls, such as scrubbers, fabric filters, thermal oxidizers 

and other devices that control and reduce emissions after they are 

produced. 

! Combinations of Inherently Lower Emitting Processes and Add-on 

Controls. For example, the application of combustion and 

post-combustion controls to reduce NOx emissions at a gas-fired 

turbine. 

The top-down BACT analysis should consider potentially applicable 

control techniques from all three categories. Lower-polluting processes 

should be considered based on demonstrations made on the basis of 

manufacturing identical or similar products from identical or similar raw 

materials or fuels. Add-on controls, on the other hand, should be considered 

based on the physical and chemical characteristics of the pollutant-bearing 

emission stream. Thus, candidate add-on controls may have been applied to a 

broad range of emission unit types that are similar, insofar as emissions 

B.10
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OCTOBER 1990 

characteristics, to the emissions unit undergoing BACT review. 

IV.A.1. DEMONSTRATED AND TRANSFERABLE TECHNOLOGIES 

Applicants are expected to identify all demonstrated and potentially 

applicable control technology alternatives. Information sources to consider 

include: 

! EPA's BACT/LAER Clearinghouse and Control Technology Center; 

! Best Available Control Technology Guideline - South Coast Air Quality 

Management District; 

! control technology vendors; 

! Federal/State/Local new source review permits and associated 

inspection/performance test reports; 

! environmental consultants; 

! technical journals, reports and newsletters (e.g., JAPCA and the 

McIvaine reports), air pollution control seminars; and 

! EPA's New Source Review (NSR) bulletin board. 

The applicant should make a good faith effort to compile appropriate 

information from available information sources, including any sources 

specified as necessary by the permit agency. The permit agency should review 

the background search and resulting list of control alternatives presented by 

the applicant to check that it is complete and comprehensive. 

In identifying control technologies, the applicant needs to survey the 

range of potentially available control options. Opportunities for technology 

transfer lie where a control technology has been applied at source categories 

other than the source under consideration. Such opportunities should be 

identified. Also, technologies in application outside the United States to 

the extent that the technologies have been successfully demonstrated in 

practice on full scale operations. Technologies which have not yet been 

applied to (or permitted for) full scale operations need not be considered 

available; an applicant should be able to purchase or construct a process or 

control device that has already been demonstrated in practice. 

B.11
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OCTOBER 1990 

To satisfy the legislative requirements of BACT, EPA believes that the 

applicant must focus on technologies with a demonstrated potential to achieve 

the highest levels of control. For example, control options incapable of 

meeting an applicable New Source Performance Standard (NSPS) or State 

Implementation Plan (SIP) limit would not meet the definition of BACT under 

any circumstances. The applicant does not need to consider them in the BACT 

analysis. 

The fact that a NSPS for a source category does not require a certain 

level of control or particular control technology does not preclude its 

consideration in the top-down BACT analysis. For example, post combustion NOx 

controls are not required under the Subpart GG of the NSPS for Stationary Gas 

Turbines. However, such controls must still be considered available 

technologies for the BACT selection process and be considered in the BACT 

analysis. An NSPS simply defines the minimal level of control to be 

considered in the BACT analysis. The fact that a more stringent technology 

was not selected for a NSPS (or that a pollutant is not regulated by an NSPS) 

does not exclude that control alternative or technology as a BACT candidate. 

When developing a list of possible BACT alternatives, the only reason for 

comparing control options to an NSPS is to determine whether the control 

option would result in an emissions level less stringent than the NSPS. If 

so, the option is unacceptable. 

IV.A.2. INNOVATIVE TECHNOLOGIES 

Although not required in step 1, the applicant may also evaluate and 

propose innovative technologies as BACT. To be considered innovative, a 

control technique must meet the provisions of 40 CFR 52.21(b)(19) or, where 

appropriate, the applicable SIP definition. In essence, if a developing 

B.12
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OCTOBER 1990 

technology has the potential to achieve a more stringent emissions level than 

otherwise would constitute BACT or the same level at a lower cost, it may be 

proposed as an innovative control technology. Innovative technologies are 

distinguished from technology transfer BACT candidates in that an innovative 

technology is still under development and has not been demonstrated in a 

commercial application on identical or similar emission units. In certain 

instances, the distinction between innovative and transferable technology may 

not be straightforward. In these cases, it is recommended that the permit 

agency consult with EPA prior to proceeding with the issuance of an innovative 

control technology waiver. 

In the past only a limited number of innovative control technology 

waivers for a specific control technology have been approved. As a practical 

matter, if a waiver has been granted to a similar source for the same 

technology, granting of additional waivers to similar sources is highly 

unlikely since the subsequent applicants are no longer "innovative". 

IV.A.3. CONSIDERATION OF INHERENTLY LOWER POLLUTING PROCESSES/PRACTICES 

Historically, EPA has not considered the BACT requirement as a means to 

redefine the design of the source when considering available control 

alternatives. For example, applicants proposing to construct a coal-fired 

electric generator, have not been required by EPA as part of a BACT analysis 

to consider building a natural gas-fired electric turbine although the turbine 

may be inherently less polluting per unit product (in this case electricity). 

However, this is an aspect of the PSD permitting process in which states have 

the discretion to engage in a broader analysis if they so desire. Thus, 

a gas turbine normally would not be included in the list of control 

alternatives for a coal-fired boiler. However, there may be instances where, 

in the permit authority's judgment, the consideration of alternative 

production processes is warranted and appropriate for consideration in the 

BACT analysis. A production process is defined in terms of its physical and 

chemical unit operations used to produce the desired product from a specified 

B.13
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OCTOBER 1990 

set of raw materials. In such cases, the permit agency may require the 

applicant to include the inherently lower-polluting process in the list of 

BACT candidates. 

In many cases, a given production process or emissions unit can be made 

to be inherently less polluting (e.g; the use of water-based versus solvent 

based paints in a coating operation or a coal-fired boiler designed to have a 

low emission factor for NOx). In such cases the ability of design 

considerations to make the process inherently less polluting must be 

considered as a control alternative for the source. Inherently lowerpolluting processes/practice are usually more environmentally effective 

because of lower amounts of solid wastes and waste water than are generated 

with add-on controls. These factors are considered in the cost, energy and 

environmental impacts analyses in step 4 to determine the appropriateness of 

the additional add-on option. 

Combinations of inherently lower-polluting processes/practices (or a 

process made to be inherently less polluting) and add-on controls are likely 

to yield more effective means of emissions control than either approach alone. 

Therefore, the option to utilize a inherently lower-polluting process does 

not, in and of itself, mean that no additional add-on controls need be 

included in the BACT analysis. These combinations should be identified in 

step 1 of the top down process for evaluation in subsequent steps. 

IV.A.4. EXAMPLE 

The process of identifying control technology alternatives (step 1 in 

the top-down BACT process) is illustrated in the following hypothetical 

example. 

B.14
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OCTOBER 1990 

Description of Source 

A PSD applicant proposes to install automated surface coating process 

equipment consisting of a dip-tank priming stage followed by a two-step spray 

application and bake-on enamel finish coat. The product is a specialized 

electronics component (resistor) with strict resistance property 

specifications that restrict the types of coatings that may be employed. 

List of Control Options 

The source is not covered by an applicable NSPS. A review of the 

BACT/LAER Clearinghouse and other appropriate references indicates the 

following control options may be applicable: 

Option #1: water-based primer and finish coat; 

[The water-based coatings have never been used in applications similar 

to this.] 

Option #2: low-VOC solvent/high solids coating for primer and finish 

coat; 

[The high solids/low VOC solvent coatings have recently been applied 

with success with similar products (e.g., other types of electrical 

components).] 

Option #3: electrostatic spray application to enhance coating transfer 

efficiency; and 

[Electrostatically enhanced coating application has been applied 

elsewhere on a clearly similar operation.] 

Option #4: emissions capture with add-on control via incineration or 

carbon adsorber equipment. 

[The VOC capture and control option (incineration or carbon adsorber) 

has been used in many cases involving the coating of different products 

and the emission stream characteristics are similar to the proposed 

resistor coating process and is identified as an option available 

through technology transfer.] 

B.15
D R A F T 

OCTOBER 1990 

Since the low-solvent coating, electrostatically enhanced application, 

and ventilation with add-on control options may reasonably be considered for 

use in combination to achieve greater emissions reduction efficiency, a total 

of eight control options are eligible for further consideration. The options 

include each of the four options listed above and the following four 

combinations of techniques: 

Option #5: low-solvent coating with electrostatic applications without 

ventilation and add-on controls; 

Option #6: low-solvent coating without electrostatic applications with 

ventilation and add-on controls; 

Option #7: electrostatic application with add-on control; and 

Option #8: a combination of all three technologies. 

A "no control" option also was identified but eliminated because the 

applicant's State regulations require at least a 75 percent reduction in VOC 

emissions for a source of this size. Because "no control" would not meet the 

State regulations it could not be BACT and, therefore, was not listed for 

consideration in the BACT analysis. 

Summary of Key Points 

The example illustrates several key guidelines for identifying control 

options. These include: 

! All available control techniques must be considered in the BACT 

analysis. 

! Technology transfer must be considered in identifying control 

options. The fact that a control option has never been applied to 

process emission units similar or identical to that proposed does 

not mean it can be ignored in the BACT analysis if the potential for 

its application exists. 

! Combinations of techniques should be considered to the extent they 

result in more effective means of achieving stringent emissions 

levels represented by the "top" alternative, particularly if the 

"top" alternative is eliminated. 

B.16
D R A F T 

OCTOBER 1990 

IV.B. TECHNICAL FEASIBILITY ANALYSIS (STEP 2) 

In step 2, the technical feasibility of the control options identified 

in step 1 is evaluated. This step should be straightforward for control 

technologies that are demonstrated--if the control technology has been 

installed and operated successfully on the type of source under review, it is 

demonstrated and it is technically feasible. For control technologies that 

are not demonstrated in the sense indicated above, the analysis is somewhat 

more involved. 

Two key concepts are important in determining whether an undemonstrated 

technology is feasible: "availability" and "applicability." As explained in 

more detail below, a technology is considered "available" if it can be 

obtained by the applicant through commercial channels or is otherwise 

available within the common sense meaning of the term. An available 

technology is "applicable" if it can reasonably be installed and operated on 

the source type under consideration. A technology that is available and 

applicable is technically feasible. 

Availability in this context is further explained using the following 

process commonly used for bringing a control technology concept to reality as 

a commercial product: 

! concept stage; 

! research and patenting; 

! bench scale or laboratory testing; 

! pilot scale testing; 

! licensing and commercial demonstration; and 

! commercial sales. 

B.17
D R A F T 

OCTOBER 1990 

A control technique is considered available, within the context 

presented above, if it has reached the licensing and commercial sales stage of 

development. A source would not be required to experience extended time 

delays or resource penalties to allow research to be conducted on a new 

technique. Neither is it expected that an applicant would be required to 

experience extended trials to learn how to apply a technology on a totally 

new and dissimilar source type. Consequently, technologies in the pilot scale 

testing stages of development would not be considered available for BACT 

review. An exception would be if the technology were proposed and permitted 

under the qualifications of an innovative control device consistent with the 

provisions of 40 CFR 52.21(v) or, where appropriate, the applicable SIP. 

Commercial availability by itself, however, is not necessarily 

sufficient basis for concluding a technology to be applicable and therefore 

technically feasible. Technical feasibility, as determined in Step 2, also 

means a control option may reasonably be deployed on or "applicable" to the 

source type under consideration. 

Technical judgment on the part of the applicant and the review authority 

is to be exercised in determining whether a control alternative is applicable 

to the source type under consideration. In general, a commercially available 

control option will be presumed applicable if it has been or is soon to be 

deployed (e.g., is specified in a permit) on the same or a similar source 

type. Absent a showing of this type, technical feasibility would be based on 

examination of the physical and chemical characteristics of the pollutantbearing gas stream and comparison to the gas stream characteristics of the 

source types to which the technology had been applied previously. Deployment 

of the control technology on an existing source with similar gas stream 

characteristics is generally sufficient basis for concluding technical 

feasibility barring a demonstration to the contrary. 

B.18
D R A F T 

OCTOBER 1990 

For process-type control alternatives the decision of whether or not it 

is applicable to the source in question would have to be based on an 

assessment of the similarities and differences between the proposed source and 

other sources to which the process technique had been applied previously. 

Absent an explanation of unusual circumstances by the applicant showing why a 

particular process cannot be used on the proposed source the review authority 

may presume it is technically feasible. 

In practice, decisions about technical feasibility are within the 

purview of the review authority. Further, a presumption of technical 

feasibility may be made by the review authority based solely on technology 

transfer. For example, in the case of add-on controls, decisions of this type 

would be made by comparing the physical and chemical characteristics of the 

exhaust gas stream from the unit under review to those of the unit from which 

the technology is to be transferred. Unless significant differences between 

source types exist that are pertinent to the successful operation of the 

control device, the control option is presumed to be technically feasible 

unless the source can present information to the contrary. 

Within the context of the top-down procedure, an applicant addresses the 

issue of technical feasibility in asserting that a control option identified 

in Step 1 is technically infeasible. In this instance, the applicant should 

make a factual demonstration of infeasibility based on commercial 

unavailability and/or unusual circumstances which exist with application of 

the control to the applicant's emission units. Generally, such a 

demonstration would involve an evaluation of the pollutant-bearing gas stream 

characteristics and the capabilities of the technology. Also a showing of 

unresolvable technical difficulty with applying the control would constitute a 

showing of technical infeasibility (e.g., size of the unit, location of the 

proposed site, and operating problems related to specific circumstances of the 

source). Where the resolution of technical difficulties is a matter of cost, 

the applicant should consider the technology as technically feasible. The 

economic feasibility of a control alternative is reviewed in the economic 

impacts portion of the BACT selection process. 

B.19
D R A F T 

OCTOBER 1990 

A demonstration of technical infeasibility is based on a technical 

assessment considering physical, chemical and engineering principles and/or 

empirical data showing that the technology would not work on the emissions 

unit under review, or that unresolvable technical difficulties would preclude 

the successful deployment of the technique. Physical modifications needed to 

resolve technical obstacles do not in and of themselves provide a 

justification for eliminating the control technique on the basis of technical 

infeasibility. However, the cost of such modifications can be considered in 

estimating cost and economic impacts which, in turn, may form the basis for 

eliminating a control technology (see later discussion at V.D.2). 

Vendor guarantees may provide an indication of commercial availability 

and the technical feasibility of a control technique and could contribute to a 

determination of technical feasibility or technical infeasibility, depending 

on circumstances. However, EPA does not consider a vendor guarantee alone to 

be sufficient justification that a control option will work. Conversely, lack 

of a vendor guarantee by itself does not present sufficient justification that 

a control option or an emissions limit is technically infeasible. Generally, 

decisions about technical feasibility will be based on chemical, and 

engineering analyses (as discussed above) in conjunction with information 

about vendor guarantees. 

A possible outcome of the top-down BACT procedures discussed in this 

document is the evaluation of multiple control technology alternatives which 

result in essentially equivalent emissions. It is not EPA's intent to 

encourage evaluation of unnecessarily large numbers of control alternatives 

for every emissions unit. Consequently, judgment should be used in deciding 

what alternatives will be evaluated in detail in the impacts analysis (Step 4) 

of the top-down procedure discussed in a later section. For example, if two 

or more control techniques result in control levels that are essentially 

identical considering the uncertainties of emissions factors and other 

parameters pertinent to estimating performance, the source may wish to point 

this out and make a case for evaluation and use only of the less costly of 

these options. The scope of the BACT analysis should be narrowed in this way 

B.20
D R A F T 

OCTOBER 1990 

only if there is a negligible difference in emissions and collateral 

environmental impacts between control alternatives. Such cases should be 

discussed with the reviewing agency before a control alternative is dismissed 

at this point in the BACT analysis due to such considerations. 

It is encouraged that judgments of this type be discussed during a 

preapplication meeting between the applicant and the review authority. In 

this way, the applicant can be better assured that the analysis to be 

conducted will meet BACT requirements. The appropriate time to hold such a 

meeting during the analysis is following the completion of the control 

hierarchy discussed in the next section. 

Summary of Key Points 

In summary, important points to remember in assessing technical 

feasibility of control alternatives include: 

! A control technology that is "demonstrated" for a given type or class 

of sources is assumed to be technically feasible unless 

source-specific factors exist and are documented to justify technical 

infeasibility. 

! Technical feasibility of technology transfer control candidates 

generally is assessed based on an evaluation of pollutant-bearing gas 

stream characteristics for the proposed source and other source types 

to which the control had been applied previously. 

! Innovative controls that have not been demonstrated on any source 

type similar to the proposed source need not be considered in the 

BACT analysis. 

! The applicant is responsible for providing a basis for assessing 

technical feasibility or infeasibility and the review authority is 

responsible for the decision on what is and is not technically 

feasible. 

B.21
D R A F T 

OCTOBER 1990 

IV.C. RANKING THE TECHNICALLY FEASIBLE ALTERNATIVES TO ESTABLISH A CONTROL 

HIERARCHY (STEP 3) 

Step 3 involves ranking all the technically feasible control 

alternatives 

which have been previously identified in Step 2. For the regulated pollutant 

and emissions unit under review, the control alternatives are ranked-ordered 

from the most to the least effective in terms of emission reduction potential. 

Later, once the control technology is determined, the focus shifts to the 

specific limits to be met by the source. 

Two key issues that must be addressed in this process include: 

! What common units should be used to compare emissions performance 

levels among options? 

! How should control techniques that can operate over a wide range of 

emission performance levels (e.g., scrubbers, etc.) be considered in 

the analysis? 

IV.C.1. CHOICE OF UNITS OF EMISSIONS PERFORMANCE TO COMPARE LEVELS AMONGST 

CONTROL OPTIONS 

In general, this issue arises when comparing inherently lower-polluting 

processes to one another or to add-on controls. For example, direct 

comparison of powdered (and low-VOC) coatings and vapor recovery and control 

systems at a metal furniture finishing operation is difficult because of the 

different units of measure for their effectiveness. In such cases, it is 

generally most effective to express emissions performance as an average steady 

state emissions level per unit of product produced or processed. Examples 

are: 

B.22
D R A F T 

OCTOBER 1990 

! pounds VOC emission per gallons of solids applied, 

! pounds PM emission per ton of cement produced, 

! pounds SO2 emissions per million Btu heat input, and 

! pounds SO2 emission per kilowatt of electric power produced, 

Calculating annual emissions levels (tons/yr) using these units becomes 

straightforward once the projected annual production or processing rates are 

known. The result is an estimate of the annual pollutant emissions that the 

source or emissions unit will emit. Annual "potential" emission projections 

are calculated using the source's maximum design capacity and full year round 

operation (8760 hours), unless the final permit is to include federally 

enforceable conditions restricting the source's capacity or hours of 

operation. However, emissions estimates used for the purpose of calculating 

and comparing the cost effectiveness of a control option are based on a 

different approach (see section V.D.2.b. COST EFFECTIVENESS). 

IV.C.2. CONTROL TECHNIQUES WITH A WIDE RANGE OF EMISSIONS PERFORMANCE LEVELS 

The objective of the top-down BACT analysis is to not only identify the 

best control technology, but also a corresponding performance level (or in 

some cases performance range) for that technology considering source-specific 

factors. Many control techniques, including both add-on controls and 

inherently lower polluting processes can perform at a wide range of levels. 

Scrubbers, high and low efficiency electrostatic precipitators (ESPs), and 

low-VOC coatings are examples of just a few. It is not the EPA's intention to 

require analysis of each possible level of efficiency for a control technique, 

as such an analysis would result in a large number of options. Rather, the 

applicant should use the most recent regulatory decisions and performance data 

for identifying the emissions performance level(s) to be evaluated in all 

cases. 

The EPA does not expect an applicant to necessarily accept an emission 

limit as BACT solely because it was required previously of a similar source 

type. While the most effective level of control must be considered in the 

B.23
D R A F T 

OCTOBER 1990 

BACT analysis, different levels of control for a given control alternative can 

be considered.1 For example, the consideration of a lower level of control 

for a given technology may be warranted in cases where past decisions involved 

different source types. The evaluation of an alternative control level can 

also be considered where the applicant can demonstrate to the satisfaction of 

the permit agency demonstrate that other considerations show the need to 

evaluate the control alternative at a lower level of effectiveness. 

Manufacturer's data, engineering estimates and the experience of other 

sources provide the basis for determining achievable limits. Consequently, in 

assessing the capability of the control alternative, latitude exists to 

consider any special circumstances pertinent to the specific source under 

review, or regarding the prior application of the control alternative. 

However, the basis for choosing the alternate level (or range) of control in 

the BACT analysis must be documented in the application. In the absence of a 

showing of differences between the proposed source and previously permitted 

sources achieving lower emissions limits, the permit agency should conclude 

that the lower emissions limit is representative for that control alternative. 

In summary, when reviewing a control technology with a wide range of 

emission performance levels, it is presumed that the source can achieve the 

same emission reduction level as another source unless the applicant 

demonstrates that there are source-specific factors or other relevant 

information that provide a technical, economic, energy or environmental 

justification to do otherwise. Also, a control technology that has been 

eliminated as having an adverse economic impact at its highest level of 

performance, may be acceptable at a lesser level of performance. For example, 

this can occur when the cost effectiveness of a control technology at its 

1 In reviewing the BACT submittal by a source the permit agency may

determine that an applicant should consider a control technology alternative

otherwise eliminated by the applicant, if the operation of that control

technology at a lower level of control (but still higher than the next control

alternative. For example, while scrubber operating at 98% efficiency may be

eliminated as BACT by the applicant due to source specific economic

considerations, the scrubber operating in the 90% to 95% efficiency range may

not have an adverse economic impact.

B.24 
D R A F T 

OCTOBER 1990 

highest level of performance greatly exceeds the cost of that control 

technology at a somewhat lower level (or range) of performance. 

IV.C.3. ESTABLISHMENT OF THE CONTROL OPTIONS HIERARCHY 

After determining the emissions performance levels (in common units) of 

each control technology option identified in Step 2, a hierarchy is 

established that places at the "top" the control technology option that 

achieves the lowest emissions level. Each other control option is then placed 

after the "top" in the hierarchy by its respective emissions performance 

level, ranked from lowest emissions to highest emissions (most effective to 

least stringent effective emissions control alternative). 

From the hierarchy of control alternatives the applicant should develop 

a chart (or charts) displaying the control hierarchy and, where applicable,: 

! expected emission rate (tons per year, pounds per hour); 

! emissions performance level (e.g., percent pollutant removed, 

emissions per unit product, lb/MMbtu, ppm); 

! expected emissions reduction (tons per year); 

! economic impacts (total annualized costs, cost effectiveness, 

incremental cost effectiveness); 

! environmental impacts (includes any significant or unusual other 

media impacts (e.g., water or solid waste), and the relative ability 

of each control alternative to control emissions of toxic or 

hazardous air contaminants); 

! energy impacts (indicate any significant energy benefits or 

disadvantages). 

B.25
D R A F T 

OCTOBER 1990 

This should be done for each pollutant and for each emissions unit (or 

grouping of similar units) subject to a BACT analysis. The chart is used in 

comparing the control alternatives during step 4 of the BACT selection 

process. Some sample charts are displayed in Table B-2 and Table B-3. 

Completed sample charts accompany the example BACT analyses provided in 

section VI. 

At this point, it is recommended that the applicant contact the 

reviewing agency to determine whether the agency feels that any other 

applicable control alternative should be evaluated or if any issues require 

special attention in the BACT selection process. 

IV.D. THE BACT SELECTION PROCESS (STEP 4) 

After identifying and listing the available control options the next 

step is the determination of the energy, environmental, and economic impacts 

of each option and the selection of the final level of control. The applicant 

is responsible for presenting an evaluation of each impact along with 

appropriate supporting information. Consequently, both beneficial and adverse 

impacts should be discussed and, where possible, quantified. In general, the 

BACT analysis should focus on the direct impact of the control alternative. 

Step 4 validates the suitability of the top control option in the 

listing for selection as BACT, or provides clear justification why the top 

candidate is inappropriate as BACT. If the applicant accepts the top 

alternative in the listing as BACT from an economic and energy standpoint, the 

applicant proceeds to consider whether collateral environmental impacts (e.g., 

emissions of unregulated air pollutants or impacts in other media) would 

justify selection of an alternative control option. If there are no 

outstanding issues regarding collateral environmental impacts, the analysis is 

ended and the results proposed as BACT. In the event that the top candidate 

B.26
D R A F T 

OCTOBER 1990 

TABLE B-2. SAMPLE BACT CONTROL HIERARCHY

Control 

Range level 

of for BACT 

control analysis Emissions 

Pollutant Technology (%) (%) limit 

____________________________________________________________________________ 

SO2 First Alternative 

Second Alternative 

Third Alternative 

Fourth Alternative 

Fifth Alternative 

Baseline Alternative 

80-95 95 15 ppm 

80-95 90 30 ppm 

70-85 85 45 ppm 

40-80 75 75 ppm 

50-85 70 90 ppm 

- - -

B.27
-- --- 

-- -- 

-v roP ZG al- CT --_ 
D R A F T 

OCTOBER 1990 

is shown to be inappropriate, due to energy, environmental, or economic 

impacts, the rationale for this finding needs to be fully documented for the 

public record. Then, the next most effective alternative in the listing 

becomes the new control candidate and is similarly evaluated. This process 

continues until the control technology under consideration cannot be 

eliminated by any source-specific environmental, energy, or economic impacts 

which demonstrate that the alternative is inappropriate as BACT. 

The determination that a control alternative to be inappropriate 

involves a demonstration that circumstances exist at the source which 

distinguish it from other sources where the control alternative may have been 

required previously, or that argue against the transfer of technology or 

application of new technology. Alternately, where a control technique has 

been applied to only one or a very limited number of sources, the applicant 

can identify those characteristic(s) unique to those sources that may have 

made the application of the control appropriate in those case(s) but not for 

the source under consideration. In showing unusual circumstances, objective 

factors dealing with the control technology and its application should be the 

focus of the consideration. The specifics of the situation will determine to 

what extent an appropriate demonstration has been made regarding the 

elimination of the more effective alternative(s) as BACT. In the absence of 

unusual circumstance, the presumption is that sources within the same category 

are similar in nature, and that cost and other impacts that have been borne by 

one source of a given source category may be borne by another source of the 

same source category. 

IV.D.1. ENERGY IMPACTS ANALYSIS 

Applicants should examine the energy requirements of the control 

technology and determine whether the use of that technology results in any 

significant or unusual energy penalties or benefits. A source may, for 

example, benefit from the combustion of a concentrated gas stream rich in 

volatile organic compounds; on the other hand, more often extra fuel or 

electricity is required to power a control device or incinerate a dilute gas 

stream. If such benefits or penalties exist, they should be quantified. 

Because energy penalties or benefits can usually be quantified in terms of 

B.29 
D R A F T 

OCTOBER 1990 

additional cost or income to the source, the energy impacts analysis can, in 

most cases, simply be factored into the economic impacts analysis. However, 

certain types of control technologies have inherent energy penalties 

associated with their use. While these penalties should be quantified, so 

long as they are within the normal range for the technology in question, such 

penalties should not, in general, be considered adequate justification for 

nonuse of that technology. 

Energy impacts should consider only direct energy consumption and not 

indirect energy impacts. For example, the applicant could estimate the direct 

energy impacts of the control alternative in units of energy consumption at 

the source ( e.g., Btu, kWh, barrels of oil, tons of coal). The energy 

requirements of the control options should be shown in terms of total (and in 

certain cases also incremental) energy costs per ton of pollutant removed. 

These units can then be converted into dollar costs and, where appropriate, 

factored into the economic analysis. 

As noted earlier, indirect energy impacts (such as energy to produce raw 

materials for construction of control equipment) generally are not considered. 

However, if the permit authority determines, either independently or based on 

a showing by the applicant, that the indirect energy impact is unusual or 

significant and that the impact can be well quantified, the indirect impact 

may be considered. The energy impact should still focus on the application of 

the control alternative and not a concern over general energy impacts 

associated with the project under review as compared to alternative projects 

for which a permit is not being sought, or as compared to a pollution source 

which the project under review would replace (e.g., it would be inappropriate 

to argue that a cogeneration project is more efficient in the production of 

electricity than the powerplant production capacity it would displace and, 

therefore, should not be required to spend equivalent costs for the control of 

the same pollutant). 

The energy impact analysis may also address concerns over the use of 

locally scarce fuels. The designation of a scarce fuel may vary from region 

to region, but in general a scarce fuel is one which is in short supply 

B.30 
D R A F T 

OCTOBER 1990 

locally and can be better used for alternative purposes, or one which may not 

be reasonably available to the source either at the present time or in the 

near future. 

IV.D.2. COST/ECONOMIC IMPACTS ANALYSIS 

Average and incremental cost effectiveness are the two economic criteria 

that are considered in the BACT analysis. Cost effectiveness, is the dollars 

per ton of pollutant emissions reduced. Incremental cost is the cost per ton 

reduced and should be considered in conjunction with total average 

effectiveness. 

In the economical impacts analysis, primary consideration should be 

given to quantifying the cost of control and not the economic situation of the 

individual source. Consequently, applicants generally should not propose 

elimination of control alternatives on the basis of economic parameters that 

provide an indication of the affordability of a control alternative relative 

to the source. BACT is required by law. Its costs are integral to the 

overall cost of doing business and are not to be considered an afterthought. 

Consequently, for control alternatives that have been effectively employed in 

the same source category, the economic impact of such alternatives on the 

particular source under review should be not nearly as pertinent to the BACT 

decision making process as the average and, where appropriate, incremental 

cost effectiveness of the control alternative. Thus, where a control 

technology has been successfully applied to similar sources in a source 

category, an applicant should concentrate on documenting significant cost 

differences, if any, between the application of the control technology on 

those other sources and the particular source under review. 

Cost effectiveness (dollars per ton of pollutant reduced) values above 

the levels experienced by other sources of the same type and pollutant, are 

taken as an indication that unusual and persuasive differences exist with 

respect to the source under review. In addition, where the cost of a control 

alternative for the specific source reviewed is within the range of normal 

costs for that control alternative, the alternative, in certain limited 

circumstances, may still be eligible for elimination. To justify elimination 

B.31 
D R A F T 

OCTOBER 1990 

of an alternative on these grounds, the applicant should demonstrate to the 

satisfaction of the permitting agency that costs of pollutant removal for the 

control alternative are disproportionately high when compared to the cost of 

control for that particular pollutant and source in recent BACT 

determinations. If the circumstances of the differences are adequately 

documented and explained in the application and are acceptable to the 

reviewing agency they may provide a basis for eliminating the control 

alternative. 

In all cases, economic impacts need to be considered in conjunction with 

energy and environmental impacts (e.g., toxics and hazardous pollutant 

considerations) in selecting BACT. It is possible that the environmental 

impacts analysis or other considerations (as described elsewhere) would 

override the economic elimination criteria as described in this section. 

However, absent overriding environmental impacts concerns or other 

considerations, an acceptable demonstration of a adverse economic impact can 

be adequate basis for eliminating the control alternative. 

IV.D.2.a. ESTIMATING THE COSTS OF CONTROL 

Before costs can be estimated, the control system design parameters must 

be specified. The most important item here is to ensure that the design 

parameters used in costing are consistent with emissions estimates used in 

other portions of the PSD application (e.g., dispersion modeling inputs and 

permit emission limits). In general, the BACT analysis should present vendorsupplied design parameters. Potential sources of other data on design 

parameters are BID documents used to support NSPS development, control 

technique guidelines documents, cost manuals developed by EPA, or control data 

in trade publications. Table B-4 presents some example design parameters 

which are important in determining system costs. 

B.32 
D R A F T 

OCTOBER 1990 

To begin, the limits of the area or process segment to be costed 

specified. This well defined area or process segment is referred to as the 

control system battery limits. The second step is to list and cost each major 

piece of equipment within the battery limits. The top-down BACT analysis 

should provide this list of costed equipment. The basis for equipment cost 

estimates also should be documented, either with data supplied by an equipment 

vendor (i.e., budget estimates or bids) or by a referenced source [such as the 

OAQPS Control Cost Manual (Fourth Edition), EPA 450/3-90-006, January 1990, 

Table B-4]. Inadequate documentation of battery limits is one of the most 

common reasons for confusion in comparison of costs of the same controls 

applied to similar sources. For control options that are defined as 

inherently lower-polluting processes (and not add-on controls), the battery 

limits may be the entire process or project. 

Design parameters should correspond to the specified emission level. 

The equipment vendors will usually supply the design parameters to the 

applicant, who in turn should provide them to the reviewing agency. In order 

to determine if the design is reasonable, the design parameters can be 

compared with those shown in documents such as the OAQPS Control Cost Manual, 

Control Technology for Hazardous Air Pollutants (HAPS) Manual (EPA 625/6-86-

014, September 1986), and background information documents for NSPS and NESHAP 

regulations. If the design specified does not appear reasonable, then the 

applicant should be requested to supply performance test data for the control 

technology in question applied to the same source, or a similar source. 

B.33 
D R A F T 

OCTOBER 1990 

TABLE B-4. EXAMPLE CONTROL SYSTEM DESIGN PARAMETERS 

Control Example Design parameters 

Wet Scrubbers 

Carbon Absorbers 

Condensers 

Incineration 

Electrostatic Precipitator 

Fabric Filter 

Selective Catalytic Reduction 

Scrubber liquor (water, chemicals, etc.) 

Gas pressure drop 

Liquid/gas ratio 

Specific chemical species 

Gas pressure drop 

lbs carbon/lbs pollutant 

Condenser type 

Outlet temperature 

Residence time 

Temperature 

Specific collection area (ft2/acfm) 

Voltage density 

Air to cloth ratio 

Pressure drop 

Space velocity 

Ammonia to NOx molar ratio 

Pressure drop 

Catalyst life 

B.34 
D R A F T 

OCTOBER 1990 

Once the control technology alternatives and achievable emissions performance 

levels have been identified, capital and annual costs are developed. These 

costs form the basis of the cost and economic impacts (discussed later) used 

to determine and document if a control alternative should be eliminated on 

grounds of its economic impacts. 

Consistency in the approach to decision-making is a primary objective of 

the top-down BACT approach. In order to maintain and improve the consistency 

of BACT decisions made on the basis of cost and economic considerations, 

procedures for estimating control equipment costs are based on EPA's OAQPS 

Control cost Manual and are set forth in Appendix B of this document. 

Applicants should closely follow the procedures in the appendix and any 

deviations should be clearly presented and justified in the documentation of 

the BACT analysis. 

Normally the submittal of very detailed and comprehensive project cost 

data is not necessary. However, where initial control cost projections on the 

part of the applicant appear excessive or unreasonable (in light of recent 

cost data) more detailed and comprehensive cost data may be necessary to 

document the applicant's projections. An applicant proposing the top 

alternative usually does not need to provide cost data on the other possible 

control alternatives. 

Total cost estimates of options developed for BACT analyses should be on 

order of plus or minus 30 percent accuracy. If more accurate cost data are 

available (such as specific bid estimates), these should be used. However, 

these types of costs may not be available at the time permit applications are 

being prepared. Costs should also be site specific. Some site specific 

factors are costs of raw materials (fuel, water, chemicals) and labor. For 

example, in some remote areas costs can be unusually high. For example, 

remote locations in Alaska may experience a 40-50 percent premium on 

installation costs. The applicant should document any unusual costing 

assumptions used in the analysis. 

B.35 
D R A F T 

OCTOBER 1990 

IV.D.2.b. COST EFFECTIVENESS 

Cost effectiveness is the economic criterion used to assess the 

potential for achieving an objective at least cost. Effectiveness is measured 

in terms of tons of pollutant emissions removed. Cost is measured in terms of 

annualized control costs. 

The Cost effectiveness calculations can be conducted on an average, or 

incremental basis. The resultant dollar figures are sensitive to the number 

of alternatives costed as well as the underlying engineering and cost 

parameters. There are limits to the use of cost-effectiveness analysis. For 

example, cost-effectiveness analysis should not be used to set the 

environmental objective. Second, cost-effectiveness should, in and of itself, 

not be construed as a measure of adverse economic impacts. There are two 

measures of cost-effectiveness that will be discussed in this section: (1) 

average cost-effectiveness, and (2) incremental cost-effectiveness. 

Average Cost Effectiveness 

Average cost effectiveness (total annualized costs of control divided by 

annual emission reductions, or the difference between the baseline emission 

rate and the controlled emission rate) is a way to present the costs of 

control. Average cost effectiveness is calculated as shown by the following 

formula: 

B.36 
D R A F T 

OCTOBER 1990 

Average cost Effectiveness (dollars per ton removed) = 

Control option annualized cost 

Baseline emissions rate - Control option emissions rate 

Costs are calculated in (annualized) dollars per year ($/yr) and 

emissions 

rates are calculated in tons per year (tons/yr). The result is a cost 

effectiveness number in (annualized) dollars per ton ($/ton) of pollutant 

removed. 

Calculating Baseline Emissions 

The baseline emissions rate represents a realistic scenario of upper 

boundary uncontrolled emissions for the source. The NSPS/NESHAP requirements 

or the application of controls, including other controls necessary to comply 

with State or local air pollution regulations, are not considered in 

calculating the baseline emissions. In other words, baseline emissions are 

essentially uncontrolled emissions, calculated using realistic upper boundary 

operating assumptions. When calculating the cost effectiveness of adding post 

process emissions controls to certain inherently lower polluting processes, 

baseline emissions may be assumed to be the emissions from the lower polluting 

process itself. In other words, emission reduction credit can be taken for 

use of inherently lower polluting processes. 

Estimating realistic upper-bound case scenario does not mean that the 

source operates in an absolute worst case manner all the time. For example, 

in 

developing a realistic upper boundary case, baseline emissions calculations 

can also consider inherent physical or operational constraints on the source. 

Such constraints should accurately reflect the true upper boundary of the 

source's ability to physically operate and the applicant should submit 

documentation to verify these constraints. If the applicant does not 

adequately verify these constraints, then the reviewing agency should not be 

compelled to consider these constraints in calculating baseline emissions. In 

addition, the reviewing agency may require the applicant to calculate cost 

B.37 
D R A F T 

OCTOBER 1990 

effectiveness based on values exceeding the upper boundary assumptions to 

determine whether or not the assumptions have a deciding role in the BACT 

determination. If the assumptions have a deciding role in the BACT 

determination, the reviewing agency should include enforceable conditions in 

the permit to assure that the upper bound assumptions are not exceeded. 

For example, VOC emissions from a storage tank might vary significantly 

with temperature, volatility of liquid stored, and throughput. In this case, 

potential emissions would be overestimated if annual VOC emissions were 

estimated by extrapolating over the course of a year VOC emissions based 

solely on the hottest summer day. Instead, the range of expected temperatures 

should be considered in determining annual baseline emissions. Likewise, 

potential emissions would be overestimated if one assumed that gasoline would 

be stored in a storage tank being built to feed an oil-fired power boiler or 

such a tank will be continually filled and emptied. On the other hand, an 

upper bound case for a storage tank being constructed to store and transfer 

liquid fuels at a marine terminal should consider emissions based on the most 

volatile liquids at a high annual throughput level since it would not be 

unrealistic for the tank to operate in such a manner. 

In addition, historic upper bound operating data, typical for the 

source or industry, may be used in defining baseline emissions in evaluating 

the cost effectiveness of a control option for a specific source. For 

example, if for a source or industry, historical upper bound operations 

call for two shifts a day, it is not necessary to assume full time (8760 

hours) operation on an annual basis in calculating baseline emissions. For 

comparing cost effectiveness, the same realistic upper boundary assumptions 

must, however, be used for both the source in question and other sources (or 

source categories) that will later be compared during the BACT analysis. 

For example, suppose (based on verified historic data regarding the 

industry in question) a given source can be expected to utilize numerous 

colored inks over the course of a year. Each color ink has a different VOC 

content ranging from a high VOC content to a relatively low VOC content. The 

source verifies that its operation will indeed call for the application of 

numerous color inks. In this case, it is more realistic for the baseline 

B.38 
D R A F T 

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emission calculation for the source (and other similar sources) to be based on 

the expected mix of inks that would be expected to result in an upper boundary 

case annual VOC emissions rather than an assumption that only one color (i.e, 

the ink with the highest VOC content) will be applied exclusively during the 

whole year. 

In another example, suppose sources in a particular industry 

historically operate at most at 85 percent capacity. For BACT cost 

effectiveness purposes (but not for applicability), an applicant may calculate 

cost effectiveness using 85 percent capacity. However, in comparing costs 

with similar sources, the applicant must consistently use an 85 percent 

capacity factor for the cost effectiveness of controls on those other sources. 

Although permit conditions are normally used to make operating 

assumptions enforceable, the use of "standard industry practice" parameters 

for cost effectiveness calculations (but not applicability determinations) can 

be acceptable without permit conditions. However, when a source projects 

operating parameters (e.g., limited hours of operation or capacity 

utilization, type of fuel, raw materials or product mix or type) that are 

lower than standard industry practice or which have a deciding role in the 

BACT determination, then these parameters or assumptions must be made 

enforceable with permit conditions. If the applicant will not accept 

enforceable permit conditions, then the reviewing agency should use the 

absolute worst case uncontrolled emissions in calculating baseline emissions. 

This is necessary to ensure that the permit reflects the conditions under 

which the source intends to operate. 

For example, the baseline emissions calculation for an emergency standby 

generator may consider the fact that the source does not intend to operate 

more than 2 weeks a year. On the other hand, baseline emissions associated 

with a base-loaded turbine would not consider limited hours of operation. 

This produces a significantly higher level of baseline emissions than in the 

case of the emergency/standby unit and results in more cost effective 

controls. As a consequence of the dissimilar baseline emissions, BACT for the 

B.39 
D R A F T 

OCTOBER 1990 

two cases could be very different. Therefore, it is important that the 

applicant confirm that the operational assumptions used to define the source's 

baseline emissions (and BACT) are genuine. As previously mentioned, this is 

usually done through enforceable permit conditions which reflect limits on the 

source's operation which were used to calculate baseline emissions. 

In certain cases, such explicit permit conditions may not be necessary. 

For example, a source for which continuous operation would be a physical 

impossibility (by virtue of its design) may consider this limitation in 

estimating baseline emissions, without a direct permit limit on operations. 

However, the permit agency has the responsibility to verify that the source is 

constructed and operated consistent with the information and design 

specifications contained in the permit application. 

For some sources it may be more difficult to define what emissions level 

actually represents uncontrolled emissions in calculating baseline emissions. 

For example, uncontrolled emissions could theoretically be defined for a spray 

coating operation as the maximum VOC content coating at the highest possible 

rate of application that the spray equipment could physically process, (even 

though use of such a coating or application rate would be unrealistic for the 

source). Assuming use of a coating with a VOC content and application rate 

greater than expected is unrealistic and would result in an overestimate in 

the amount of emissions reductions to be achieved by the installation of 

various control options. Likewise, the cost effectiveness of the options 

could consequently be greatly underestimated. To avoid these problems, 

uncontrolled emission factors should be represented by the highest realistic 

VOC content of 

the types of coatings and highest realistic application rates that would be 

used by the source, rather than by highest VOC based coating materials or rate 

of application in general. 

Conversely, if uncontrolled emissions are underestimated, emissions 

reductions to be achieved by the various control options would also be 

underestimated and their cost effectiveness overestimated. For example, this 

type of situation occurs in the previous example if the baseline for the above 

B.40 
D R A F T 

OCTOBER 1990 

coating operation was based on a VOC content coating or application rate that 

is too low [when the source had the ability and intent to utilize (even 

infrequently) a higher VOC content coating or application rate]. 

Incremental Cost Effectiveness 

In addition to the average cost effectiveness of a control option, 

incremental cost effectiveness between control options should also be 

calculated. The incremental cost effectiveness should be examined in 

combination with the total cost effectiveness in order to justify elimination 

of a control option. The incremental cost effectiveness calculation compares 

the costs and emissions performance level of a control option to those of the 

next most stringent option, as shown in the following formula: 

Incremental Cost (dollars per incremental ton removed) = 

Total costs (annualized) of control option - Total costs (annualized) of next control option 

Next control option emission rate - Control option emissions rate 

Care should be exercised in deriving incremental costs of candidate 

control options. Incremental cost-effectiveness comparisons should focus on 

annualized cost and emission reduction differences between dominant 

alternatives. Dominant set of control alternatives are determined by 

generating what is called the envelope of least-cost alternatives. This is a 

graphical plot of total annualized costs for a total emissions reductions for 

all control alternatives identified in the BACT analysis (see Figure B-1). 

For example, assume that eight technically available control options for 

analysis are listed in the BACT hierarchy. These are represented as A through 

H in Figure B-1. In calculating incremental costs, the analysis should only 

be conducted for control options that are dominant among all possible options. 

In Figure B-1, the dominant set of control options, A, B, D, F, G, and H, 

represent the least-cost envelope depicted by the curvilinear line connecting 

them. Points C and E are inferior options and should not be considered in the 

B.41 
D R A F T 

OCTOBER 1990 

A B 

C 

E 

D 

F 

G 

H 

Inferior controls (A,C,E) 

Dominant controls (A, B, D, F, G, H) lie on envelope 

"delta" Emissions Reduction 

"delta" Total Annual Costs 

INCREASING TOTAL ANNUAL COSTS ($/yr) 

INCREASING EMISSIONS REDUCTION (Tons/yr) 

Figure B-1. LEAST-COST ENVELOPE 

B.42 
D R A F T 

OCTOBER 1990 

derivation of incremental cost effectiveness. Points A, C and E represent 

inferior controls because B will buy more emissions reduction for less money 

than A; and similarly, D and F will by more reductions for less money than E, 

respectively. 

Consequently, care should be taken in selecting the dominant set of 

controls when calculating incremental costs. First, the control options need 

to be rank ordered in ascending order of annualized total costs. Then, as 

Figure B-1 illustrates, the most reasonable smooth curve of the control 

options is plotted. The incremental cost effectiveness is then determined by 

the difference in total annual costs between two contiguous options divided by 

the difference in emissions reduction. An example is illustrated in Figure 

B-1 for the incremental cost effectiveness for control option F. The vertical 

distance, "delta" Total Costs Annualized, divided by the horizontal distance, 

"delta" Emissions Reduced (tpy), would be the measure of the incremental cost 

effectiveness for option F. 

A comparison of incremental costs can also be useful in evaluating the 

economic viability of a specific control option over a range of efficiencies. 

For example, depending on the capital and operational cost of a control 

device, total and incremental cost may vary significantly (either increasing 

or decreasing) over the operation range of a control device. 

As a precaution, differences in incremental costs among dominant 

alternatives cannot be used by itself to argue one dominant alternative is 

preferred to another. For example, suppose dominant alternative is preferred 

to another. For example, suppose dominant alternatives B, D and F on the 

least-cost envelope (see Figure B-1) are identified as alternatives for a BACT 

analysis. We may observe the incremental cost effectiveness between dominant 

alternative B and D is $500 per ton whereas between dominant alternative D and 

F is $1000 per ton. Alternative D does not dominate alternative F. Both 

alternatives are dominant and hence on the least cost envelope. Alternative D 

cannot legitimately be preferred to F on grounds of incremental cost 

effectiveness. 

B.43 
D R A F T 

OCTOBER 1990 

In addition, when evaluating the total or incremental cost effectiveness 

of a control alternative, reasonable and supportable assumptions regarding 

control efficiencies should be made. An unrealistically low assessment of the 

emission reduction potential of a certain technology could result in inflated 

cost effectiveness figures. 

The final decision regarding the reasonableness of calculated cost 

effectiveness values will be made by the review authority considering previous 

regulatory decisions. Study cost estimates used in BACT are typically 

accurate to ± 20 to 30 percent. Therefore, control cost options which are 

within ± 20 to 30 percent of each other should generally be considered to be 

indistinguishable when comparing options. 

IV.D.2.c. DETERMINING AN ADVERSE ECONOMIC IMPACT 

It is important to keep in mind that BACT is primarily a technologybased standard. In essence, if the cost of reducing emissions with the top 

control alternative, expressed in dollars per ton, is on the same order as the 

cost previously borne by other sources of the same type in applying that 

control alternative, the alternative should initially be considered 

economically achievable, and therefore acceptable as BACT. However, unusual 

circumstances may greatly affect the cost of controls in a specific 

application. If so they should be documented. An example of an unusual 

circumstance might be the unavailability in an arid region of the large 

amounts of water needed for a scrubbing system. Acquiring water from a 

distant location might add unreasonable costs to the alternative, thereby 

justifying its elimination on economic grounds. Consequently, where unusual 

factors exist that result in cost/economic impacts beyond the range normally 

incurred by other sources in that category, the technology can be eliminated 

provided the applicant has adequately identified the circumstances, including 

the cost or other analyses, that show what is significantly different about 

the proposed source. 

Where the cost of a control alternative for the specific source being 

reviewed is within the range of normal costs for that control alternative, the 

B.44 
D R A F T 

OCTOBER 1990 

alternative may also be eligible for elimination in limited circumstances. 

This may occur, for example, where a control alternative has not been required 

as BACT (or its application as BACT has been extremely limited) and there is a 

clear demarcation between recent BACT control costs in that source category 

and the control costs for sources in that source category which have been 

driven by other constraining factors (e.g., need to meet a PSD increment or a 

NAAQS). 

To justify elimination of an alternative on these grounds, the applicant 

should demonstrate to the satisfaction of the permitting agency that costs of 

pollutant removal (e.g., dollars per total ton removed) for the control 

alternative are disproportionately high when compared to the cost of control 

for the pollutant in recent BACT determinations. Specifically, the applicant 

should document that the cost to the applicant of the control alternative is 

significantly beyond the range of recent costs normally associated with BACT 

for the type of facility (or BACT control costs in general) for the pollutant. 

This type of analysis should demonstrate that a technically and economically 

feasible control option is nevertheless, by virtue of the magnitude of its 

associated costs and limited application, unreasonable or otherwise not 

"achievable" as BACT in the particular case. Total and incremental cost 

effectiveness numbers are factored into this type of analysis. However, such 

economic information should be coupled with a comprehensive demonstration, 

based on objective factors, that the technology is inappropriate in the 

specific circumstance. 

The economic impact portion of the BACT analysis should not focus on 

inappropriate factors or exclude pertinent factors, as the results may be 

misleading. For example, the capital cost of a control option may appear 

excessive when presented by itself or as a percentage of the total project 

cost. However, this type of information can be misleading. If a large 

emissions reduction is projected, low or reasonable cost effectiveness numbers 

may validate the option as an appropriate BACT alternative irrespective of the 

apparent high capital costs. In another example, undue focus on incremental 

cost effectiveness can give an impression that the cost of a control 

B.45 
D R A F T 

OCTOBER 1990 

alternative is unreasonably high, when, in fact, the total cost effectiveness, 

in terms of dollars per total ton removed, is well within the normal range of 

acceptable BACT costs. 

IV.D.3. ENVIRONMENTAL IMPACTS ANALYSIS 

The environmental impacts analysis is not to be confused with the air 

quality impact analysis (i.e., ambient concentrations), which is an 

independent statutory and regulatory requirement and is conducted separately 

from the BACT analysis. The purpose of the air quality analysis is to 

demonstrate that the source (using the level of control ultimately determined 

to be BACT) will not cause or contribute to a violation of any applicable 

national ambient air quality standard or PSD increment. Thus, regardless of 

the level of control proposed as BACT, a permit cannot be issued to a source 

that would cause or contribute to such a violation. In contrast, the 

environmental impacts portion of the BACT 

analysis concentrates on impacts other than impacts on air quality (i.e., 

ambient concentrations) due to emissions of the regulated pollutant in 

question, such as solid or hazardous waste generation, discharges of polluted 

water from a control device, visibility impacts, or emissions of unregulated 

pollutants. 

Thus, the fact that a given control alternative would result in only a 

slight decrease in ambient concentrations of the pollutant in question when 

compared to a less stringent control alternative should not be viewed as an 

adverse environmental impact justifying rejection of the more stringent 

control alternative. However, if the cost effectiveness of the more stringent 

alternative is exceptionally high, it may (as provided in section V.D.2.) be 

considered in determining the existence of an adverse economic impact that 

would justify rejection of the more stringent alternative. 

B.46 
D R A F T 

OCTOBER 1990 

The applicant should identify any significant or unusual environmental 

impacts associated with a control alternative that have the potential to 

affect the selection or elimination of a control alternative. Some control 

technologies may have potentially significant secondary (i.e., collateral) 

environmental impacts. Scrubber effluent, for example, may affect water 

quality and land use. Similarly, emissions of water vapor from technologies 

using cooling towers may affect local visibility. Other examples of secondary 

environmental impacts could include hazardous waste discharges, such as spent 

catalysts or contaminated carbon. Generally, these types of environmental 

concerns become important when sensitive site-specific receptors exist or when 

the incremental emissions reduction potential of the top control is only 

marginally greater than the next most effective option. However, the fact 

that a control device creates liquid and solid waste that must be disposed of 

does not necessarily argue against selection of that technology as BACT, 

particularly if the control device has been applied to similar facilities 

elsewhere and the solid or liquid waste problem under review is similar to 

those other applications. On the other hand, where the applicant can show 

that unusual circumstances at the proposed facility create greater problems 

than experienced elsewhere, this may provide a basis for the elimination of 

that control alternative as BACT. 

The procedure for conducting an analysis of environmental impacts should 

be made based on a consideration of site-specific circumstances. In general, 

however, the analysis of environmental impacts starts with the identification 

and quantification of the solid, liquid, and gaseous discharges from the 

control device or devices under review. This analysis of environmental 

impacts should be performed for the entire hierarchy of technologies (even if 

the applicant proposes to adopt the "top", or most stringent, alternative). 

However, the analysis need only address those control alternatives with any 

significant or unusual environmental impacts that have the potential to affect 

the selection or elimination of a control alternative. Thus, the relative 

environmental impacts (both positive and negative) of the various alternatives 

can be compared with each other and the "top" alternative. 

B.47 
!

!

D R A F T 

OCTOBER 1990 

Initially, a qualitative or semi-quantitative screening is performed to 

narrow the analysis to discharges with potential for causing adverse 

environmental effects. Next, the mass and composition of any such discharges 

should be assessed and quantified to the extent possible, based on readily 

available information. Pertinent information about the public or 

environmental consequences of releasing these materials should also be 

assembled. 

IV.D.3.a. EXAMPLES (Environmental Impacts) 

The following paragraphs discuss some possible factors for 

considerations in evaluating the potential for an adverse other media impact. 

! Water Impact 

Relative quantities of water used and water pollutants produced and 

discharged as a result of use of each alternative emission control system 

relative to the "top" alternative would be identified. Where possible, the 

analysis would assess the effect on ground water and such local surface water 

quality parameters as ph, turbidity, dissolved oxygen, salinity, toxic 

chemical levels, temperature, and any other important considerations. The 

analysis should consider whether applicable water quality standards will be 

met and the availability and effectiveness of various techniques to reduce 

potential adverse effects. 

! Solid Waste Disposal Impact 

The quality and quantity of solid waste (e.g., sludges, solids) that 

must be stored and disposed of or recycled as a result of the application of 

each alternative emission control system would be compared with the quality 

and quantity of wastes created with the "top" emission control system. The 

composition and various other characteristics of the solid waste (such as 

permeability, water retention, rewatering of dried material, compression 

strength, leachability of dissolved ions, bulk density, ability to support 

vegetation growth and hazardous characteristics) which are significant with 

B.48 
!

!

D R A F T 

OCTOBER 1990 

regard to potential surface water pollution or transport into and 

contamination of subsurface waters or aquifers would be appropriate for 

consideration. 

! Irreversible or Irretrievable Commitment of Resources 

The BACT decision may consider the extent to which the alternative 

emission control systems may involve a trade-off between short-term 

environmental gains at the expense of long-term environmental losses and the 

extent to which the alternative systems may result in irreversible or 

irretrievable commitment of resources (for example, use of scarce water 

resources). 

! Other Environmental Impacts 

Significant differences in noise levels, radiant heat, or dissipated 

static electrical energy may be considered. 

One environmental impact that could be examined is the trade-off 

between emissions of the various pollutants resulting from the application of 

a specific control technology. The use of certain control technologies may 

lead to increases in emissions of pollutants other than those the technology 

was designed to control. For example, the use of certain volatile organic 

compound (VOC) control technologies can increase nitrogen oxides (NOx) 

emissions. In this instance, the reviewing authority may want to give 

consideration to any relevant local air quality concern relative to the 

secondary pollutant (in this case NOx) in the region of the proposed source. 

For example, if the region in the example were nonattainment for NOx, a 

premium could be placed on the potential NOx impact. This could lead to 

elimination of the most stringent VOC technology (assuming it generated high 

quantities of NOx) in favor of one having less of an impact on ambient NOx 

concentrations. Another example is the potential for higher emissions of 

toxic and hazardous pollutants from a municipal waste combustor operating at a 

low flame temperature to reduce the formation of NOx. In this case the real 

concern to mitigate the emissions of toxic and hazardous emissions (via high 

B.49 
D R A F T 

OCTOBER 1990 

combustion temperatures) may well take precedent over mitigating NOx emissions 

through the use of a low flame temperature. However, in most cases (unless an 

overriding concern over the formation and impact of the secondary pollutant is 

clearly present as in the examples given), it is not expected that this type 

impact would affect the outcome of the decision. 

Other examples of collateral environmental impacts would include 

hazardous waste discharges such as spent catalysts or contaminated carbon. 

Generally these types of environmental concerns become important when sitespecific sensitive receptors exist or when the incremental emissions reduction 

potential of the top control option is only marginally greater than the next 

most effective option. 

IV.D.3.b. CONSIDERATION OF EMISSIONS OF TOXIC AND HAZARDOUS AIR POLLUTANTS 

The generation or reduction of toxic and hazardous emissions, including 

compounds not regulated under the Clean Air Act, are considered as part of the 

environmental impacts analysis. Pursuant to the EPA Administrator's decision 

in North County Resource Recovery Associates, PSD Appeal No. 85-2 (Remand 

Order, June 3, 1986), a PSD permitting authority should consider the effects 

of a given control alternative on emissions of toxics or hazardous pollutants 

not regulated under the Clean Air Act. The ability of a given control 

alternative to control releases of unregulated toxic or hazardous emissions 

must be evaluated and may, as appropriate, affect the BACT decision. 

Conversely, hazardous or toxic emissions resulting from a given control 

technology should also be considered and may, as appropriate, also affect the 

BACT decision. 

Because of the variety of sources and pollutants that may be considered 

in this assessment, it is not feasible for the EPA to provide highly detailed 

national guidance on performing an evaluation of the toxic impacts as part of 

the BACT determination. Also, detailed information with respect to the type 

and magnitude of emissions of unregulated pollutants for many source 

categories is currently limited. For example, a combustion source emits 

hundreds of substances, but knowledge of the magnitude of some of these 

B.50 
D R A F T 

OCTOBER 1990 

emissions or the hazards they produce is sparse. The EPA believes it is 

appropriate for agencies to proceed on a case-by-case basis using the best 

information available. Thus, the determination of whether the pollutants 

would be emitted in amounts sufficient to be of concern is one that the 

permitting authority has considerable discretion in making. However, 

reasonable efforts should be made to address these issues. For example, such 

efforts might include consultation with the: 

! EPA Regional Office; 

! Control Technology Center (CTC); 

! National Air Toxics Information Clearinghouse; 

! Air Risk Information Support Center in the Office of Air Quality 

Planning and Standards (OAQPS); and 

! Review of the literature, such as; EPA-prepared compilations of 

emission factors. 

Source-specific information supplied by the permit applicant is often 

the best source of information, and it is important that the applicant be made 

aware of its responsibility to provide for a reasonable accounting of air 

toxics emissions. 

Similarly, once the pollutants of concern are identified, the permitting 

authority has flexibility in determining the methods by which it factors air 

toxics considerations into the BACT determination, subject to the obligation 

to make reasonable efforts to consider air toxics. Consultation by the review 

authority with EPA's implementation centers, particularly the CTC, is again 

advised. 

It is important to note that several acceptable methods, including risk 

assessment, exist to incorporate air toxics concerns into the BACT decision. 

The depth of the toxics assessment will vary with the circumstances of the 

particular source under review, the nature and magnitude of the toxic 

pollutants, and the locality. Emissions of toxic or hazardous pollutant of 

concern to the permit agency should be identified and, to the extent possible, 

quantified. In addition, the effectiveness of the various control 

B.51 
D R A F T 

OCTOBER 1990 

alternatives in the hierarchy at controlling the toxic pollutant should be 

estimated and summarized to assist in making judgements about how potential 

emissions of toxic or hazardous pollutants may be mitigated through the 

selection of one control option over another. For example, the response to 

the Administrator made by EPA Region IX in its analysis of the North County 

permitting decision illustrates one of several approaches (for further 

information see the September 22, 1987 EPA memorandum from Mr. Gerald Emission 

titled "Implementation of North County Resource Recover PSD Remand" and July 

28, 1988 EPA memorandum from Mr. John Calcagni titled "Supplemental guidance 

on Implementing the North County Prevention of Significant Deterioration (PSD) 

Remand"). 

Under a top-down BACT analysis, the control alternative selected as BACT 

will most likely reduce toxic emissions as well as the regulated pollutant. 

An example is the emissions of heavy metals typically associated with coal 

combustion. The metals generally are a portion of, or adsorbed on, the fine 

particulate in the exhaust gas stream. Collection of the particulate in a 

high efficiency fabric filter rather than a low efficiency electrostatic 

precipitator reduces criteria pollutant particulate matter emissions and 

toxic heavy metals emissions. Because in most instances the interests of 

reducing toxics coincide with the interests of reducing the pollutants subject 

to BACT, consideration of toxics in the BACT analysis generally amounts to 

quantifying toxic emission levels for the various control options. 

In limited other instances, though, control of regulated pollutant 

emissions may compete with control of toxic compounds, as in the case of 

certain selective catalytic reduction (SCR) NOx control technologies. The SCR 

technology itself results in emissions of ammonia, which increase, generally 

speaking, with increasing levels of NOx control. It is the intent of the 

toxics screening in the BACT procedure to identify and quantify this type of 

toxic effect. Generally, toxic effects of this type will not necessarily be 

overriding concerns and will likely not to affect BACT decisions. Rather, the 

intent is to require a screening of toxics emissions effects to ensure that a 

possible overriding toxics issue does not escape notice. 

B.52 
D R A F T 

OCTOBER 1990 

On occasion, consideration of toxics emissions may support the selection 

of a control technology that yields less than the maximum degree of reduction 

in emissions of the regulated pollutant in question. An example is the 

municipal solid waste combustor and resource recovery facility that was the 

subject of the North County remand. Briefly, BACT for SO2 and PM was selected 

to be a lime slurry spray drier followed by a fabric filter. The combination 

yields good SO2 control (approximately 83 percent), good PM control 

(approximately 99.5 percent) and also removes acid gases (approximately 95 

percent), metals, dioxins, and other unregulated pollutants. In this 

instance, the permitting authority determined that good balanced control of 

regulated and unregulated pollutants took priority over achieving the maximum 

degree of emissions reduction for one or more regulated pollutants. 

Specifically, higher levels (up to 95 percent) of SO2 control could have been 

obtained by a wet scrubber. 

IV.E. SELECTING BACT (STEP 5) 

The most effective control alternative not eliminated in Step 4 is 

selected as BACT. 

It is important to note that, regardless of the control level proposed 

by the applicant as BACT, the ultimate BACT decision is made by the permit 

issuing agency after public review. The applicant's role is primarily to 

provide information on the various control options and, when it proposes a 

less stringent control option, provide a detailed rationale and supporting 

documentation for eliminating the more stringent options. It is the 

responsibility of the permit agency to review the documentation and rationale 

presented and; (1) ensure that the applicant has addressed all of the most 

effective control options that could be applied and; (2) determine that the 

applicant has adequately demonstrated that energy, environmental, or economic 

impacts justify any proposal to eliminate the more effective control options. 

Where the permit agency does not accept the basis for the proposed elimination 

of a control option, the agency may inform the applicant of the need for more 

information regarding the control option. However, the BACT selection 

essentially should default to the highest level of control for which the 

B.53 
D R A F T 

OCTOBER 1990 

applicant could not adequately justify its elimination based on energy, 

environmental and economic impacts. If the applicant is unable to provide to 

the permit agency's satisfaction an adequate demonstration for one or more 

control alternatives, the permit agency should proceed to establish BACT and 

prepare a draft permit based on the most effective control option for which an 

adequate justification for rejection was not provided. 

IV.F. OTHER CONSIDERATIONS 

Once energy, environmental, and economic impacts have been considered, 

BACT can only be made more stringent by other considerations outside the 

normal scope of the BACT analysis as discussed under the above steps. 

Examples include cases where BACT does not produce a degree of control 

stringent enough to prevent exceedances of a national ambient air quality 

standard or PSD increment, or where the State or local agency will not accept 

the level of control selected as BACT and requires more stringent controls to 

preserve a greater amount of the available increment. A permit cannot be 

issued to a source that would cause or contribute to such a violation, 

regardless of the outcome of the BACT analysis. Also, States which have set 

ambient air quality standards at levels tighter than the federal standards may 

demand a more stringent level of control at a source to demonstrate compliance 

with the State standards. Another consideration which could override the 

selected BACT are legal constraints outside of the Clean Air Act requiring the 

application of a more stringent technology (e.g., a consent decree requiring a 

greater degree of control). In all cases, regardless of the rationale for the 

permit requiring a more stringent emissions limit than would have otherwise 

been chosen as a result of the BACT selection process, the emission limit in 

the final permit (and corresponding control alternative) represents BACT for 

the permitted source on a case-by-case basis. 

The BACT emission limit in a new source permit is not set until the 

final permit is issued. The final permit is not issued until a draft permit 

has gone through public comment and the permitting agency has had an 

opportunity to consider any new information that may have come to light during 

the comment period. Consequently, in setting a proposed or final BACT limit, 

B.54 
D R A F T 

OCTOBER 1990 

the permit agency can consider new information it learns, including recent 

permit decisions, subsequent to the submittal of a complete application. This 

emphasizes the importance of ensuring that prior to the selection of a 

proposed BACT, all potential sources of information have been reviewed by the 

source to ensure that the list of potentially applicable control alternatives 

is complete (most importantly as it relates to any more effective control 

options than the one chosen) and that all considerations relating to economic, 

energy and environmental impacts have been addressed. 

B.55 
D R A F T 

OCTOBER 1990 

V. ENFORCEABILITY OF BACT 

To complete the BACT process, the reviewing agency must establish an 

enforceable emission limit for each subject emission unit at the source and 

for each pollutant subject to review that is emitted from the source. If 

technological or economic limitations in the application of a measurement 

methodology to a particular emission unit would make an emissions limit 

infeasible, a design, equipment, work practice, operation standard, or 

combination thereof, may be prescribed. Also, the technology upon which the 

BACT emissions limit is based should be specified in the permit. These 

requirements should be written in the permit so that they are specific to the 

individual emission unit(s) subject to PSD review. 

The emissions limits must be included in the proposed permit submitted 

for public comment, as well as the final permit. BACT emission limits or 

conditions must be met on a continual basis at all levels of operation (e.g., 

limits written in pounds/MMbtu or percent reduction achieved), demonstrate 

protection of short term ambient standards (limits written in pounds/hour) and 

be enforceable as a practical matter (contain appropriate averaging times, 

compliance verification procedures and recordkeeping requirements). 

Consequently, the permit must: 

! be able to show compliance or noncompliance (i.e., through 

monitoring times of operation, fuel input, or other indices of 

operating conditions and practices); and 

! specify a reasonable averaging time consistent with established 

reference methods, contain reference methods for determining 

compliance, and provide for adequate reporting and recordkeeping so 

that the permitting agency can determine the compliance status of 

the source. 

B.56 
D R A F T 

OCTOBER 1990 

VI. EXAMPLE BACT ANALYSES FOR GAS TURBINES 

Note: The following example provided is for illustration only. The example 

source is fictitious and has been created to highlight many of the aspects of the 

top-down process. Finally, it must be noted that the cost data and other numbers 

presented in the example are used only to demonstrate the BACT decision making 

process. Cost data are used in a relative sense to compare control costs among 

sources in a source category or for a pollutant. Determination of appropriate 

costs is made on a case-by-case basis. 

In this section a BACT analysis for a stationary gas turbine project is 

presented and discussed under three alternative operating scenarios: 

! Example 1--Simple Cycle Gas Turbines Firing Natural Gas 

! Example 2--Combined Cycle Gas Turbines Firing Natural Gas 

! Example 3--Combined Cycle Gas Turbines Firing Distillate Oil 

The purpose of the examples are to illustrate points to be considered in 

developing BACT decision criteria for the source under review and selecting 

BACT. They are intended to illustrate the process rather than provide 

universal guidance on what constitutes BACT for any particular source 

category. BACT must be determined on a case-by-case basis. 

These examples are not based on any actual analyses performed for the 

purposes of obtaining a PSD permit. Consequently, the actual emission rates, 

costs, and design parameters used are neither representative of any actual 

case nor do they apply to any particular facility. 

B.57 
D R A F T 

OCTOBER 1990 

VI.A. EXAMPLE 1--SIMPLE CYCLE GAS TURBINES FIRING NATURAL GAS 

VI.A.1 PROJECT SUMMARY 

Table B-5 presents project data, stationary gas design parameters, and 

uncontrolled emission estimates for the new source in example 1. The gas 

turbine is designed to provide peaking service to an electric utility. The 

planned operating hours are less than 1000 hours per year. Natural gas fuel 

will be fired. The source will be limited through enforceable conditions to 

the specified hours of operation and fuel type. The area where the source is 

to be located is in compliance for all criteria pollutants. No other changes 

are proposed at this facility, and therefore the net emissions change will be 

equal to the emissions shown on Table B-5. Only NOx emissions are significant 

(i.e., greater than the 40 tpy significance level for NOx) and a BACT analysis 

is required for NOx emissions only. 

VI.A.2. BACT ANALYSIS SUMMARY 

VII.A.2.a. CONTROL TECHNOLOGY OPTIONS 

The first step in evaluating BACT is identifying all candidate control 

technology options for the emissions unit under review. Table B-6 presents 

the list of control technologies selected as potential BACT candidates. The 

first three control technologies, water or steam injection and selective 

catalytic reduction, were identified by a review of existing gas turbine 

facilities in operation. Selective noncatalytic reduction was identified as a 

potential type of control technology because it is an add-on NOx control which 

has been applied to other types of combustion sources. 

B.58 
D R A F T 

OCTOBER 1990 

TABLE B-5. EXAMPLE 1--COMBUSTION TURBINE DESIGN PARAMETERS 

Characteristics 

__________________________________________________________________________

Number of emissions units

Unit Type

Cycle Type

Output

Exhaust temperature, 

Fuel(s)

Heat rate, Btu/kw hr

Fuel flow, Btu/hr

Fuel flow, lb/hr

Service Type

Operating Hours (per year)

1 

Gas Turbines 

Simple-cycle 

75 MW 

1,000 o

F 

Natural Gas 

11,000 

1,650 million 

83,300 

Peaking 

1,000 

Uncontrolled Emissions, tpy(a) 

NOx 564 (169 ppm) 

SO2 <1 

CO 4.6 (6 ppm) 

VOC 1 

PM 5 (0.0097 gr/dscf) 

(a) Based on 1000 hours per year of operation at full load 

B.59 
D R A F T 

OCTOBER 1990 

TABLE B-6. EXAMPLE 1--SUMMARY OF POTENTIAL NOx CONTROL 

TECHNOLOGY OPTIONS 

Typical In Service On: 

control 

efficiency Simple 

range cycle 

Combined Technically 

cycle Other feasible on 

gas combustion simple cycle 

Control technology(a) (% reduction) turbines turbines sources(c) turbines 

____________________________________________________________________________________________________ 

Selective Catalytic 

Reductions 

Water Injection 

Steam Injection 

Low NOx Burner 

Selective Noncatalytic 

Reduction 

40-90 No Yes Yes Yes(b) 

30-70 Yes Yes Yes Yes 

30-70 No Yes Yes No 

30-70 Yes Yes Yes Yes 

20-50 No Yes Yes No 

(a) Ranked in order of highest to lowest stringency. 

(b) Exhaust must be diluted with air to reduce its temperature to 600-750o

F. 

(c) Boiler incinerators, etc.

B.60 
D R A F T 

OCTOBER 1990 

In this example, the control technologies were identified by the

applicant based on a review of the BACT/LAER Clearinghouse, and discussions

with State agencies with experience permitting gas turbines in NOx

nonattainment areas. A preliminary meeting with the State permit issuing

agency was held to determine whether the permitting agency felt that any other

applicable control technologies should be evaluated and they agreed on the

proposed control hierarchy.

VI.A.2.b. TECHNICAL FEASIBILITY CONSIDERATIONS 

Once potential control technologies have been identified, each 

technology is evaluated for its technical feasibility based on the 

characteristics of the source. Because the gas turbines in this example are 

intended to be used for peaking service, a heat recovery steam generator 

(HRSG) will not be included. A HRSG recovers heat from the gas turbine 

exhaust to make steam and increase overall energy efficiency. A portion of 

the steam produced can be used for steam injection for NOx control, sometimes 

increasing the effectiveness of the net injection control system. However, 

the electrical demands of the grid dictate that the turbine will be brought on 

line only for short periods of time to meet peak demands. Due to the lag time 

required to bring a heat recovery steam generator on line, it is not 

technically feasible to use a HRSG at the facility. Use of an HRSG in this 

instance was shown to interfere with the performance of the unit for peaking 

service, which requires immediate response times for the turbine. Although it 

was shown that a HRSG was not feasible and therefore not available, water and 

steam are readily available for NOx control since the turbine will be located 

near an existing steam generating powerplant. 

The turbine type and, therefore, the turbine model selection process, 

affects the achievability of NOx emissions limits. Factors which the customer 

considered in selecting the proposed turbine model were outlined in the 

application as: the peak demand which must be met, efficiency of the gas 

turbine, reliability requirements, and the experience of the utility with the 

operation and maintenance service of the particular manufacturer and turbine 

design. In this example, the proposed turbine is equipped with a combustor 

B.61 
D R A F T 

OCTOBER 1990 

designed to achieve an emission level, at 15 percent O2, of 25 ppm NOx with 

steam injection or 42 ppm with water injection.2 

Selective noncatalytic reduction (SNCR) was eliminated as technically 

infeasible and therefore not available, because this technology requires a 

flue gas temperature of 1300 to 2100EF. The exhaust from the gas turbines 

will be approximately 1000EF, which is below the required temperature range. 

Selective catalytic reduction (SCR) was evaluated and no basis was found 

to eliminate this technology as technically infeasible. However, there are no 

known examples where SCR technology has been applied to a simple-cycle gas 

turbine or to a gas turbine in peaking service. In all cases where SCR has 

been applied, there was an HRSG which served to reduce the exhaust temperature 

to the optimum range of 600-750oF and the gas turbine was operated 

continuously. Consequently, application of SCR to a simple cycle turbine 

involves special circumstances. For this example, it is assumed that dilution 

air can be added to the gas turbine exhaust to reduce its temperature. 

However, the dilution air will make the system more costly due to higher gas 

flows, and may reduce the removal efficiency because the NOx concentration at 

the inlet will be reduced. Cost considerations are considered later in the 

analysis. 

VI.A.2.c. CONTROL TECHNOLOGY HIERARCHY 

After determining technical feasibility, the applicant selected the 

control levels for evaluation shown in Table B-7. Although the applicant 

2 For some gas turbine models, 25 ppm is not achievable with either water

or steam injection.

B.62 
D R A F T

OCTOBER 1990

TABLE B-7. EXAMPLE 1--CONTROL TECHNOLOGY HIERARCHY 

Emissions Limits 

Control Technology ppm(a) TPY

_________________________________________________________________

Steam Injection plus SCR 13 44

Steam Injection at maximum(b) design rate 25 84

Water Injection at maximum(b) design rate 42 140

Steam Injection to meet NSPS 93 312

(a) Corrected to 15 percent oxygen. 

(b) Water to fuel ratio. 

B.63 
D R A F T 

OCTOBER 1990 

reported that some sites in California have achieved levels as low as 9 ppm, 

at this facility a 13 ppm level was determined to be the feasible limit with 

SCR. This decision is based on the lowest achievable level with steam 

injection of 25 ppm and an SCR removal efficiency of 50 percent. Even though 

the reported removal efficiencies for SCR are up to 90 percent at some 

facilities, at this facility the actual NOx concentration at the inlet to the 

SCR system will only be approximately 17 ppm (at actual conditions) due to the 

dilution air required. Also the inlet concentrations, flowrates, and 

temperatures will vary due to the high frequency of startups. These factors 

make achieving the optimum 90 percent NOx removal efficiency unrealistic. 

Based on discussions with SCR vendors, the applicant has established a 

50 percent removal efficiency as the highest level achievable, thereby 

resulting in a 13 ppm level (i.e., 50 percent of 25 ppm). 

The next most stringent level achievable would be steam injection at the 

maximum water-to-fuel ratio achievable by the unit within its design operating 

range. For this particular gas turbine model, that level is 25 ppm as 

supported by vendor NOx emissions guarantees and unit test data. The 

applicant provided documentation obtained from the gas turbine manufacturer3 

verifying ability to achieve this range. 

After steam injection the next most stringent level of control would be 

water injection at the maximum water-to-fuel ratio achievable by the unit 

within its design operating range. For this particular gas turbine model, 

that level is 42 ppm as supported by vendor NOx emissions guarantees and 

actual unit test data. The applicant provided documentation obtained from the 

gas turbine manufacturer verifying ability to achieve this range. 

The least stringent level evaluated by the applicant was the current 

NSPS for utility gas turbines. For this model, that level is 93 ppm at 

15 percent O2. By definition, BACT can be no less stringent than NSPS. 

3 It should be noted that achievability of the NOx limits is dependent on

the turbine model, fuel, type of wet injection (water or steam), and system

design. Not all gas turbine models or fuels can necessarily achieve these

levels.

B.64 
D R A F T 

OCTOBER 1990 

Therefore, less stringent levels are not evaluated. 

VI.A.2.d. IMPACTS ANALYSIS SUMMARY 

The next steps completed by the applicant were the development of the 

cost, economic, environmental and energy impacts of the different control 

alternatives. Although the top-down process would allow for the selection of 

the top alternative without a cost analysis, the applicant felt cost/economic 

impacts were excessive and that appropriate documentation may justify the 

elimination of SCR as BACT and therefore chose to quantify cost and economic 

impacts. Because the technologies in this case are applied in combination, it 

was necessary to quantify impacts for each of the alternatives. The impact 

estimates are shown in Table B-8. Adequate documentation of the basis for the 

impacts was determined to be included in the PSD permit application. 

The incremental cost impacts shown are the cost of the alternative 

compared to the next most stringent control alternative. Figure B-2 is a plot 

of the least-cost envelope defined by the list of control options. 

VI.A.2.e. TOXICS ASSESSMENT 

If SCR were applied, potential toxic emissions of ammonia could occur. 

Ammonia emissions resulting from application of SCR could be as large as 20 

tons per year. Application of SCR would reduce NOx by an additional 20 tpy 

over steam injection alone (25 ppm)(not including ammonia emissions). 

Another environmental impact considered was the spent catalyst which 

would have to be disposed of at certain operating intervals. The catalyst 

contains vanadium pentoxide, which is listed as a hazardous waste under RCRA 

regulations (40 CFR 261.3). Disposal of this waste creates an additional 

economic and environmental burden. This was considered in the applicant's 

proposed BACT determination. 

B.65 
D R A F T 

OCTOBER 1990 

TABLE B-8. EXAMPLE 1--SUMMARY OF TOP-DOWN BACT IMPACT ANALYSIS RESULTS FOR NOx 

Emissions per Turbine Economic Impacts Energy Impacts Environmental Impacts

Incremental 

Installed Total Cost Incremental increase Adverse

Emissions capital annualized effectiveness cost over Toxics environmental

Emissions reduction(a) cost(b) cost(c) over baseline(d) effectiveness(e) baseline(f) impact impact 

Control alternative (lb/hr) (tpy) (tpy) ($) ($/yr) ($/ton) ($/ton) (MMBtu/yr) (Yes/No) (Yes/No)

______________________________________________________________________________________________________________________________________________________

13 ppm Alternative 44 22 260 11,470,000 1,717,000(g) 6,600 56,200 464,000 Yes No 

25 ppm Alternative 84 42 240 1,790,000 593,000 2,470 8,460 30,000 No No 

42 ppm Alternative 140 70 212 1,304,000 356,000 1,680 800 15,300 No No

NSPS Alternative 312 156 126 927,000 288,000 2,285 8,000 No No

Uncontrolled Baseline 564 282 - - - - - - - -

(a) Emissions reduction over baseline control level. 

(b) Installed capital cost relative to baseline. 

(c) Total annualized cost (capital, direct, and indirect) of purchasing, installing, and operating the proposed control alternative. A capital 

recovery factor approach using a real interest rate (i.e., absent inflation) is used to express capital costs in present-day annual costs. 

(d) Cost Effectiveness over baseline is equal to total annualized cost for the control option divided by the emissions reductions resulting from the

uncontrolled baseline. 

(e) The optional incremental cost effectiveness criteria is the same as the total cost effectiveness criteria except that the control alternative 

is considered relative to the next most stringent alternative rather than the baseline control alternative. 

(f) Energy impacts are the difference in total project energy requirements with the control alternative and the baseline control alternative

expressed in equivalent millions of Btus per year. 

(g) Assued 10 year catalyst life since this turbine operates only 1000 hours per year. Assumptions made on catalyst life may have a profound affect

upon cost effectiveness.

B.66 
D R A F T

OCTOBER 1990

Total Annualized Cost ($ per year) 

2,000,000 

1,500,000 

1,000,000 

500,000 

0

0 50 100 150 200 250 300

NSPS 

42ppm 

25ppm 

13ppm 

Emissions Reduction (tons per year) 

Figure B-2. Least-Cost Envelope for Example 1

B.67 
D R A F T 

OCTOBER 1990 

VI.A.2.f. RATIONALE FOR PROPOSED BACT 

Based on these impacts, the applicant proposed eliminating the 13 ppm 

alternative as economically infeasible. The applicant documented that the 

cost effectiveness is high at 6,600 $/ton, and well out of the range of recent 

BACT NOx control costs for similar sources. The incremental cost 

effectiveness of $56,200 also is high compared to the incremental cost 

effectiveness of the next option. 

The applicant documented that the other combustion turbine sources which 

have applied SCR have much higher operating hours (i.e., all were permitted as 

base-loaded units). Also, these sources had heat recovery steam generators so 

that the cost effectiveness of the application of SCR was lower. For this 

source, dilution air must be added to cool the flue gas to the proper 

temperature. This increases the cost of the SCR system relative to the same 

gas turbine with a HRSG. Therefore, the other sources had much lower cost 

impacts for SCR relative to steam injection alone, and much lower cost 

effectiveness numbers. Application of SCR would also result in emission of 

ammonia, a toxic chemical, of possibly 20 tons per year while reducing NOx 

emissions by 20 tons per year. The applicant asserted that, based on these 

circumstances, to apply SCR in this case would be an unreasonable burden 

compared to what has been done at other similar sources. 

Consequently, the applicant proposed eliminating the SCR plus steam 

injection alternative. The applicant then accepted the next control 

alternative, steam injection to 25 ppmv. The use of steam injection was shown 

by the applicant to be consistent with recent BACT determinations for similar 

sources. The review authority concurred with the proposed elimination of SCR 

and the selection of a 25 ppmv limit as BACT. The use of steam injection was 

shown by the applicant to be consistent with recent BACT determinations for 

similar sources. The review authority concurred with the proposed elimination 

of SCR and the selection of a 25 ppmv limit as BACT. 

B.68 
D R A F T 

OCTOBER 1990 

VI.B. EXAMPLE 2--COMBINED CYCLE GAS TURBINES FIRING NATURAL GAS 

Table B-9 presents the design parameters for an alternative set of 

circumstances. In this example, two gas turbines are being installed. Also, 

the operating hours are 5000 per year and the new turbines are being added to 

meet intermediate loads demands. The source will be limited through 

enforceable conditions to the specified hours of operation and fuel type. In 

this case, HRSG units are installed. The applicable control technologies and 

control technology hierarchy are the same as the previous example except that 

no dilution is required for the gas turbine exhaust because the HRSG serves to 

reduce the exhaust temperature to the optimum level for SCR operation. Also, 

since there is no dilution required and fewer startups, the most stringent 

control option proposed is 9 ppm based on performance limits for several other 

natural gas fired baseload combustion turbine facilities. 

Table B-10 presents the results of the cost and economic impact analysis 

for the example and Figure B-3 is a plot of the least-cost envelope defined by 

the list of control options. The incremental cost impacts shown are the cost 

of the alternative compared to the next most stringent control alternative. 

Due to the increased operating hours and design changes, the economic impacts 

of SCR are much lower for this case. There does not appear to be a persuasive 

argument for stating that SCR is economically infeasible. Cost effectiveness 

numbers are within the range typically required of this and other similar 

source types. 

In this case, there would also be emissions of ammonia. However, now 

the magnitude of ammonia emissions, approximately 40 tons per year, is much 

lower than the additional NOx reduction achieved, which is 270 tons per year. 

Under these alternative circumstances, PM emissions are also now above 

the significance level (i.e., greater than 25 tpy). The gas turbine 

B.69 
D R A F T 

OCTOBER 1990 

TABLE B-9. EXAMPLE 2--COMBUSTION TURBINE DESIGN PARAMETERS 

Characteristics 

______________________________________________________________________________

Number of emission units 

Emission units 

Cycle Type 

Output 

Gas Turbines (2 @ 75 MW each) 

Steam Turbine (no emissions generated) 

Fuel(s) 

Gas Turbine Heat Rate, Btu/kw-hr 

Fuel Flow per gas turbine, Btu/hr 

Fuel Flow per gas turbine, lb/hr 

Service Type 

Hours per year of operation 

Uncontrolled Emissions per gas turbine, tpy (a)(b) 

NOx 

SO2 

CO 

VOC 

PM 

2

Gas Turbine

Combined-cycle

150 MW

70 MW

Natural Gas

11,000 Btu/kw-hr

1,650 million

83,300

Intermediate

5000

1,410 (169 ppm)

<1

23 (6 ppm)

5

25 (0.0097 gr/dscf)

(a) Based on 5000 hours per year of operation. 

(b) Total uncontrolled emissions for the proposed project is equal to the 

pollutants uncontrolled emission rate multiplied by 2 turbines. For example, 

total NOx = (2 turbines) x 1410 tpy per turbine) = 2820 tpy.

B.70
D R A F T 

OCTOBER 1990 

TABLE B-10. EXAMPLE 2--SUMMARY OF TOP-DOWN BACT IMPACT ANALYSIS RESULTS FOR NOx 

Emissions per Turbine Economic Impacts Energy Impacts Environmental Impacts

Incremental 

Installed Total Cost Incremental increase Adverse

Emissions capital annualized effectiveness cost over Toxics environmental

Emissions reduction(a,h) cost(b) cost(c) over baseline(d) effectiveness(e) baseline(f) impact impact 

Control alternative (lb/hr) (tpy) (tpy) ($) ($/yr) ($/ton) ($/ton) (MMBtu/yr) (Yes/No) (Yes/No)

______________________________________________________________________________________________________________________________________________________

9 ppm Alternative 30 75 1,335 10,980,000 3,380,000(g) 2,531 12,200 160,000 Yes No 

25 ppm Alternative 84 210 1,200 1,791,000 1,730,000 1,440 6,050 105,000 No No 

42 ppm Alternative 140 350 1,060 1,304,000 883,000 833 181 57,200 No No 

NSPS Alternative 312 780 630 927,000 805,000 1,280 27,000 No No 

Uncontrolled Baseline 564 1,410 - - - - - - - -

(a) Emissions reduction over baseline control level. 

(b) Installed capital cost relative to baseline. 

(c) Total annualized cost (capital, direct, and indirect) of purchasing, installing, and operating the proposed control alternative. A capital 

recovery factor approach using a real interest rate (i.e., absent inflation) is used to express capital costs in present-day annual costs. 

(d) Cost Effectiveness over baseline is equal to total annualized cost for the control option divided by the emissions reductions resulting from the

uncontrolled baseline. 

(e) The optional incremental cost effectiveness criteria is the same as the total cost effectiveness criteria except that the control alternative 

is considered relative to the next most stringent alternative rather than the baseline control alternative. 

(f) Energy impacts are the difference in total project energy requirements with the control alternative and the baseline control alternative

expressed in equivalent millions of Btus per year. 

(g) Assumes a 2 year catalyst life. Assumptions made on catalyst life may have a profound affect upon cost effectiveness.

(h) Since the project calls for two turbines, actual project wide emissions reductions for an alternative will be equal to two times the reduction

listed.

B.71 
D R A F T 

OCTOBER 1990 

Total Annualized Cost ($ per year) 

4,000,000 

3,000,000 

2,000,000 

1,000,000 

0 

0 200 400 600 800 1,000 1,200 1,400 1,600 

NSPS 

42ppm 

25ppm 

9ppm 

Emissions Reduction (tons per year) 

Figure B-3. Least-Cost Envelope for Example 2 

B.72 
D R A F T 

OCTOBER 1990 

combustors are designed to combust the fuel as completely as possible and 

therefore reduce PM to the lowest possible level. Natural gas contains no 

solids and solids are removed from the injected water. The PM emission rate 

without add-on controls is on the same order (0.009 gr/dscf) as that for other 

particulate matter sources controlled with stringent add-on controls (e.g., 

fabric filter). Since the applicant documented that precombustion or add-on 

controls for PM have never been required for natural gas fired turbines, the 

reviewing agency accepted the applicants analysis that natural gas firing was 

BACT for PM emissions and that no additional analysis of PM controls was 

required. 

VI.C. EXAMPLE 3--COMBINED CYCLE GAS TURBINE FIRING DISTILLATE OIL 

In this example, the same combined cycle gas turbines are proposed 

except that distillate oil is fired rather than natural gas. The reason is 

that natural gas is not available on site and there is no pipeline within a 

reasonable distance. The fuel change raises two issues; the technical 

feasibility of SCR in gas turbines firing sulfur bearing fuel, and NOx levels 

achievable with water injection while firing fuel oil. 

In this case the applicant proposed to eliminate SCR as technically 

infeasible because sulfur present in the fuel, even at low levels, will poison 

the catalyst and quickly render it ineffective. The applicant also noted that 

there are no cases in the U.S. where SCR has been applied to a gas turbine 

firing distillate oil as the primary fuel.4 

A second issue would be the most stringent NOx control level achievable 

with wet injection. For oil firing the applicant has proposed 42 ppm at 

15 percent oxygen. Due to flame characteristics inherent with oil firing, and 

limits on the amount of water or steam that can be injected, 42 ppm is the 

lowest NOx emission level achievable with distillate oil firing. Since 

4 Though this argument was considered persuasive in this case, advances

in catalyst technology have now made SCR with oil firing technically feasible.

B.73 
D R A F T 

OCTOBER 1990 

natural gas is not available and SCR is technically infeasible, 42 ppm is the 

most stringent alternative considered. Based on the cost effectiveness of wet 

injection, approximately 833 $/ton, there is no economic basis to eliminate 

the 42 ppm option since this cost is well within the range of BACT costs for 

NOx control. Therefore, this option is proposed as BACT. 

The switch to oil from gas would also result in SO2, CO, PM, and 

beryllium emissions above significance levels. Therefore, BACT analyses would 

also be required for these pollutants. These analyses are not shown in this 

example, but would be performed in the same manner as the BACT analysis for 

NOx. 

VI.D. OTHER CONSIDERATIONS 

The previous judgements concerning economic feasibility were in an area 

meeting NAAQS for both NOx and ozone. If the natural gas fired simple cycle 

gas turbine example previously presented were sited adjacent to a Class I 

area, or where air quality improvement poses a major challenge, such as next 

to a nonattainment area, the results may differ. In this case, even though 

the region of the actual site location is achieving the NAAQS, adherence to a 

local or regional NOx or ozone attainment strategy might result in the 

determination that higher costs than usual are appropriate. In such 

situations, higher costs (e.g., 6,600 $/ton) may not necessarily be persuasive 

in eliminating SCR as BACT. 

While it is not the intention of BACT to prevent construction, it is 

possible that local or regional air quality management concerns regarding the 

need to minimize the air quality impacts of new sources would lead the 

permitting authority to require a source to either achieve stringent emission 

control levels or, at a minimum, that control cost expenditures meet certain 

cost levels without consideration of the resultant economic impact to the 

source. 

Besides local or regional air quality concerns, other site constraints 

may significantly impact costs of particular control technologies. For the 

B.74 
D R A F T 

OCTOBER 1990 

examples previously presented, two factors of concern are land and water 

availability. 

The cost of the raw water is usually a small part of the cost of wet 

controls. However, gas turbines are sometimes located in remote locations. 

Though water can obviously be trucked to any location, the costs may be very 

high. 

Land availability constraints may occur where a new source is being 

located at an existing plant. In these cases, unusual design and additional 

structural requirements could make the costs of control technologies which are 

commonly affordable prohibitively expensive. Such considerations may be 

pertinent to the calculations of impacts and ultimately the selection of BACT. 

B.75 
D R A F T 

OCTOBER 1990 

CHAPTER C 

THE AIR QUALITY ANALYSIS 

I. INTRODUCTION 

An applicant for a PSD permit is required to conduct an air quality 

analysis of the ambient impacts associated with the construction and operation 

of the proposed new source or modification. The main purpose of the air 

quality analysis is to demonstrate that new emissions emitted from a proposed 

major stationary source or major modification, in conjunction with other 

applicable emissions increases and decreases from existing sources (including 

secondary emissions from growth associated with the new project), will not 

cause or contribute to a violation of any applicable NAAQS or PSD increment. 

Ambient impacts of noncriteria pollutants must also be evaluated. 

A separate air quality analysis must be submitted for each regulated 

pollutant if the applicant proposes to emit the pollutant in a significant 

amount from a new major stationary source, or proposes to cause a significant 

net emissions increase from a major modification (see Table I-A-4, chapter A 

of this part). [Note: The air quality analysis requirement also applies to 

any pollutant whose rate of emissions from a proposed new or modified source 

is considered to be "significant" because the proposed source would construct 

within 10 kilometers of a Class I area and would have an ambient impact on 

such area equal to or greater than 1 μg/m3

, 24-hour average.] Regulated 

pollutants include (1) pollutants for which a NAAQS exists (criteria 

pollutants) and (2) other pollutants, which are regulated by EPA, for which no 

NAAQS exist (noncriteria pollutants). 

Each air quality analysis will be unique, due to the variety of sources and 

meteorological and topographical conditions that may be involved. 

Nevertheless, the air quality analysis must be accomplished in a manner 

consistent with the requirements set forth in either EPA's PSD regulations 

under 40 CFR 52.21, or a State or local PSD program approved by EPA pursuant 

to 40 CFR 51.166. Generally, the analysis will involve (1) an assessment of 

existing air quality, which may include ambient monitoring data and air 

C.1 
D R A F T 

OCTOBER 1990 

quality dispersion modeling results, and (2) predictions, using dispersion 

modeling, of ambient concentrations that will result from the applicant's 

proposed project and future growth associated with the project. 

In describing the various concepts and procedures involved with the air 

quality analysis in this section, it is assumed that the reader has a basic 

understanding of the principles involved in collecting and analyzing ambient 

monitoring data and in performing air dispersion modeling. Considerable 

guidance is contained in EPA's Ambient Monitoring Guidelines for Prevention of 

Significant Deterioration [Reference 1] and Guideline on Air Quality Models 

(Revised) [Reference 2] . Numerous times throughout this chapter, the reader 

will be referred to these guidance documents, hereafter referred to as the PSD 

Monitoring Guideline and the Modeling Guideline, respectively. 

In addition, because of the complex character of the air quality analysis 

and the site-specific nature of the modeling techniques involved, applicants 

are advised to review the details of their proposed modeling analysis with the 

appropriate reviewing agency before a complete PSD application is submitted. 

This is best done using a modeling protocol. The modeling protocol should be 

submitted to the reviewing agency for review and approval prior to commencing 

any extensive analysis. Further description of the modeling protocol is 

contained in this chapter. 

The PSD applicant should also be aware that, while this chapter focuses 

primarily on compliance with the NAAQS and PSD increments, additional impact 

analyses are required under separate provisions of the PSD regulations for 

determining any impairment to visibility, soils and vegetation that might 

result, as well as any adverse impacts to Class I areas. These provisions are 

described in the following chapters D and E, respectively. 

C.2 
D R A F T 

OCTOBER 1990 

II. NATIONAL AMBIENT AIR QUALITY STANDARDS AND PSD INCREMENTS 

As described in the introduction to this chapter, the air quality analysis 

is designed to protect the national ambient air quality standards (NAAQS) and 

PSD increments. The NAAQS are maximum concentration "ceilings" measured in 

terms of the total concentration of a pollutant in the atmosphere (See Table 

C-1). For a new or modified source, compliance with any NAAQS is based upon 

the total estimated air quality, which is the sum of the ambient estimates 

resulting from existing sources of air pollution (modeled source impacts plus 

measured background concentrations, as described in this section) and the 

modeled ambient impact caused by the applicant's proposed emissions increase 

(or net emissions increase for a modification) and associated growth. 

A PSD increment, on the other hand, is the maximum allowable increase in 

concentration that is allowed to occur above a baseline concentration for a 

pollutant (see section II.E). The baseline concentration is defined for each 

pollutant (and relevant averaging time) and, in general, is the ambient 

concentration existing at the time that the first complete PSD permit 

application affecting the area is submitted. Significant deterioration is 

said to occur when the amount of new pollution would exceed the applicable PSD 

increment. It is important to note, however, that the air quality cannot 

deteriorate beyond the concentration allowed by the applicable NAAQS, even if 

not all of the PSD increment is consumed. 

II.A CLASS I, II, AND III AREAS AND INCREMENTS. 

The PSD requirements provide for a system of area classifications which 

affords States an opportunity to identify local land use goals. There are 

three area classifications. Each classification differs in terms of the 

amount of growth it will permit before significant air quality deterioration 

would be deemed to occur. Class I areas have the smallest increments and thus 

allow only a small degree of air quality deterioration. Class II areas can 

C.3 
--

--

--

D R A F T 

OCTOBER 1990 

TABLE C-1. National Ambient Air Quality Standards 

Primary Secondary 

Pollutant/averaging time Standard Standard 

______________________________________________________________________________ 

Particulate Matter 

o PM10, annuala 

o PM10, 24-hourb 

Sulfur Dioxide 

o SO2, annualc 

o SO2, 24-hourd 

365 μg/m3 (0.14 ppm) 

o SO2, 3-hourd 

Nitrogen Dioxide 

o NO2, annualc 

Ozone 

o O3, 1-hourb 

Carbon Monoxide 

o CO, 8-hourd 

o CO, 1-hourd 

Lead 

50 μg/m3 50 μg/m3 

150 μg/m3 150 μg/m3 

80 μg/m3 (0.03 ppm) 

1,300 μg/m3

 (0.5 ppm) 

0.053 ppm (100 μg/m3

0.053 ppm (100 μg/m3) 

0.12 ppm (235 μg/m3

) 0.12 ppm (235 μg/m3) 

9 ppm (10 mg/m3

) 

35 ppm (40 mg/m3

) 

o Pb, calendar quarterc 1.5 μg/m3 

______________________________________________________________________________

a Standard is attained when the expected annual arithmetic mean is less than 

or equal to 50 μg/m3

. 

b Standard is attained when the expected number of exceedances is less than or 

equal to 1. 

c Never to be exceeded. 

d Not to be exceeded more than once per year. 

C.4 
D R A F T 

OCTOBER 1990 

accommodate normal well-managed industrial growth. Class III areas have the 

largest increments and thereby provide for a larger amount of development than 

either Class I or Class II areas. 

Congress established certain areas, e.g., wilderness areas and national 

parks, as mandatory Class I areas. These areas cannot be redesignated to any 

other area classification. All other areas of the country were initially 

designated as Class II. Procedures exist under the PSD regulations to 

redesignate the Class II areas to either Class I or Class III, depending upon 

a State's land management objectives. 

PSD increments for SO2 and particulate matter--measured as total suspended 

particulate (TSP)--have existed in their present form since 1978. On July 1, 

1987, EPA revised the NAAQS for particulate matter and established the new PM10 indicator by which the NAAQS are to be measured. (Since each State is 

required to adopt these revised NAAQS and related implementation requirements 

as part of the approved implementation plan, PSD applicants should check with 

the appropriate permitting agency to determine whether such State action has 

already been taken. Where the PM-10 NAAQS are not yet being implemented, 

compliance with the TSP-based ambient standards is still required in 

accordance with the currently-approved State implementation plan.) 

Simultaneously with the promulgation of the PM-10 NAAQS, EPA announced that it 

would develop PM-10 increments to replace the TSP increments. Such new 

increments have not yet been promulgated, however. Thus the national PSD 

increment system for particulate matter is still based on the TSP indicator. 

The EPA promulgated PSD increments for NO2 on October 17, 1988. These new 

increments become effective under EPA's PSD regulations (40 CFR 52.21) on 

November 19, 1990, although States may have revised their own PSD programs to 

incorporate the new increments for NO2 on some earlier date. Until 

November 19, 1990, PSD applicants should determine whether the NO2 increments 

are being implemented in the area of concern; if so, they must include the 

necessary analysis, if applicable, as part of a complete permit application. 

[NOTE: the "trigger date" (described below in section II.B) for the NO2 

increments has been established by regulation as of February 8, 1988. This 

applies to all State PSD programs as well as EPA's Part 52 PSD program. Thus, 

C.5 
D R A F T 

OCTOBER 1990 

consumption of the NO2 increments may actually occur before the increments 

become effective in any particular PSD program.] The PSD increments for SO2, 

TSP and NO2 are summarized in Table C-2. 

II.B ESTABLISHING THE BASELINE DATE 

As already described, the baseline concentration is the reference point for 

determining air quality deterioration in an area. The baseline concentration 

is essentially the air quality existing at the time of the first complete PSD 

permit application submittal affecting that area. In general, then, the 

submittal date of the first complete PSD application in an area is the 

"baseline date." On or before the date of the first PSD application, most 

emissions are considered to be part of the baseline concentration, and 

emissions changes which occur after that date affect the amount of available 

PSD increment. However, to fully understand how and when increment is 

consumed or expanded, three different dates related to baseline must be 

explained. In chronological order, these dates are as follows: 

! the major source baseline date; 

! the trigger date; and 

! the minor source baseline date. 

The major source baseline date is the date after which actual emissions 

associated with construction (i.e., physical changes or changes in the method 

of operation) at a major stationary source affect the available PSD increment. 

Other changes in actual emissions occurring at any source after the major 

source baseline date do not affect the increment, but instead (until after the 

minor source baseline date is established) contribute to the baseline 

concentration. The trigger date is the date after which the minor source 

C.6 
D R A F T

OCTOBER 1990

TABLE C-2. PSD INCREMENTS

(μg/m3

)

44444444444444444444444444444444444444444444444444444444444444444444444444444

Class I Class II Class III

______________________________________________________________________________

Sulfur Dioxide 

o SO2, annuala

o SO2, 24-hourb

o SO2, 3-hourb

Particulate Matter 

o TSP, annuala

o TSP, 24-hourb

Nitrogen Dioxide 

o NO2, annuala

2 20 40 

5 91 182 

25 512 700 

5 19 37 

10 37 75 

2.5 25 50 

a Never to be exceeded. 

b Not to be exceeded more than once per year.

C.7 
D R A F T 

OCTOBER 1990 

baseline date (described below) may be established. Both the major source 

baseline date and the trigger date are fixed dates, although different dates 

apply to (1) SO2 and particulate matter, and (2) NO2, as follows: 

4444444444444444444444444444444444444444444444444444444444444444444444444444 

Pollutant Major Source Baseline Date 

Trigger Date 

PM January 6, 1975 August 7, 1977 

SO2 January 6, 1975 August 7, 1977 

NO2 February 8, 1988 February 8, 1988 

______________________________________________________________________________ 

The minor source baseline date is the earliest date after the trigger date 

on which a complete PSD application is received by the permit reviewing 

agency. If the application that established the minor source baseline date is 

ultimately denied or is voluntarily withdrawn by the applicant, the minor 

source baseline date remains in effect nevertheless. Because the date marks 

the point in time after which actual emissions changes from all sources affect 

the available increment (regardless of whether the emissions changes are a 

result of construction), it is often referred to as the "baseline date." 

The minor source baseline date for a particular pollutant is triggered by a 

PSD applicant only if the proposed increase in emissions of that pollutant is 

significant. For instance, a PSD application for a major new source or 

modification that proposes to increase its emissions in a significant amount 

for SO2, but in an insignificant amount for PM, will establish the minor 

source baseline date for SO2 but not for PM. Thus, the minor source baseline 

dates for different pollutants (for which increments exist) need not be the 

same in a particular area. 

C.8 
D R A F T 

OCTOBER 1990 

II.C ESTABLISHING THE BASELINE AREA 

The area in which the minor source baseline date is established by a PSD 

permit application is known as the baseline area. The extent of a baseline 

area is limited to intrastate areas and may include one or more areas 

designated as attainment or unclassified under Section 107 of the Act. The 

baseline area established pursuant to a specific PSD application is to include 

1) all portions of the attainment or unclassifiable area in which the PSD 

applicant would propose to locate, amd 2) any attainment or unclassifiable 

area in which the proposed emissions would have a significant ambient impact. 

For this purpose, a significant impact is defined as at least a 1 μg/m3

 annual 

increase in the average annual concentration of the applicable pollutant. 

Again, a PSD applicant's establishment of a baseline area in one State does 

not trigger the minor source baseline date in, or extend the baseline area 

into, another State. 

II.D REDEFINING BASELINE AREAS (AREA REDESIGNATIONS) 

It is possible that the boundaries of a baseline area may not reasonably 

reflect the area affected by the PSD source which established the baseline 

area. A state may redefine the boundaries of an existing baseline area by 

redesignating the section 107 areas contained therein. Section 107(d) of the 

Clean Air Act specifically authorizes states to submit redesignations to the 

EPA. Consequently, a State may submit redefinitions of the boundaries of 

attainment or unclassifiable areas at any time, as long as the following 

criteria are met: 

!area redesignations can be no smaller than the 1 μg/m3

 area of 

impact of the triggering source; and 

! the boundaries of any redesignated area cannot intersect the 

1 μg/m3

 area of impact of any major stationary source that 

established or would have established a minor source baseline date 

for the area proposed for redesignation. 

C.9 
D R A F T 

OCTOBER 1990 

II.E INCREMENT CONSUMPTION AND EXPANSION 

The amount of PSD increment that has been consumed in a PSD area is 

determined from the emissions increases and decreases which have occurred from 

sources since the applicable baseline date. It is useful to note, however, 

that in order to determine the amount of PSD increment consumed (or the amount 

of available increment), no determination of the baseline concentration needs 

to be made. Instead, increment consumption calculations must reflect only the 

ambient pollutant concentration change attributable to increment-affecting 

emissions. 

Emissions increases that consume a portion of the applicable increment are, 

in general, all those not accounted for in the baseline concentration and 

specifically include: 

! actual emissions increases occurring after the major source baseline date, 

which are associated with physical changes or changes in the method of 

operation (i.e., construction) at a major stationary source; and 

!actual emissions increases at any stationary source, area source, or 

mobile source occurring after the minor source baseline date. 

The amount of available increment may be added to, or "expanded," in two 

ways. The primary way is through the reduction of actual emissions from any 

source after the minor source baseline date. Any such emissions reduction 

would increase the amount of available increment to the extent that ambient 

concentrations would be reduced. 

Increment expansion may also result from the reduction of actual emissions 

after the major source baseline date, but before the minor source baseline 

date, if the reduction results from a physical change or change in the method 

of operation (i.e., construction) at a major stationary source. Moreover, the 

reduction will add to the available increment only if the reduction is 

included in a federally enforceable permit or SIP provision. Thus, for major 

stationary sources, actual emissions reductions made prior to the minor source 

baseline date expand the available increment just as increases before the 

minor source baseline date consume increment. 

C.10 
D R A F T 

OCTOBER 1990 

The creditable increase of an existing stack height or the application of 

any other creditable dispersion technique may affect increment consumption or 

expansion in the same manner as an actual emissions increase or decrease. 

That is, the effects that a change in the effective stack height would have on 

ground level pollutant concentrations generally should be factored into the 

increment analysis. For example, this would apply to a raised stack height 

occurring in conjunction with a modification at a major stationary source 

prior to the minor source baseline date, or to any changed stack height 

occurring after the minor source baseline date. It should be noted, however, 

that any increase in a stack height, in order to be creditable, must be 

consistent with the EPA's stack height regulations; credit cannot be given for 

that portion of the new height which exceeds the height demonstrated to be the 

good engineering practice (GEP) stack height. 

Increment consumption (and expansion) will generally be based on changes in 

actual emissions reflected by the normal source operation for a period of 2 

years. However, if little or no operating data are available, as in the case 

of permitted emission units not yet in operation at the time of the increment 

analysis, the potential to emit must be used instead. Emissions data 

requirements for modeling increment consumption are described in 

Section IV.D.4. Further guidance for identifying increment-consuming sources 

(and emissions) is provided in Section IV.C.2. 

C.11 
D R A F T 

OCTOBER 1990 

II.F BASELINE DATE AND BASELINE AREA CONCEPTS -- EXAMPLES 

An example of how a baseline area is established is illustrated in Figure 

C-1. A major new source with the potential to emit significant amounts of SO2 

proposes to locate in County C. The applicant submits a complete PSD 

application to the appropriate reviewing agency on October 6, 1978. (The 

trigger date for SO2 is August 7, 1977.) A review of the State's SO2 

attainment designations reveals that attainment status is listed by individual 

counties in the state. Since County C is designated attainment for SO2, and 

the source proposes to locate there, October 6, 1978 is established as the 

minor source baseline date for SO2 for the entire county. 

Dispersion modeling of proposed SO2 emissions in accordance with approved 

methods reveals that the proposed source's ambient impact will exceed 1 ug/m3 

(annual average) in Counties A and B. Thus, the same minor source baseline 

date is also established throughout Counties A and B. Once it is triggered, 

the minor source baseline date for Counties A, B and C establishes the time 

after which all emissions changes affect the available increments in those 

three counties. 

Although SO2 impacts due to the proposed emissions are above the 

significance level of 1 μg/m3

 (annual average) in the adjoining State, the 

proposed source does not establish the minor source baseline date in that 

State. This is because, as mentioned in Section II.C of this chapter, 

baseline areas are intrastate areas only. 

The fact that a PSD source's emissions cannot trigger the minor source 

baseline date across a State's boundary should not be interpreted as 

precluding the applicant's emissions from consuming increment in another 

State. Such increment-consuming emissions (e.g., SO2 emissions increases 

resulting from a physical change or a change in the method of operation at a 

C.12 
D R A F T

OCTOBER 1990

County E 

Unclassified 

County A 

County B 

Unclassified 

County C 

Attainment 

County D 

Attainment 

Major Source 

Triggers Baseline 

Baseline Date Triggered 10/6/78 

State line 

County line 

Attainmen t 

Figure C-1. Establishing the Baseline Area. 

C.13 
D R A F T 

OCTOBER 1990 

major stationary source after January 6, 1975) that affect another State will 

consume increment there even though the minor source baseline date has not 

been triggered, but are not considered for increment-consuming purposes until 

after the minor source baseline date has been independently established in 

that State. A second example, illustrated in Figure C-2, 

demonstrates how a baseline area may be redefined. Assume that the State in 

the first example decides that it does not want the minor source baseline date 

to be established in the western half of County A where the proposed source 

will not have a significant annual impact (i.e., 1 μg/m3

, annual average). 

The State, therefore, proposes to redesignate the boundaries of the existing 

section 107 attainment area, comprising all of County A, to create two 

separate attainment areas in that county. If EPA agrees that the available 

data support the change, the redesignations will be approved. At that time, 

the October 6, 1978 minor source baseline date will no longer apply to the 

newly-established attainment area comprising the western portion of County A. 

If the minor source baseline date has not been triggered by another PSD 

application having a significant impact in the redesignated western portion of 

County A, the SO2 emissions changes occurring after October 6, 1978 from minor 

point, area, and mobile sources, and from nonconstruction-related activities 

at all major stationary sources in this area will be transferred into the 

baseline concentration. In accordance with the major source baseline date, 

construction-related emissions changes at major point sources continue to 

consume or expand increment in the westerm poriton of County A which is no 

longer part of the original baseline area. 

C.14 
D R A F T 

OCTOBER 1990 

Redes ignated Attainmen t Areas 

Coun ty E 

Unc lassified 

Coun ty A 

Coun ty B 

Unc lassified 

Coun ty C 

A tta in men t 

Coun ty D 

A tta in men t 

Ma jor Source 

Tri ggers Base lin e 2 

A tta in men t A tta in men t 2 

Base line Da te Triggered 10/6/78 

S tate line 

Coun ty line 

F igure C-2. Redefining the Baseline Area. 

C.15 
D R A F T 

OCTOBER 1990 

III. AMBIENT DATA REQUIREMENTS 

An applicant should be aware of the potential need to establish and operate 

a site-specific monitoring network for the collection of certain ambient data. 

With respect to air quality data, the PSD regulations contain provisions 

requiring an applicant to provide an ambient air quality analysis which may 

include pre-application monitoring data, and in some instances postconstruction monitoring data, for any pollutant proposed to be emitted by the 

new source or modification. In the absence of available monitoring data which 

is representative of the area of concern, this requirement could involve the 

operation of a site-specific air quality monitoring network by the applicant. 

Also, the need for meteorological data, for any dispersion modeling that must 

be performed, could entail the applicant's operation of a site-specific 

meteorological network. 

Pre-application data generally must be gathered over a period of at least 1 

year and the data are to represent at least the 12-month period immediately 

preceding receipt of the PSD application. Consequently, it is important that 

the applicant ascertain the need to collect any such data and proceed with the 

required monitoring activities as soon as possible in order to avoid undue 

delay in submitting a complete PSD application. 

III.A PRE-APPLICATION AIR QUALITY MONITORING 

For any criteria pollutant that the applicant proposes to emit in 

significant amounts, continuous ambient monitoring data may be required as 

part of the air quality analysis. If, however, either (1) the predicted 

ambient impact, i.e., the highest modeled concentration for the applicable 

averaging time, caused by the proposed significant emissions increase (or 

significant net emissions increase), or (2) the existing ambient pollutant 

concentrations are less than the prescribed significant monitoring value (see 

Table C-3), the permitting agency has discretionary authority to exempt an 

applicant from this data requirement. 

C.16 
D R A F T 

OCTOBER 1990 

TABLE C-3. SIGNIFICANT MONITORING CONCENTRATIONS 

Air Quality Concentration (μg/m3

) 

Pollutant and Averaging Time 

______________________________________________________________________________ 

Carbon monoxide 575 (8-hour) 

Nitrogen dioxide

Sulfur dioxide

Particulate Matter, TSP

Particulate Matter, PM-10

Ozone

Lead

Asbestos

Beryllium

Mercury

Vinyl chloride

Fluorides

Sulfuric acid mist

Total reduced sulfur (including H2S)

Reduced sulfur (including H2S)

Hydrogen sulfide

14 (Annual) 

13 (24-hour) 

10 (24-hour) 

10 (24-hour) 

a 

0.1 (3-month) 

b 

0.001(24-hour) 

0.25 (24-hour) 

15 (24-hour) 

0.25 (24-hour) 

b 

b 

b 

0.2 (1-hour) 

a No significant air quality concentration for ozone monitoring has been established. Instead, 

applicants with a net emissions increase of 100 tons/year or more of VOC's subject to PSD would 

be required to perform an ambient impact analysis, including pre-application monitoring data. 

b Acceptable monitoring techniques may not be available at this time. Monitoring requirements 

for this pollutant should be discussed with the permitting agency. 

C.17 
D R A F T 

OCTOBER 1990 

The determination of the proposed project's effects on air quality (for 

comparison with the significant monitoring value) is based on the results of 

the dispersion modeling used for establishing the impact area (see Section 

IV.B of this chapter). Modeling by itself or in conjunction with available 

monitoring data should be used to determine whether the existing ambient 

concentrations are equal to or greater than the significant monitoring value. 

The applicant may utilize a screening technique for this purpose, or may elect 

to use a refined model. Consultation with the permitting agency is advised 

before any model is selected. Ambient impacts from existing sources are 

estimated using the same model input data as are used for the NAAQS analysis, 

as described in section IV.D.4 of this chapter. 

If a potential threat to the NAAQS is identified by the modeling 

predictions, then continuous ambient monitoring data should be required, even 

when the predicted impact of the proposed project is less than the significant 

monitoring value. This is especially important when the modeled impacts of 

existing sources are uncertain due to factors such as complex terrain and 

uncertain emissions estimates. 

Also, if the location of the proposed source or modification is not 

affected by other major stationary point sources, the assessment of existing 

ambient concentrations may be done by evaluating available monitoring data. 

It is generally preferable to use data collected within the area of concern; 

however, the possibility of using measured concentrations from representative 

"regional" sites may be discussed with the permitting agency. The 

PSD Monitoring Guideline provides additional guidance on the use of such 

regional sites. 

Once a determination is made by the permitting agency that ambient 

monitoring data must be submitted as part of the PSD application, the 

requirement can be satisfied in one of two ways. First, under certain 

conditions, the applicant may use existing ambient data. To be acceptable, 

such data must be judged by the permitting agency to be representative of the 

air quality for the area in which the proposed project would construct and 

operate. Although a State or local agency may have monitored air quality for 

C.18 
D R A F T 

OCTOBER 1990 

several years, the data collected by such efforts may not necessarily be 

adequate for the preconstruction analysis required under PSD. In determining 

the representativeness of any existing data, the applicant and the permitting 

agency must consider the following critical items (described further in the 

PSD Monitoring Guideline): 

! monitor location; 

! quality of the data; and 

! currentness of the data. 

If existing data are not available, or they are judged not to be 

representative, then the applicant must proceed to establish a site-specific 

monitoring network. The EPA strongly recommends that the applicant prepare a 

monitoring plan before any actual monitoring begins. Some permitting agencies 

may require that such a plan be submitted to them for review and approval. In 

any case, the applicant will want to avoid any possibility that the resulting 

data are unacceptable because of such things as improperly located monitors, 

or an inadequate number of monitors. To assure the accuracy and precision of 

the data collected, proper quality assurance procedures pursuant to Appendix B 

of 40 CFR Part 58 must also be followed. The recommended minimum contents of 

a monitoring plan, and a discussion of the various considerations to be made 

in designing a PSD monitoring network, are contained in the PSD Monitoring 

Guideline. 

The PSD regulations generally require that the applicant collect 1 year 

of ambient data (EPA recommends 80 percent data recovery for PSD purposes). 

However, the permitting agency has discretion to accept data collected over a 

shorter period of time (but in no case less than 4 months) if a complete and 

adequate analysis can be accomplished with the resulting data. Any decision 

to approve a monitoring period shorter than 1 year should be based on a 

demonstration by the applicant (through historical data or dispersion 

modeling) that the required air quality data will be obtained during a time 

period, or periods, when maximum ambient concentrations can be expected. 

C.19 
D R A F T 

OCTOBER 1990 

For a pollutant for which there is no NAAQS (i.e., a noncriteria 

pollutant), EPA's general position is not require monitoring data, but to base 

the air quality analysis on modeled impacts. However, the permitting agency 

may elect to require the submittal of air quality monitoring data for 

noncriteria pollutants in certain cases, such as where: 

! a State has a standard for a non-criteria pollutant; 

! the reliability of emissions data used as input to modeling 

existing sources is highly questionable; and 

! available models or complex terrain make it difficult to 

estimate air quality or the impact of the proposed or 

modification. 

The applicant will need to confer with the permitting agency to determine 

whether any ambient monitoring may be required. Before the agency exercises 

its discretion to require such monitoring, there should be an acceptable 

measurement method approved by EPA or the appropriate permitting agency. 

With regard to particulate matter, where two different indicators of the 

pollutant are being regulated, EPA considers the PM-10 indicator to represent 

the criteria form of the pollutant (the NAAQS are now expressed in terms of 

ambient PM-10 concentrations) and TSP is viewed as the non-criteria form. 

Consequently, EPA intends to apply the pre-application monitoring requirements 

to PM-10 primarily, while treating TSP on a discretionary basis in light of 

its noncriteria status. Although the PSD increments for particulate matter 

are still based on the TSP indicator, modeling data, not ambient monitoring 

data, are used for increment analyses. 

Ambient air quality data collected by the applicant must be presented in 

the PSD application as part of the air quality analysis. Monitoring data 

collected for a criteria pollutant may be used in conjunction with dispersion 

modeling results to demonstrate NAAQS compliance. Each PSD application 

involves its own unique set of factors, i.e., the integration of measured 

ambient data and modeled projections. Consequently, the amount of data to be 

C.20 
D R A F T 

OCTOBER 1990 

used and the manner of presentation are matters that should be discussed with 

the permitting agency. 

III.B POST-CONSTRUCTION AIR QUALITY MONITORING 

The PSD Monitoring Guideline recommends that post-construction 

monitoring be done when there is a valid reason, such as (1) when the NAAQS 

are threatened, and (2) when there are uncertainties in the data bases for 

modeling. Any decision to require post-construction monitoring will generally 

be made after the PSD application has been thoroughly reviewed. It should be 

noted that the PSD regulations do not require that the significant monitoring 

concentrations be considered by the permitting agency in determining the need 

for post-construction monitoring. 

Existing monitors can be considered for collecting post-construction 

ambient data as long as they have been approved for PSD monitoring purposes. 

However, the location of the monitors should be checked to ascertain their 

appropriateness if other new sources or modifications have subsequently 

occurred, because the new emissions from the more recent projects could alter 

the location of points of maximum ambient concentrations where ambient 

measurements need to be made. 

Generally, post-construction monitoring should not begin until the 

source is operating near intended capacity. If possible the collection of 

data should be delayed until the source is operating at a rate equal to or 

greater than 50 percent of design capacity. The PSD Monitoring Guideline 

provides, however, that in no case should post-construction monitoring be 

delayed later than 2 years after the start-up of the new source or 

modification. 

Post-approval ozone monitoring is an alternative to pre-application 

monitoring for applicants proposing to emit VOC's if they choose to accept 

nonattainment preconstruction review requirements, including LAER, emissions 

and air quality offsets, and statewide compliance of other sources under the 

same ownership. As indicated in Table C-3, pre-application monitoring for 

C.21 
D R A F T 

OCTOBER 1990 

ozone is required when the proposed source or modification would emit at least 

100 tons per year of volatile organic compounds (VOC). Note that this 

emissions rate for VOC emissions is a surrogate for the significant monitoring 

concentration for the pollutant ozone (see Table C-3). Under 

40 CFR 52.21(m)(1)(vi), post-approval monitoring data for ozone is required 

(and cannot be waived) in conjunction with the aforementioned nonattainment 

review requirements when the permitting agency waives the requirement for preapplication ozone monitoring data. The post-approval period may begin any 

time after the source receives its PSD permit. In no case should the postapproval monitoring be started later than 2 years after the start-up of the 

new source or modification. 

III.C METEOROLOGICAL MONITORING 

Meteorological data is generally needed for model input as part of the 

air quality analysis. It is important that such data be representative of the 

atmospheric dispersion and climatological conditions at the site of the 

proposed source or modification, and at locations where the source may have a 

significant impact on air quality. For this reason, site specific data are 

preferable to data collected elsewhere. On-site meteorological monitoring may 

be required, even when on-site air quality monitoring is not. 

The PSD Monitoring Guideline should be used to establish locations for 

any meteorological monitoring network that the applicant may be required to 

operate and maintain as part of the preconstruction monitoring requirements. 

That guidance specifies the meteorological instrumentation to be used in 

measuring meteorological parameters such as wind speed, wind direction, and 

temperature. The PSD Monitoring Guideline also provides that the retrieval 

of valid wind/stability data should not fall below 90 percent on an annual 

basis. The type, quantity, and format of the required data will be influenced 

by the specific input requirements of the dispersion modeling techniques used 

in the air quality analysis. Therefore, the applicant will need to consult 

with the permitting agency prior to establishing the required network. 

C.22 
D R A F T 

OCTOBER 1990 

Additional guidance for the collection and use of on-site data is 

provided in the PSD Monitoring Guideline. Also, the EPA documents entitled 

On-Site Meteorological Program Guidance for Regulatory Modeling Applications 

(Reference 3), and Volume IV of the series of reports entitled Quality 

Assurance Handbook for Air Pollution Measurement Systems (Reference 4), 

contain information required to ensure the quality of the meteorological 

measurements collected. 

C.23 
D R A F T 

OCTOBER 1990 

IV. DISPERSION MODELING ANALYSIS 

Dispersion models are the primary tools used in the air quality 

analysis. These models estimate the ambient concentrations that will result 

from the PSD applicant's proposed emissions in combination with emissions from 

existing sources. The estimated total concentrations are used to demonstrate 

compliance with any applicable NAAQS or PSD increments. The applicant should 

consult with the permitting agency to determine the particular requirements 

for the modeling analysis to assure acceptability of any air quality modeling 

technique(s) used to perform the air quality analysis contained in the PSD 

application. 

IV.A OVERVIEW OF THE DISPERSION MODELING ANALYSIS 

The dispersion modeling analysis usually involves two distinct phases: 

(1) a preliminary analysis and (2) a full impact analysis. The preliminary 

analysis models only the significant increase in potential emissions of a 

pollutant from a proposed new source, or the significant net emissions 

increase of a pollutant from a proposed modification. The results of this 

preliminary analysis determine whether the applicant must perform a full 

impact analysis, involving the estimation of background pollutant 

concentrations resulting from existing sources and growth associated with the 

proposed source. Specifically, the preliminary analysis: 

! determines whether the applicant can forego further air quality 

analyses for a particular pollutant; 

! may allow the applicant to be exempted from the ambient monitoring 

data requirements (described in section III of this chapter); and 

! is used to define the impact area within which a full impact 

analysis must be carried out. 

The EPA does not require a full impact analysis for a particular 

pollutant when emissions of that pollutant from a proposed source or 

modification would not increase ambient concentrations by more than prescribed 

significant ambient impact levels, including special Class I significance 

C.24 
D R A F T 

OCTOBER 1990 

levels. However, the applicant should check any applicable State or local PSD 

program requirements in order to determine whether such requirements may 

contain any different procedures which may be more stringent. In addition, 

the applicant must still address the requirements for additional impacts 

required under separate PSD requirements, as described in Chapters D and E 

which follow this chapter. 

A full impact analysis is required for any pollutant for which the 

proposed source's estimated ambient pollutant concentrations exceed prescribed 

significant ambient impact levels. This analysis expands the preliminary 

analysis in that it considers emissions from: 

! the proposed source; 

! existing sources; 

! residential, commercial, and industrial growth that accompanies 

the new activity at the new source or modification (i.e., 

secondary emissions). 

For SO2, particulate matter, and NO2, the full impact analysis actually 

consists of separate analyses for the NAAQS and PSD increments. As described 

later in this section, the selection of background sources (and accompanying 

emissions) to be modeled for the NAAQS and increment components of the overall 

analysis proceeds under somewhat different sets of criteria. In general, 

however, the full impact analysis is used to project ambient pollutant 

concentrations against which the applicable NAAQS and PSD increments are 

compared, and to assess the ambient impact of non-criteria pollutants. 

The reviewer's primary role is to determine whether the applicant select 

ed the appropriate model(s), used appropriate input data, and followed 

recommended procedures to complete the air quality analysis. Appendix C in 

the Modeling Guideline provides an example checklist which recommends a 

standardized set of data to aid the reviewer in determining the completeness 

and correctness of an applicant's air quality analysis. 

C.25 
D R A F T 

OCTOBER 1990 

Figure C-3 outlines the basic steps for an applicant to follow for a PSD 

dispersion modeling analysis to demonstrate compliance with the NAAQS and PSD 

increments. These steps are described in further detail in the sections which 

follow. 

IV.B DETERMINING THE IMPACT AREA 

The proposed project's impact area is the geographical area for which 

the required air quality analyses for the NAAQS and PSD increments are carried 

out. This area includes all locations where the significant increase in the 

potential emissions of a pollutant from a new source, or significant net 

emissions increase from a modification, will cause a significant ambient 

impact (i.e., equal or exceed the applicable significant ambient impact level, 

as shown in Table C-4). The highest modeled pollutant concentration for each 

averaging time is used to determine whether the source will have a significant 

ambient impact for that pollutant. 

The impact area is a circular area with a radius extending from the 

source to (1) the most distant point where approved dispersion modeling 

predicts a significant ambient impact will occur, or (2) a modeling receptor 

distance of 50 km, whichever is less. Usually the area of modeled significant 

impact does not have a continuous, smooth border. (It may actually be 

comprised of pockets of significant impact separated by pockets of 

insignificant impact.) Nevertheless, the required air quality analysis is 

carried out within the circle that circumscribes the significant ambient 

impacts, as shown in Figure C-4. 

Initially, for each pollutant subject to review an impact area is 

determined for every averaging time. The impact area used for the air quality 

analysis of a particular pollutant is the largest of the areas determined for 

that pollutant. For example, modeling the proposed SO2 emissions from a new 

source might show that a significant ambient SO2 impact occurs out to a 

distance from the source of 2 kilometers for the annual averaging period; 

C.26 
D R A F T 

OCTOBER 1990 

Pollutant Emitted in 

Significant Amounts 

Meteorological Data 

Source Input Data 

Ambient 

Concentrations 

Above Air Quality 

Significance 

Level 

Yes 

No No Further NAAQS or 

Required for Pollutant 

Determine 

Impact Area 

Develop Emissions 

Inventory 

Source Input Data 

Meteorological Data 

Demonstration of 

Compliance 

Model Impact of 

Proposed, Existing, and 

Model Impact of 

Proposed Source 

Add Monitored 

Background Levels 

Determine Need for 

Pre-application 

Monitoring 

PSD Increment Analysis 

(for NAAQS only) 

Secondary Emissions 

Preliminary 

Analysis Full Impact Analysis 

Figure I-C-3. Basic Steps in the Air Quality Analysis 

(NAAQS and PSD Increments) 

C.27 
------------------------------------------------------------------------------

D R A F T 

OCTOBER 1990 

TABLE C-4. 

SIGNIFICANCE LEVELS FOR AIR QUALITY IMPACTS IN CLASS II AREASa 

444444444444444444444444444444444444444444444444444444444444444444444444444444 

Pollutant Annual 24-hour 8-hour 3-hour 1-hour 

SO2 1 5 - 25 -

TSP 1 5 - - -

PM-10 1 5 - - -

NOx 1 - - - -

CO - - 500 - 2,000 

O3 - - - - b 

444444444444444444444444444444444444444444444444444444444444444444444444444444 

a This table does not apply to Class I areas. If a proposed source is 

located within 100 kilometers of a Class I area, an impact of 1 μg/m3

 on a 

24-hour basis is significant. 

b No significant ambient impact concentration has been established. Instead, 

any net emissions increase of 100 tons per year of VOC subject to PSD would 

be required to perform an ambient impact analysis. 

C.28 
D R A F T 

OCTOBER 1990 

County E 

Unclassified 

County A 

County B 

Unclassified 

County C 

Attainment 

County D 

Attainment 

Major Source 

State line 

r 

Impact Area 

Attainment 

County line 

Figure C-4. Determining the Impact Area. 

C.29 
D R A F T 

OCTOBER 1990 

4.3 kilometers for the 24-hour averaging period; and 3.8 kilometers for the 3-

hour period. Therefore, an impact area with a radius of 4.3 kilometers from 

the proposed source is selected for the SO2 air quality analysis. 

In the event that the maximum ambient impact of a proposed emissions 

increase is below the appropriate ambient air quality significance level for 

all locations and averaging times, a full impact analysis for that pollutant 

is not required by EPA. Consequently, a preliminary analysis which predicts 

an insignificant ambient impact everywhere is accepted by EPA as the required 

air quality analysis (NAAQS and PSD increments) for that pollutant. [NOTE: 

While it may be shown that no impact area exists for a particular pollutant, 

the PSD application (assuming it is the first one in the area) still 

establishes the PSD baseline area and minor source baseline date in the 

section 107 attainment or unclassifiable area where the source will be 

located, regardless of its insignificant ambient impact.] 

For each applicable pollutant, the determination of an impact area must 

include all stack emissions and quantifiable fugitive emissions resulting from 

the proposed source. For a proposed modification, the determination includes 

contemporaneous emissions increases and decreases, with emissions decreases 

input as negative emissions in the model. The EPA allows for the exclusion of 

temporary emissions (e.g., emissions occurring during the construction phase 

of a project) when establishing the impact area and conducting the subsequent 

air quality analysis, if it can be shown that such emissions do not impact a 

Class I area or an area where a PSD increment for that pollutant is known to 

be violated. However, where EPA is not the PSD permitting authority, the 

applicant should confer with the appropriate permitting agency to determine 

whether it allows for the exclusion of temporary emissions. 

C.30 
D R A F T 

OCTOBER 1990 

Once defined for the proposed PSD project, the impact area(s) will 

determine the scope of the required air quality analysis. That is, the impact 

area(s) will be used to 

! set the boundaries within which ambient air quality monitoring 

data may need to be collected, 

! define the area over which a full impact analysis (one that 

considers the contribution of all sources) must be undertaken, and 

! guide the identification of other sources to be included in the 

modeling analyses. 

Again, if no significant ambient impacts are predicted for a particular 

pollutant, EPA does not require further NAAQS or PSD increment analysis of 

that pollutant. However, the applicant must still consider any additional 

impacts which the proposed source may have concerning impairment on 

visibility, soils and vegetation, as well as any adverse impacts on air 

quality related values in Class I areas (see Chapters D and E of this part). 

IV.C SELECTING SOURCES FOR THE PSD EMISSIONS INVENTORIES 

When a full impact analysis is required for any pollutant, the applicant 

is responsible for establishing the necessary inventories of existing sources 

and their emissions, which will be used to carry out the required NAAQS and 

PSD increment analyses. Such special emissions inventories contain the 

various source data used as input to an applicable air quality dispersion 

model to estimate existing ambient pollutant concentrations. Requirements for 

preparing an emissions inventory to support a modeling analysis are described 

to a limited extent in the Modeling Guideline. In addition, a number of other 

EPA documents (e.g., References 5 through 11) contain guidance on the 

fundamentals of compiling emissions inventories. The discussion which follows 

pertains primarily to identifying and selecting existing sources to be 

included in a PSD emissions inventory as needed for a full impact analysis. 

The permitting agency may provide the applicant a list of existing 

sources upon request once the extent of the impact area(s) is known. If the 

C.31 
D R A F T 

OCTOBER 1990 

list includes only sources above a certain emissions threshold, the applicant 

is responsible for identifying additional sources below that emissions level 

which could affect the air quality within the impact area(s). The permitting 

agency should review all required inventories for completeness and accuracy. 

IV.C.1 THE NAAQS INVENTORY 

While air quality data may be used to help identify existing background 

air pollutant concentrations, EPA requires that, at a minimum, all nearby 

sources be explicitly modeled as part of the NAAQS analysis. The Modeling 

Guideline defines a "nearby" source as any point source expected to cause a 

significant concentration gradient in the vicinity of the proposed new source 

or modification. For PSD purposes, "vicinity" is defined as the impact area. 

However, the location of such nearby sources could be anywhere within the 

impact area or an annular area extending 50 kilometers beyond the impact area. 

(See Figure C-5.) 

In determining which existing point sources constitute nearby sources, 

the Modeling Guideline necessarily provides flexibility and requires judgment 

to be exercised by the permitting agency. Moreover, the screening method for 

identifying a nearby source may vary from one permitting agency to another. 

To identify the appropriate method, the applicant should confer with the 

permitting agency prior to actually modeling any existing sources. 

The Modeling Guideline indicates that the useful distance for guideline 

models is 50 kilometers. Occasionally, however, when applying the above 

source identification criteria, existing stationary sources located in the 

annular area beyond the impact area may be more than 50 kilometers from 

portions of the impact area. When this occurs, such sources' modeled impacts 

throughout the entire impact area should be calculated. That is, special 

steps should not be taken to cut off modeled impacts of existing sources at 

receptors within the applicants impact area merely because the receptors are 

C.32 
D R A F T 

OCTOBER 1990 

County E 

Unclassified 

County A 

County B 

Unclassified 

County C 

Attainment 

County D 

Attainment 

Major Source 

State line 

County line 

r 

Attainment 

Screening Area 

Impact Area 

50 km. 

Figure C-5 

Defining the Emissions Inventory Screening Area. 

C.33 
D R A F T 

OCTOBER 1990 

located beyond 50 kilometers from such sources. Modeled impacts beyond 50 

kilometers should be considered as conservative estimate in that they tend to 

overestimate the true source impacts. Consequently, if it is found that an 

existing source's impact include estimates at distances exceeding the normal 

50-kilometer range, it may be appropriate to consider other techniques, 

including long-range transport models. Applicants should consult with the 

permitting agency prior to the selection of a model in such cases. 

It will be necessary to include in the NAAQS inventory those sources 

which have received PSD permits but have not yet not begun to operate, as well 

as any complete PSD applications for which a permit has not yet been issued. 

In the latter case, it is EPA's policy to account for emissions that will 

occur at sources whose complete PSD application was submitted as of thirty 

days prior to the date the proposed source files its PSD application. Also, 

sources from which secondary emissions will occur as a result of the proposed 

source should be identified and evaluated for inclusion in the NAAQS 

inventory. While existing mobile source emissions are considered in the 

determination of background air quality for the NAAQS analysis (typically 

using existing air quality data), it should be noted that the applicant need 

not model estimates of future mobile source emissions growth that could result 

from the proposed project because the definition of "secondary emissions" 

specifically excludes any emissions coming directly from mobile sources. 

Air quality data may be used to establish background concentrations in 

the impact area resulting from existing sources that are not considered as 

nearby sources (e.g., area and mobile sources, natural sources, and distant 

point sources). If, however, adequate air quality data do not exist (and the 

applicant was not required to conduct pre-application monitoring), then these 

"other" background sources are also included in the NAAQS inventory so that 

their ambient impacts can be estimated by dispersion modeling. 

C.34 
D R A F T 

OCTOBER 1990 

IV.C.2 THE INCREMENT INVENTORY 

An emissions inventory for the analysis of affected PSD increments must 

also be developed. The increment inventory includes all increment-affecting 

sources located in the impact area of the proposed new source or modification. 

Also, all increment-affecting sources located within 50 kilometers of the 

impact area (see Figure C-5) are included in the inventory if they, either 

individually or collectively, affect the amount of PSD increment consumed. 

The applicant should contact the permitting agency to determine what 

particular procedures should be followed to identify sources for the increment 

inventory. 

In general, the stationary sources of concern for the increment 

inventory are those stationary sources with actual emissions changes occurring 

since the minor source baseline date. However, it should be remembered that 

certain actual emissions changes occurring before the minor source baseline 

date (i.e., at major stationary point sources) also affect the increments. 

Consequently, the types of stationary point sources that are initially 

reviewed to determine the need to include them in the increment inventory fall 

under two specific time frames as follows: 

After the major source baseline date­

! existing major stationary sources having undergone a physical 

change or change in their method of operation; and 

! new major stationary sources. 

After the minor source baseline date­

! existing stationary sources having undergone a physical 

change or change in their method of operation; 

! existing stationary sources having increased hours of 

operation or capacity utilization (unless such change was 

considered representative of baseline operating conditions); and 

! new stationary sources. 

C.35 
D R A F T 

OCTOBER 1990 

If, in the impact area or surrounding screening area, area or mobile 

source emissions will affect increment consumption, then emissions input data 

for such minor sources are also included in the increment inventory. The 

change in such emissions since the minor source baseline date (rather than the 

absolute magnitude of these emissions) is of concern since this change is what 

may affect a PSD increment. Specifically, the rate of growth and the amount 

of elapsed time since the minor source baseline date was established determine 

the extent of the increase in area and mobile source emissions. For example, 

in an area where the minor source baseline date was recently established 

(e.g., within the past year or so of the proposed PSD project), very little 

area and mobile source emissions growth may have occurred. Also, sufficient 

data (particularly mobile source data) may not yet be available to reflect the 

amount of growth that has taken place. As with the NAAQS analysis, applicants 

are not required to estimate future mobile source emissions growth that could 

result from the proposed project because they are excluded from the definition 

of "secondary emissions." 

The applicant should initially consult with the permitting agency to 

determine the availability of data for assessing area and mobile source growth 

since the minor source baseline date. This information, or the fact that such 

data is not available, should be thoroughly documented in the application. 

The permitting agency should verify and approve the basis for actual area 

source emissions estimates and, especially if these estimates are considered 

by the applicant to have an insignificant impact, whether it agrees with the 

applicant's assessment. 

When area and mobile sources are determined to affect any PSD increment, 

their emissions must be reported on a gridded basis. The grid should cover 

the entire impact area and any areas outside the impact area where area and 

mobile source emissions are included in the analysis. The exact sizing of an 

emissions inventory grid cell generally should be based on the emissions 

density in the area and any computer constraints that may exist. Techniques 

for assigning area source emissions to grid cells are provided in 

Reference 11. The grid layout should always be discussed with, and approved 

by, the permitting agency in advance of its use. 

C.36 
D R A F T 

OCTOBER 1990 

IV.C.3 NONCRITERIA POLLUTANTS INVENTORY 

An inventory of all noncriteria pollutants emitted in significant 

amounts is required for estimating the resulting ambient concentrations of 

those pollutants. Significant ambient impact levels have not been established 

for non-criteria pollutants. Thus, an impact area cannot be defined for noncriteria pollutants in the same way as for criteria pollutants. Therefore, as 

a general rule of thumb, EPA believes that an emissions inventory for noncriteria pollutants should include sources within 50 kilometers of the 

proposed source. Some judgment will be exercised in applying this position on 

a case-by-case basis. 

IV.D MODEL SELECTION 

Two levels of model sophistication exist: screening and refined 

dispersion modeling. Screening models may be used to eliminate more extensive 

modeling for either the preliminary analysis phase or the full impact analysis 

phase, or both. However, the results must demonstrate to the satisfaction of 

the permitting agency that all applicable air quality analysis requirements 

are met. Screening models produce conservative estimates of ambient impact in 

order to reasonably assure that maximum ambient concentrations will not be 

underestimated. If the resulting estimates from a screening model indicate a 

threat to a NAAQS or PSD increment, the applicant uses a refined model to reestimate ambient concentrations (of course, the applicant can select other 

options, such as reducing emissions, or to decrease impacts). Guidance on the 

use of screening procedures to estimate the air quality impact of stationary 

sources is presented in EPA's Screening Procedures for Estimating Air Qaulity 

Impact of Stationary Sources [Reference 12]. 

A refined dispersion model provides more accurate estimates of a 

source's impact and, consequently, requires more detailed and precise input 

data than does a screening model. The applicant is referred to Appendix A of 

the Modeling Guideline for a list of EPA-preferred models, i.e., guideline 

models. The guideline model selected for a particular application should be 

the one which most accurately represents atmospheric transport, dispersion, 

C.37 
D R A F T 

OCTOBER 1990 

and chemical transformations in the area under analysis. For example, models 

have been developed for both simple and complex terrain situations; some are 

designed for urban applications, while others are designed for rural 

applications. 

In many circumstances the guideline models known as Industrial Source 

Complex Model Short- and Long-term (ISCST and ISCLT, respectively) are 

acceptable for stationary sources and are preferred for use in the dispersion 

modeling analysis. A brief discussion of options required for regulatory 

applications of the ISC model is contained in the Modeling Guideline. Other 

guideline models, such as the Climatological Dispersion Model (CDM), may be 

needed to estimate the ambient impacts of area and mobile sources. 

Under certain circumstances, refined dispersion models that are not 

listed in the Modeling Guideline, i.e., non-guideline models, may be 

considered for use in the dispersion modeling analysis. The use of a nonguideline model for a PSD permit application must, however, be pre-approved on 

a case-by-case basis by EPA. The applicant should refer to the EPA documents 

entitled Interim Procedures for Evaluating Air Quality Models (Revised) 

[Reference 13] and Interim Procedures for Evaluating Air Quality Models: 

Experience with Implementation [Reference 14]. Close coordination with EPA 

and the appropriate State or local permitting agency is essential if a nonguideline model is to be used successfully. 

C.38 
D R A F T 

OCTOBER 1990 

IV.D.1 METEOROLOGICAL DATA 

Meteorological data used in air quality modeling must be spatially and 

climatologically (temporally) representative of the area of interest. 

Therefore, an applicant should consult the permitting authority to determine 

what data will be most representative of the location of the applicant's 

proposed facility. 

Use of site-specific meteorological data is preferred for air quality 

modeling analyses if 1 or more years of quality-assured data are available. 

If at least 1 year of site-specific data is not available, 5 years of 

meteorological data from the nearest National Weather Service (NWS) station 

can be used in the modeling analysis. Alternatively, data from universities, 

the Federal Aviation Administration, military stations, industry, and State or 

local air pollution control agencies may be used if such data are equivalent 

in accuracy and detail to the NWS data, and are more representative of the 

area of concern. 

The 5 years of data should be the most recent consecutive 5 years of 

meteorological data available. This 5-year period is used to ensure that the 

model results adequately reflect meteorological conditions conducive to the 

prediction of maximum ambient concentrations. The NWS data may be obtained 

from the National Climatic Data Center (Asheville, North Carolina), which 

serves as a clearinghouse to collect and distribute meteorological data 

collected by the NWS. 

IV.D.2 RECEPTOR NETWORK 

Polar and Cartesian networks are two types of receptor networks commonly 

used in refined air dispersion models. A polar network is comprised of 

concentric rings and radial arms extending outward from a center point (e.g., 

the modeled source). Receptors are located where the concentric rings and 

radial arms intersect. Particular care should be exercised in using a polar 

network to identify maximum estimated pollutant concentrations because of the 

inherent problem of increased longitudinal spacing of adjacent receptors as 

C.39 
D R A F T 

OCTOBER 1990 

their distance along neighboring radial arms increases. For example, as 

illustrated in Figure C-6, while the receptors on individual radials, e.g., 

A1, A2, A3... and B1, B2, B3..., may be uniformly spaced at a distance of 1 

kilometer apart, at greater distances from the proposed source, the 

longitudinal distance between the receptors, e.g., A4 and B4, on neighboring 

radials may be several kilometers. As a result of the presence of larger and 

larger "blind spots" between the radials as the distance from the modeled 

source increases, finding the maximum source impact can be somewhat 

problematic. For this reason, using a polar network for anything other than 

initial screening is generally discouraged. 

A cartesian network (also referred to as a rectangular network) consists 

of north-south and east-west oriented lines forming a rectangular grid, as 

shown in Figure C-6, with receptors located at each intersection point. In 

most refined air quality analyses, a cartesian grid with from 300 to 400 

receptors (where the distance from the source to the farthest receptor is 10 

kilometers) is usually adequate to identify areas of maximum concentration. 

However, the total number of receptors will vary based on the specific air 

quality analysis performed. 

In order to locate the maximum modeled impact, perform multiple model 

runs, starting with a relatively coarse receptor grid (e.g., one or two 

kilometer spacing) and proceeding to a relatively fine receptor grid (e.g., 

100 meters). The fine receptor grid should be used to focus on the area(s) of 

higher estimated pollutant concentrations identified by the coarse grid model 

runs. With such multiple runs the maximum modeled concentration can be 

identified. It is the applicant's responsibility to demonstrate that the 

final receptor network is sufficiently compact to identify the maximum 

estimated pollutant concentration for each applicable averaging period. This 

applies both to the PSD increments and to the NAAQS. 

C.40 
D R A F T

OCTOBER 1990

A1 A2 A3 A4 A5 A6 

B1 

B2 

B3 

B4 

B5 

B6 

A1 A2 A3 A4 A5 A6 

B1 B2 B3 B4 B5 B6 

Cartesian Grid Network 

Polar Grid Network 

1 km 

1 km 

1 km 

5 km 

Figure C-6. Examples of Polar and Cartesian Grid Networks. 

C.41 
D R A F T 

OCTOBER 1990 

Some air quality models allow the user to input discrete receptors at 

user-specified locations. The selection of receptor sites should be a caseby-case determination, taking into consideration the topography, the 

climatology, the monitor sites, and the results of the preliminary analysis. 

For example, receptors should be located at: 

! the fenceline of a proposed facility; 

! the boundary of the nearest Class I or nonattainment area; 

! the location(s) of ambient air monitoring sites; and 

! locations where potentially high ambient air concentrations are 

expected to occur. 

In general, modeling receptors for both the NAAQS and the PSD 

increment analyses should be placed at ground level points anywhere 

except on the applicant's plant property if it is inaccessible to the 

general public. Public access to plant property is to be assumed, however, 

unless a continuous physical barrier, such as a fence or wall, precludes 

entrance onto that property. In cases where the public has access, receptors 

should be located on the applicant's property. It is important to note that 

ground level points of receptor placement could be over bodies of water, 

roadways, and property owned by other sources. For NAAQS analyses, modeling 

receptors may also be placed at elevated locations, such as on building 

rooftops. However, for PSD increments, receptors are limited to locations at 

ground level. 

IV.D.3 GOOD ENGINEERING PRACTICE (GEP) STACK HEIGHT 

Section 123 of the Clean Air Act limits the use of dispersion 

techniques, such as merged gas streams, intermittent controls, or stack 

heights above GEP, to meet the NAAQS or PSD increments. The GEP stack height 

is defined under Section 123 as "the height necessary to insure that emissions 

from the stack do not result in excessive concentrations of any air pollutant 

in the immediate vicinity of the source as a result of atmospheric downwash, 

C.42 
D R A F T 

OCTOBER 1990 

eddies or wakes which may be created by the source itself, nearby structures 

or nearby terrain obstacles." The EPA has promulgated stack height 

regulations under 40 CFR Part 51 which help to determine the GEP stack height 

for any stationary source. 

Three methods are available for determining "GEP stack height" as 

defined in 40 CFR 51.100(ii): 

! use the 65 meter (213.5 feet) de minimis height as measured from 

the ground-level elevation at the base of the stack; 

! calculate the refined formula height using the dimensions of 

nearby structures (this height equals H + 1.5L, where H is the 

height of the nearby structure and L is the lesser dimension of 

the height or projected width of the nearby structure); or 

! demonstrate by a fluid model or field study the equivalent GEP 

formula height that is necessary to avoid excessive concentrations 

caused by atmospheric downwash, wakes, or eddy effects by the 

source, nearby structures, or nearby terrain features. 

That portion of a stack height in excess of the GEP height is generally 

not creditable when modeling to develop source emissions limitations or to 

determine source impacts in a PSD air quality analysis. For a stack height 

less than GEP height, screening procedures should be applied to assess 

potential air quality impacts associated with building downwash. In some 

cases, the aerodynamic turbulence induced by surrounding buildings will cause 

stack emissions to be mixed rapidly toward the ground (downwash), resulting in 

higher-than-normal ground level concentrations in the vicinity of the source. 

Reference 12 contain screening procedures to estimate downwash concentrations 

in the building wake region. The Modeling Guideline recommends using the 

Industrial Source Complex (ISC) air dispersion model to determine building 

wake effects on maximum estimated pollutant concentrations. 

For additional guidance on creditable stack height and plume rise 

calculations, the applicant should consult with the permitting agency. In 

addition, several EPA publications [References 15 through 19] are available 

for the applicant's review. 

C.43 
D R A F T 

OCTOBER 1990 

IV.D.4 SOURCE DATA 

Emissions rates and other source-related data are needed to estimate the 

ambient concentrations resulting from (1) the proposed new source or 

modification, and (2) existing sources contributing to background pollutant 

concentrations (NAAQS and PSD increments). Since the estimated pollutant 

concentrations can vary widely depending on the accuracy of such data, the 

most appropriate source data available should always be selected for use in a 

modeling analysis. Guidance on the identification and selection of existing 

sources for which source input data must be obtained for a PSD air quality 

analysis is provided in section IV.C. Additional information on the specific 

source input data requirements is contained in EPA's Modeling Guideline and in 

the users' guide for each dispersion model. 

Source input data that must be obtained will depend upon the 

categorization of the source(s) to be modeled as either a point, area or line 

source. Area sources are often collections of numerous small emissions 

sources that are impractical to consider as separate point or line sources. 

Line sources most frequently considered are roadways. 

For each stationary point source to be modeled, the following minimum 

information is generally necessary: 

! pollutant emission rate (see discussion below); 

! stack height (see discussion on GEP stack height); 

! stack gas exit temperature, stack exit inside diameter, and stack 

gas exit velocity; 

! dimensions of all structures in the vicinity of the stack in 

question; 

! the location of topographic features (e.g., large bodies of water, 

elevated terrain) relative to emissions points; and 

! stack coordinates. 

C.44 
D R A F T 

OCTOBER 1990 

A source's emissions rate as used in a modeling analysis for any 

pollutant is determined from the following source parameters (where MMBtu 

means "million Btu's heat input"): 

! emissions limit (e.g., lb/MMBtu); 

! operating level (e.g., MMBtu/hour); and 

! operating factor (e,g., hours/day, hours/year). 

Special procedures, as described below, apply to the way that each of these 

parameters is used in calculating the emissions rate for either the proposed 

new source (or modification) or any existing source considered in the NAAQS 

and PSD increment analyses. Table C-5 provides a summary of the point source 

emissions input data requirements for the NAAQS inventory. 

For both NAAQS and PSD increment compliance demonstrations, the 

emissions rate for the proposed new source or modification must reflect the 

maximum allowable operating conditions as expressed by the federally 

enforceable emissions limit, operating level, and operating factor for each 

applicable pollutant and averaging time. The applicant should base the 

emissions rates on the results of the BACT analysis (see Chapter B, Part I). 

Operating levels less than 100 percent of capacity may also need to be modeled 

where differences in stack parameters associated with the lower operating 

levels could result in higher ground level concentrations. A value 

representing less than continuous operation (8760 hours per year) should be 

used for the operating factor only when a federally enforceable operating 

limitation is placed upon the proposed source. [NOTE: It is important that 

the applicant demonstrate that all modeled emission rates are consistent with 

the applicable permit conditions.] 

C.45 
D R A F T 

OCTOBER 1990 

TABLE C-5 POINT SOURCE MODEL INPUT DATA (EMISSIONS) FOR NAAQS COMPLIANCE DEMONSTRATIONS 

Averaging Time Emission Limit Operating Level Operating Factor 

(#/MMBtu)1 X (MMBtu/hr)1 X (e.g., hr/yr, hr/day) 

W4444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444

Proposed Major New or Modified Source 

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Annual and quarterly Maximum allowable emission Design capacity or Federally Continuous operation 

limit or Federally enforceable enforceable permit condition (i.e, 8760 hours)2 

permit 

Short term Maximum allowable emission Design capacity or Federally Continuous operation (i.e., 

(24 hours or less) limit or Federally enforceable enforceable permit condition3 all hours of each time 

permit limit period under consideration) 

(for all hours of the 

meteorological data base)2 

W4444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 

Nearby Background Source(s)4 

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Annual and quarterly Maximum allowable emission Actual or design capacity Actual operating factor 

limit or Federally enforceable (whichever is greater), or averaged over the most 

permit Federally enforceable permit recent 2 years5 

condition 

Short term Maximum allowable emission Actual or design capacity Continuous operation (i.e., 

limit or Federally enforceable (whichever is greater), or all hours of each time 

permit limit Federally enforceable permit period under consideration) 

condition3 (for all hours of the 

meteorological data base)2 

W4444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444444 

Other Background Source(s)6 

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Annual and quarterly Maximum allowable emission Annual level when actually Actual operating factor 

limit or Federally enforceable operating, averaged over the averaged over the most 

permit limit most recent 2 years5 recent 2 years5 

Short term Maximum allowable emission Annual level when actually Continuous operation (i.e., 

limit or Federally enforceable operating, averaged over the all hours of each time 

permit limit most recent 2 years5 period under consideration) 

(for all hours of the 

meteorological data base)2 

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1 Terminology applicable to fuel burning sources; analogous terminology (e.g., #/throughput) may be used for other types of sources. 2 If operation does not occur for all hours of the time period of consideration (e.g., 3 or 24 hours) and the source operation is constrained 

by a Federally enforceable permit condition, an appropriate adjustment to the modeled emission rate may be made (e.g., if operation is only 

8:00 a.m. to 4:00 p.m. each day, only these hours will be modeled with emissions from the source. Modeled emissions should not be averaged 

across non-operating time periods). 3 Operating levels such as 50 percent and 75 percent of capacity should also be modeled to determine the load causing the highest concentration. 4 Includes existing facility to which modification is proposed if the emissions from the existing facility will not be affected by the 

modification. Otherwise use same parameters as for major modification. 5 Unless it is determined that this period is not representative. 6 Generally, the ambient impacts from non-nearby background sources can be represented by air quality data unless adequate data do not exist. 

C.46 
D R A F T 

OCTOBER 1990 

For those existing point sources that must be explicitly modeled, i.e., 

"nearby" sources (see section IV.C.1 of this chapter), the NAAQS inventory 

must contain the maximum allowable values for the emissions limit, and 

operating level. The operating factor may be adjusted to account for 

representative, historical operating conditions only when modeling for the 

annual (or quarterly for lead [Pb]) averaging period. In such cases, the 

appropriate input is the actual operating factor averaged over the most recent 

2 years (unless the permitting agency determines that another period is more 

representative). For short-term averaging periods (24 hours or less), the 

applicant generally should assume that nearby sources operate continuously. 

However, the operating factor may be adjusted to take into account any 

federally enforceable permit condition which limits the allowable hours of 

operation. In situations where the actual operating level exceeds the design 

capacity (considering any federally enforceable limitations), the actual level 

should be used to calculate the emissions rate. 

If other background sources need to be modeled (i.e., adequate air 

quality data are not available to represent their impact), the input 

requirements for the emissions limit and operating factor are identical to 

those for "nearby" sources. However, input for the operating level may be 

based on the annual level of actual operation averaged over the last 2 years 

(unless the permitting agency determines that a more representative period 

exists). 

The applicant must also include any quantifiable fugitive emissions from 

the proposed source or any nearby sources. Fugitive emissions are those 

emissions that cannot reasonably be expected to pass through a stack, vent, or 

other equivalent opening, such as a chimney or roof vent. Common quantifiable 

fugitive emissions sources of particulate matter include coal piles, road 

dust, quarry emissions, and aggregate stockpiles. Quantifiable fugitive 

emissions of volatile organic compounds (VOC) often occur at components of 

process equipment. An applicant should consult with the permitting agency to 

determine the proper procedures for characterizing and modeling fugitive 

emissions. 

C.47 
D R A F T 

OCTOBER 1990 

When building downwash affects the air quality impact of the proposed 

source or any existing source which is modeled for the NAAQS analysis, those 

impacts generally should be considered in the analysis. Consequently, the 

appropriate dimensions of all structures around the stack(s) in question also 

should be included in the emissions inventory. Information including building 

heights and horizontal building dimensions may be available in the permitting 

agency's files; otherwise, it is usually the responsibility of the applicant 

to obtain this information from the applicable source(s). 

Sources should not automatically be excluded from downwash 

considerations simply because they are located outside the impact area. Some 

sources located just outside the impact area may be located close enough to it 

that the immediate downwashing effects directly impact air quality in the 

impact area. In addition, the difference in downwind plume concentrations 

caused by the downwash phenomenon may warrant consideration within the impact 

area even when the immediate downwash effects do not. Therefore, any decision 

by the applicant to exclude the effects of downwash for a particular source 

should be justified in the application, and approved by the permitting agency. 

For a PSD increment analysis, an estimate of the amount of increment 

consumed by existing point sources generally is based on increases in actual 

emissions occurring since the minor source baseline date. The exception, of 

course, is for major stationary sources whose actual emissions have increased 

(as a result of construction) before the minor source baseline date but on or 

after the major source baseline date. For any increment-consuming (or 

increment-expanding) emissions unit, the actual emissions limit, operating 

level, and operating factor may all be determined from source records and 

other information (e.g., State emissions files), when available, reflecting 

actual source operation. For the annual averaging period, the change in the 

actual emissions rate should be calculated as the difference between: 

! the current average actual emissions rate, and 

! the average actual emissions rate as of the minor source baseline 

date (or major source baseline date for major stationary sources). 

C.48 
D R A F T 

OCTOBER 1990 

In each case, the average rate is calculated as the average over previous 

2-year period (unless the permitting agency determines that a different time 

period is more representative of normal source operation). 

For each short-term averaging period (24 hours and less), the change in 

the actual emissions rate for the particular averaging period is calculated as 

the difference between: 

! the current maximum actual emissions rate, and 

! the maximum actual emissions rate as of the minor source baseline 

date (or major source baseline date for applicable major 

stationary sources undergoing consturction before the minor source 

baseline date). 

In each case, the maximum rate is the highest occurrence for that averaging 

period during the previous 2 years of operation. 

Where appropriate, air quality impacts from fugitive emissions and 

building downwash are also taken into account for the PSD increment analysis. 

Of course, they would only be considered when applicable to incrementconsuming emissions. 

If the change in the actual emissions rate at a particular source 

involves a change in stack parameters (e.g., stack height, gas exit 

temperature, etc.) then the stack parameters and emissions rates associated 

with both the baseline case and the current situation must be used as input to 

the dispersion model. To determine increment consumption (or expansion) for 

such a source, the baseline case emissions are input to the model as negative 

emissions, along with the baseline stack parameters. In the same model run, 

the current case for the same source is modeled as the total current emissions 

associated with the current stack parameters. This procedure effectively 

calculates, for each receptor and for each averaging time, the difference 

between the baseline concentration and the current concentration (i.e., the 

amount of increment consumed by the source). 

Emissions changes associated with area and mobile source growth 

occurring since the minor source baseline date are also accounted for in the 

C.49 
D R A F T 

OCTOBER 1990 

increment analysis by modeling. In many cases state emission files will 

contain information on area source emissions or such information may be 

available from EPA's AIRS-NEDS emissions data base. In the absence of this 

information, the applicant should use procedures adopted for developing state 

area source emission inventories. The EPA documents outlining procedures for 

area source inventory development should be reviewed. 

Mobile source emissions are usually calculated by applying mobile source 

emissions factors to transportation data such as vehicle miles travelled 

(VMT), trip ends, vehicle fleet characteristics, etc. Data are also required 

on the spatial arrangement of the VMT within the area being modeled. Mobile 

source emissions factors are available for various vehicle types and 

conditions from an EPA emissions factor model entitled MOBILE4. The MOBILE4 

users manual [Reference 20] should be used in developing inputs for executing 

this model. The permitting agency can be of assistance in obtaining the 

needed mobile source emissions data. Oftentimes, these data are compiled by 

the permitting agency acting in concert with the local planning agency or 

transportation department. 

For both area source and mobile source emissions, the applicant will 

need to collect data for the minor source baseline date and the current 

situation. Data from these two dates will be required to calculate the 

increment-affecting emission changes since the minor source baseline date. 

C.50 
D R A F T 

OCTOBER 1990 

IV.E THE COMPLIANCE DEMONSTRATION 

An applicant for a PSD permit must demonstrate that the proposed source 

will not cause or contribute to air pollution in violation of any NAAQS or PSD 

increment. This compliance demonstration, for each affected pollutant, must 

result in one of the following: 

! The proposed new source or modification will not cause a 

significant ambient impact anywhere. 

If the significant net emissions increase from a proposed source would 

not result in a significant ambient impact anywhere, the applicant is usually 

not required to go beyond a preliminary analysis in order to make the 

necessary showing of compliance for a particular pollutant. In determining 

the ambient impact for a pollutant, the highest estimated ambient 

concentration of that pollutant for each applicable averaging time is used. 

! The proposed new source or modification, in conjunction with 

existing sources, will not cause or contribute to a violation of 

any NAAQS or PSD increment. 

In general, compliance is determined by comparing the predicted ground 

level concentrations (based on the full impact analysis and existing air 

quality data) at each model receptor to the applicable NAAQS and PSD 

increments. If the predicted pollutant concentration increase over the 

baseline concentration is below the applicable increment, and the predicted 

total ground level concentrations are below the NAAQS, then the applicant has 

successfully demonstrated compliance. 

The modeled concentrations which should be used to determine compliance 

with any NAAQS and PSD increment depend on 1) the type of standard, i.e., 

deterministic or statistical, 2) the available length of record of 

meteorological data, and 3) the averaginign time of the standard being 

analyzed. For example, when the analysis is based on 5 years of National 

Weather Service meteorological data, the following estimates should be used: 

C.51 
D R A F T 

OCTOBER 1990 

! for deterministically based standards (e.g., SO2), the highest, 

second-highest short term estimate and the highest annual 

estimate; and 

! for statistically based standards (e.g., PM-10), the highest, 

sixth-highest estimate and highest 5-year average estimate. 

Further guidance to determine the appropriate estimates to use for the 

compliance determination is found in Chapter 8 of the Modeling Guideline for 

SO2, TSP, lead, NO2, and CO; and in EPA's PM-10 SIP Development Guideline [Reference 

21] for PM-10. 

When a violation of any NAAQS or increment is predicted at one or more 

receptors in the impact area, the applicant can determine whether the net 

emissions increase from the proposed source will result in a significant 

ambient impact at the point (receptor) of each predicted violation, and at the 

time the violation is predicted to occur. The source will not be considered 

to cause or contribute to the violation if its own impact is not significant 

at any violating receptor at the time of each predicted violation. In such a 

case, the permitting agency, upon verification of the demonstration, may 

approve the permit. However, the agency must also take remedial action 

through applicable provisions of the state implementation plan to address the 

predicted violation(s). 

! The proposed new source or modification, in conjunction with 

existing sources, will cause or contribute to a violation, but 

will secure sufficient emissions reductions to offset its adverse 

air quality impact. 

If the applicant cannot demonstrate that only insignificant ambient 

impacts would occur at violating receptors (at the time of the predicted 

violation), then other measures are needed before a permit can be issued. 

Somewhat different procedures apply to NAAQS violations than to PSD increment 

violations. For a NAAQS violation to which an applicant contributes 

significantly, a PSD permit may be granted only if sufficient emissions 

reductions are obtained to compensate for the adverse ambient impacts caused 

by the proposed source. Emissions reductions are considered to compensate for 

the proposed source's adverse impact when, at a minimum, (1) the modeled net 

C.52 
D R A F T 

OCTOBER 1990 

concentration, resulting from the proposed emissions increase and the 

federally enforceable emissions reduction, is less than the applicable 

significant ambient impact level at each affected receptor, and (2) no new 

violations will occur. Moreover, such emissions reductions must be made 

federally enforceable in order to be acceptable for providing the air quality 

offset. States may adopt procedures pursuant to federal regulations at 

40 CFR 51.165(b) to enable the permitting of sources whose emissions would 

cause or contribute to a NAAQS violation anywhere. The applicant should 

determine what specific provisions exist within the State program to deal with 

this type of situation. 

In situations where a proposed source would cause or contribute to a PSD 

increment violation, a PSD permit cannot be issued until the increment 

violation is entirely corrected. Thus, when the proposed source would cause a 

new increment violation, the applicant must obtain emissions reductions that 

are sufficient to offset enough of the source's ambient impact to avoid the 

violation. In an area where an increment violation already exists, and the 

proposed source would significantly impact that violation, emissions 

reductions must not only offset the source's adverse ambient impact, but must 

be sufficient to alleviate the PSD increment violation, as well. 

C.53 
D R A F T 

OCTOBER 1990 

V. AIR QUALITY ANALYSIS -- EXAMPLE 

This section presents a hypothetical example of an air quality analysis 

for a proposed new PSD source. In reality, no two analyses are alike, so an 

example that covers all modeling scenarios is not possible to present. 

However, this example illustrates several significant elements of the air 

quality analysis, using the procedures and information set forth in this 

chapter. 

An applicant is proposing to construct a new coal-fired, steam electric 

generating station. Coal will be supplied by railroad from a distant mine. 

The coal-fired plant is a new major source which has the potential to emit 

significant amounts of SO2, PM (particulate matter emissions and PM-10 

emissions), NOx, and CO. Consequently, an air quality analysis must be 

carried out for each of these pollutants. In this analysis, the applicant is 

required to demonstrate compliance with respect to -

! the NAAQS for SO2, PM-10, NO2, and CO, and 

! the PSD increments for SO2, TSP, and NO2. 

V.A DETERMINING THE IMPACT AREA 

The first step in the air quality analysis is to estimate the ambient 

impacts caused by the proposed new source itself. This preliminary analysis 

establishes the impact area for each pollutant emitted in significant amounts, 

and for each averaging period. The largest impact area for each pollutant is 

then selected as the impact area to be used in the full impact analysis. 

To begin, the applicant prepares a modeling protocol describing the 

modeling techniques and data bases that will be applied in the preliminary 

analysis. These modeling procedures are reviewed in advance by the permitting 

agency and are determined to be in accordance with the procedures described in 

the Modeling Guideline and the stack height regulations. 

C.54 
D R A F T 

OCTOBER 1990 

Several pollutant-emitting activities (i.e., emissions units) at the 

source will emit pollutants subject to the air quality analysis. The two main 

boilers emit particulate matter (i.e., particulate matter emissions and PM-10 

emissions), SO2, NOx, and CO. A standby auxiliary boiler also emits these 

pollutants, but will only be permitted to operate when the main boilers are 

not operating. 

Particulate matter emissions and PM-10 emissions will also occur at the 

coal-handling operations and the limestone preparation process for the flue 

gas desulfurization (FGD) system. Emissions units associated with coal and 

limestone handling include: 

! Point sources--the coal car dump, the fly ash silos, and the three 

coal baghouse collectors; 

! Area sources--the active and the inactive coal storage piles and 

the limestone storage pile; and 

! Line sources--the coal and limestone conveying operation. 

The emissions from all of the emissions units at the proposed source are 

then modeled to estimate the source's area of significant impact (impact area) 

for each pollutant. The results of the preliminary analysis indicate that 

significant ambient concentrations of NO2 and SO2 will occur out to distances 

of 32 and 50 kilometers, respectively, from the proposed source. No 

significant concentrations of CO are predicted at any location outside the 

fenced-in property of the proposed source. Thus, an impact area is not 

defined for CO, and no further CO analysis is required. 

Particulate matter emissions from the coal-handling operations and the 

limestone preparation process result in significant ambient TSP concentrations 

out to a distance of 2.2 kilometers. However, particulate matter emissions 

from the boiler stacks will cause significant TSP concentrations for a 

distance of up to 10 kilometers. Since the boiler emissions of particulate 

matter are predominantly PM-10 emissions, the same impact area is used for 

both TSP and PM-10. 

C.55 
D R A F T 

OCTOBER 1990 

This preliminary analysis further indicates that pre-application 

monitoring data may be required for two of the criteria pollutants, SO2 and 

NO2, since the proposed new source will cause ambient concentrations exceeding 

the prescribed significant monitoring concentrations for these two pollutants 

(see Table C-3). Estimated concentrations of PM-10 are below the significant 

monitoring concentration. The permitting agency informs the applicant that 

the requirement for pre-application monitoring data will not be imposed with 

regard to PM-10. However, due to the fact that existing ambient 

concentrations of both SO2 and NO2 are known to exceed their respective 

significant monitoring concentrations, the applicant must address the preapplication monitoring data requirements for these pollutants. 

Before undertaking a site-specific monitoring program, the applicant 

investigates the availability of existing data that is representative of air 

quality in the area. The permitting agency indicates that an agency-operated 

SO2 network exists which it believes would provide representative data for the 

applicant's use. It remains for the applicant to demonstrate that the 

existing air quality data meet the EPA criteria for data sufficiency, 

representativeness, and quality as provided in the PSD Monitoring Guideline. 

The applicant proceeds to provide a demonstration which is approved by the 

permitting agency. For NO2, however, adequate data do not exist, and it is 

necessary for the applicant to take responsibility for collecting such data. 

The applicant consults with the permitting agency in order to develop a 

monitoring plan and subsequently undertakes a site-specific monitoring program 

for NO2. 

In this example, four intrastate counties are covered by the applicant's 

impact area. Each of these counties, shown in Figure C-7, is designated 

attainment for all affected pollutants. Consequently, a NAAQS and PSD 

C.56 
D R A F T

OCTOBER 1990

Proposed 

County A 

County B 

County C 

County D 

100 km 

Power Plant 

Figure I-C- 7. Counties W ithin 100 Kilometers of Proposed Source. 

C.57 
D R A F T 

OCTOBER 1990 

analysis must be completed in each county. With the exception of CO (for 

which no further analysis is required) the applicant proceeds with the full 

impact analysis for each affected pollutant. 

V.B DEVELOPING THE EMISSIONS INVENTORIES 

After the impact area has been determined, the applicant proceeds to 

develop the required emissions inventories. These inventories contain all of 

the source input data that will be used to perform the dispersion modeling for 

the required NAAQS and PSD increment analyses. The applicant contacts the 

permitting agency and requests a listing of all stationary sources within a 

100-kilometer radius of the proposed new source. This takes into account the 

50-kilometer impact area for SO2 (the largest of the defined impact areas) 

plus the requisite 50-kilometer annular area beyond that impact area. For NO2 

and particulate matter, the applicant needs only to consider the identified 

sources which fall within the specific screening areas for those two 

pollutants. 

Source input data (e.g., location, building dimensions, stack 

parameters, emissions factors) for the inventories are extracted from the 

permitting agency's air permit and emissions inventory files. Sources to 

consider for these inventories also include any that might have recently been 

issued a permit to operate, but are not yet in operation. However, in this 

case no such "existing" sources are identified. The following point sources 

are found to exist within the applicant's impact area and screening area: 

! Refinery A;

! Chemical Plant B;

! Petrochemical Complex C;

! Rock Crusher D;

! Refinery E;

! Gas Turbine Cogeneration Facility F; and

! Portland Cement Plant G.

C.58 
D R A F T 

OCTOBER 1990 

A diagram of the general location of these sources relative to the 

location proposed source is shown in Figure C-8. Because the Portland 

Cement Plant G is located 70 kilometers away from the proposed source, its 

impact is not considered in the NAAQS or PSD increment analyses for 

particulate matter. (The area of concern for particulate matter lies within 

60 kilometers of the proposed source.) In this example, the applicant first 

develops the NAAQS emissions inventory for SO2, particulate matter (PM-10), 

and NO2. 

V.B.1 THE NAAQS INVENTORY 

For each criteria pollutant undergoing review, the applicant (in 

conjunction with the permitting agency) determines which of the identified 

sources will be regarded as "nearby" sources and, therefore, must be 

explicitly modeled. Accordingly, the applicant classifies the candidate 

sources in the following way: 

Pollutant 

SO2 

NO2 

Particulate 

Nearby sources 

(explicitly model) 

Refinery A 

Chemical Plant B 

Petro. Complex C 

Refinery E 

Refinery A, 

Chemical Plant B 

Petro. Complex C 

Gas Turbines F 

Refinery A 

Matter (PM-10) Petro. Complex C 

Rock Crusher D 

Other Background Sources 

(non-modeled background) 

Port. Cement Plant G

Refinery E

Chemical Plant B

Refinery E

Gas Turbines F

For each nearby source, the applicant now must obtain emissions input 

data for the model to be used. As a conservative approach, emissions input 

data reflecting the maximum allowable emissions rate of each nearby source 

could be used in the modeling analysis. However, because of the relatively 

C.59 
D R A F T

OCTOBER 1990

Cogeneration Station F 

Refinery E 

Portland Cement Plant G 

Refinery A 

Chemical Plant B 

Rock Crusher D 

Petrochemical 

Complex C 

Proposed Power Plant 

SO 2 Impact Area (50 km.)

Figure C-8. Point Sources W ithin 100 Kilometers of Proposed Source. 

C.60 
D R A F T 

OCTOBER 1990 

high concentrations anticipated due to the clustering of sources A, B, C and 

D, the applicant decides to consider the actual operating factor for each of 

these sources for the annual averaging period, in accordance with Table C-5. 

For example, for SO2, the applicant may determine the actual operating factor 

for sources A, B, and C, because they are classified as nearby sources for SO2 

modeling purposes. On the other hand, the applicant chooses to use the 

maximum allowable emissions rate for Source E in order to save the time and 

resources involved with determining the actual operating factors for the 45 

individual NO2 emissions units comprising the source. If a more refined 

analysis is ultimately warranted, then the actual hours of operation can be 

obtained from Source E for the purposes of the annual averaging period. 

As another example, for particulate matter (PM-10), the applicant may 

determine the actual annual operating factor for sources A, C, and D, because 

they are nearby sources for PM-10 modeling purposes. Again, the applicant 

chooses to determine the actual hours of annual operation because of the 

relatively high concentrations anticipated due to the clustering of these 

particular sources. 

For each pollutant, the applicant must also determine if emissions from 

the sources that were not classified as nearby sources can be adequately 

represented by existing air quality data. In the case of SO2, for example, 

data from the existing State monitoring network will adequately measure 

Source G's ambient impact in the impact area. However, for PM-10, the 

monitored impacts of Source B cannot be separated from the impacts of the 

other sources (A, C, and D) within the proximity of Source B. The applicant 

therefore must model this source but is allowed to determine both the actual 

operating factor and the actual operating level to model the source's annual 

impact, in accordance with Table C-5. For the short-term (24-hour) analysis 

the applicant may use the actual operating level, but continuous operation 

must be used for the operating factor. The ambient impacts of Source E and 

Source F will be represented by ambient monitoring data. 

For the NO2 NAAQS inventory, the only source not classified as a nearby 

source is Refinery E. The applicant would have preferred to use ambient data 

C.61 
D R A F T 

OCTOBER 1990 

to represent the ambient impact of this source; however, adequate ambient NO2 

data is not available for the area. In order to avoid modeling this source 

with a refined model for NO2, the applicant initially agrees to use a 

screening technique recommended by the permitting agency to estimate the 

impacts of Source E. 

Air quality impacts caused by building downwash must be considered 

because several nearby sources (A, B, C, and E) have stacks that are less than 

GEP stack height. In consultation with the permitting agency, the applicant 

is instructed to consider downwash for all four sources in the SO2 NAAQS 

analysis, because the sources are all located in the SO2 impact area. Also, 

after consdieration of the expected effect of downwash for other pollutants, 

the applicant is told that, for NO2, only Source C must be modeled for its air 

quality impacts due to downwash, and no modeling for downwash needs to be done 

with respect to particulate matter. 

The applicant gathers the necessary building dimension data for the 

NAAQS inventory. In this case, these data are available from the permitting 

agency through its permit files for sources A, B, and E. However, the 

applicant must contact Source C to obtain the data from that source. 

Fortunately, the manager of Source C readily provide the applicant this 

information for each of the 45 individual emission units. 

V.B.2 THE INCREMENT INVENTORY 

An increment inventory must be developed for SO2, particulate matter 

(TSP), and NO2. This inventory includes all of the applicable emissions input 

data from: 

! increment-consuming sources within the impact area; and 

! increment-consuming sources outside the impact area that affect 

increment consumption in the impact area. 

In considering emissions changes occurring at any of the major stationary 

sources identified earlier (see Figure C-8), the applicant must consider 

actual emissions changes resulting from a physical change or a change in the 

C.62 
D R A F T 

OCTOBER 1990 

method of operation since the major source baseline date, and any actual 

emissions changes since the applicable minor source baseline date. To 

identify those sources (and emissions) that consume PSD increment, the 

applicant should request information from the permitting agency concerning the 

baseline area and all baseline dates (including the existence of any prior 

minor source baseline dates) for each applicable pollutant. 

A review of previous PSD applications within the total area of concern 

reveals that minor source baseline dates for both SO2 and TSP have already be 

established in Counties A and B. For NO2, the minor source baseline date has 

already been established in County C. A summary of the relevant baseline 

dates for each pollutant in these three counties is shown in Table C-6. The 

proposed source will, however, establish the minor source baseline date in 

Counties C and D for SO2 and TSP, and in Counties A, B and D for NO2. 

For SO2, the increment-consuming sources deemed to contribute to 

increment consumption in the impact area are sources A, B, C and E. Source B 

underwent a major modification which established the minor source baseline 

date (April 21, 1984). The actual emissions increase resulting from that 

physical change is used in the increment analysis. Source A underwent a major 

modification and Source E increased its hours of operation after the minor 

source baseline date. The actual emissions increases resulting from both of 

these changes are used in the increment analysis, as well. Finally, Source C 

received a permit to add a new unit, but the new unit is not yet operational. 

Consequently, the applicant must use the potential emissions increase 

resulting from that new unit to model the amount of increment consumed. The 

existing units at Source C do not affect the increments because no actual 

emissions changes have occurred since the April 21, 1984 minor source baseline 

C.63 
D R A F T 

OCTOBER 1990 

TABLE C-6. EXISTING BASELINE DATES FOR SO2, TSP, 

AND NO2 FOR EXAMPLE PSD INCREMENT ANALYSIS 

Major Source Minor Source Affected 

Pollutant Baseline Date Baseline Date Counties 

_____________________________________________________________________________ 

Sulfur dioxide January 6, 1975 April 21, 1984 A and B 

Particulate Matter 

(TSP) January 6, 1975 March 14, 1985 A and B 

Nitrogen Dioxide February 8, 1988 June 8, 1988 C 

C.64 
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OCTOBER 1990 

date. Building dimensions data are needed in the increment inventory for 

nearby sources A, B, and E because each has increment-consuming emissions 

which are subject to downwash problems. No building dimensions data are 

needed for Source C, however, because only the emissions from the newlypermitted unit consume increment and the stack built for that unit was 

designed and constructed at GEP stack height. 

For NO2, only the gas turbines located at Cogeneration Station F have 

emissions which affect the increment. The PSD permit application for the 

construction of these turbines established the minor source baseline date 

for NO2 (June 8, 1988). Of course, all construction-based actual emissions 

changes in NOx occurring after the major source baseline date for NO2 

(February 8, 1988), at any major stationary source affect increment. However, 

no such emissions changes were discovered at the other existing sources in the 

area. Thus, only the actual emissions increase resulting from the gas 

turbines is included in the NO2 increment inventory. 

For TSP, sources A, B, C, and E are found to have units whose emissions 

may affect the TSP increment in the impact area. Source A established the 

minor source baseline date with a PSD permit application to modify its 

existing facility. Source B (which established the minor source baseline date 

for SO2) experienced an insignificant increase in particulate matter emissions 

due to a modification prior to the minor source baseline date for particulate 

matter (March 14, 1985). Even though the emissions increase did not exceed 

the significant emissions rate for particulate matter emissions (i.e., 25 tons 

per year), increment is consumed by the actual increase nonetheless, because 

the actual emissions increase resulted from construction (i.e., a physical 

change or a change in the method of operation) at a major stationary source 

occurring after the major source baseline date for particulate matter. The 

applicant uses the allowable increase as a conservative estimate of the actual 

emissions increase. As mentioned previously, Source C received a permit to 

construct, but the newly-permitted unit is not yet in operation. Therefore, 

the applicant must use the potential emissions to model the amount of TSP 

increment consumed by that new unit. 

C.65 
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OCTOBER 1990 

Finally, Source E's actual emissions increase resulting from an increase 

in its hours of operation must be considered in the increment analysis. This 

source is located far enough outside the impact area that its effects on 

increment consumption in the impact area are estimated with a screening 

technique. Based on the conservative results, the permitting agency 

determines that the source's emissions increase will not affect the amount of 

increment consumed in the impact area. 

In compiling the increment inventory, increment-consuming TSP and SO2 

emissions occurring at minor and area sources located in Counties A and B must 

be considered. Also, increment-consuming NOx emissions occurring at minor, 

area, and mobile sources located in County C must be considered. For this 

example, the applicant proposes that because of the low growth in population 

and vehicle miles traveled in the affected counties since the applicable minor 

source baseline dates, emissions from area and mobile sources will not affect 

increment (SO2, TSP, or NO2) consumed within the impact area and, therefore, 

do not need to be included in the increment inventory. After reviewing the 

documentation submitted by the applicant, the permitting agency approves the 

applicant's proposal not to include area and mobile source emissions in the 

increment inventory. 

V.C The Full Impact Analysis 

Using the source input data contained in the emissions inventories, the 

next step is to model existing source impacts for both the NAAQS and PSD 

increment analyses. The applicant's selection of models--ISCST, for shortterm modeling, and ISCLT, for long-term modeling--was made after conferring 

with the permitting agency and determining that the area within three 

kilometers of the proposed source is rural, the terrain is simple (noncomplex), and there is a potential for building downwash with some of the 

nearby sources. 

No on-site meteorological data are available. Therefore, the applicant 

evaluates the meteorological data collected at the National Weather Service 

station located at the regional airport. The applicant proposes the use of 

C.66 
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OCTOBER 1990 

5 years of hourly observations from 1984 to 1988 for input to the dispersion 

model, and the permitting agency approves their use for the modeling analyses. 

The applicant, in consultation with the permitting agency, determines 

that terrain in the vicinity is essentially flat, so that it is not necessary 

to model with receptor elevations. (Consultation with the reviewing agency 

about receptor elevations is important since significantly different 

concentration estimates may be obtained between flat terrain and rolling 

terrain modes.) 

A single-source model run for the auxiliary boiler shows that its 

estimated maximum ground-level concentrations of SO2 and NO2 will be less than 

the significant air quality impact levels for these two pollutants (see 

Table C-4). This boiler is modeled separately from the two main boilers 

because there will be a permit condition which restricts it from operating at 

the same time as the main boilers. For particulate matter, the auxiliary 

boiler's emissions are modeled together with the fugitive emissions from the 

proposed source to estimate maximum ground-level PM-10 concentrations. In 

this case, too, the resulting ambient concentrations are less than the 

significant ambient impact level for PM-10. Thus, operation of the auxiliary 

boiler would not be considered to contribute to violations of any NAAQS or PSD 

increment for SO2, particulate matter, or NO2. The auxiliary boiler is 

eliminated from further modeling consideration because it will not be 

permitted to operate when either of the main boilers is in operation. 

V.C.1 NAAQS ANALYSIS 

The next step is to estimate total ground-level concentrations. For the 

SO2 NAAQS compliance demonstration, the applicant selects a coarse receptor 

grid of one-kilometer grid spacing to identify the area(s) of high impact 

caused by the combined impact form the proposed new source and nearby sources. 

Through the coarse grid run, the applicant finds that the area of highest 

estimated concentrations will occur in the southwest quadrant. In order to 

determine the highest total concentrations, the applicant performs a second 

model run for the southwest quadrant using a 100-meter receptor fine-grid. 

C.67 
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OCTOBER 1990 

The appropriate concentrations from the fine-grid run is added to the 

monitored background concentrations (including Source G's impacts) to 

establish the total estimated SO2 concentrations for comparison against the 

NAAQS. The results show maximum SO2 concentrations of: 

! 600 μg/m3

, 3-hour average; 

! 155 μg/m3

, 24-hour average; and 

! 27 μg/m3

, annual average. 

Each of the estimated total impacts is within the concentrations allowed by 

the NAAQS. 

For the NO2 NAAQS analysis, the sources identified as "nearby" for NO2 

are modeled with the proposed new source in two steps, in the same way as for 

the SO2 analysis: first, using the coarse (1-kilometer) grid network and, 

second, using the fine (100-meter) grid network. Appropriate concentration 

estimates from these two modeling runs are then combined with the earlier 

screening results for Refinery E and the monitored background concentrations. 

The highest average annual concentration resulting from this approach is 85 

μg/m3

, which is less than the NO2 NAAQS of 100 μg/m3, annual average. 

For the PM-10 NAAQS analysis, the same two-step procedure (coarse and 

fine receptor grid networks) is used to locate the maximum estimated PM-10 

concentration. Recognizing that the PM-10 NAAQS is a statistically-based 

standard, the applicant identifies the sixth highest 24-hour concentration 

(based on 5 full years of 24-hour concentration estimates) for each receptor 

in the network. For the annual averaging time, the applicant averages the 

5 years of modeled PM-10 concentrations at each receptor to determine the 5-

year average concentration at each receptor. To these long- and short-term 

results the applicant then added the monitored background reflecting the 

impacts of sources E and F, as well as surrounding area and mobile source 

contributions. 

For the receptor network, the highest, sixth-highest 24-hour 

concentration is 127 μg/m3

, and the highest 5-year average concentration is 

C.68 
D R A F T 

OCTOBER 1990 

38 μg/m3. These concentrations are sufficient to demonstrate compliance with 

the PM-10 NAAQS. 

V.C.2 PSD Increment Analysis 

The applicant starts the increment analysis by modeling the incrementconsuming sources of SO2, including the proposed new source. As a 

conservative first attempt, a model run is made using the maximum allowable 

SO2 emissions changes resulting from each of the increment-consuming 

activities identified in the increment inventory. (Note that this is not the 

same as modeling the allowable emissions rate for each entire source.) Using 

a coarse (1-kilometer) receptor grid, the area downwind of the source 

conglomeration in the southwest quadrant was identified as the area where the 

maximum concentration increases have occurred. The modeling is repeated for 

the southwest quadrant using a fine (100-meter) receptor grid network. 

The results of the fine-grid model run show that, in the case of peak 

concentrations downwind of the southwest source conglomeration, the allowable 

SO2 increment will be violated at several receptors during the 24-hour 

averaging period. The violations include significant ambient impacts from the 

proposed power plant. Further examination reveals that Source A in the 

southwest quadrant is the large contributor to the receptors where the 

increment violations are predicted. The applicant therefore decides to refine 

the analysis by using actual emissions increases rather than allowable 

emissions increases where needed. 

It is learned, and the permitting agency verifies, that the incrementconsuming boiler at Source A has burned refinery gas rather than residual oil 

since start-up. Consequently, the actual emissions increase at Source A's 

boiler, based upon the use of refinery gas during the preceding 2 years, is 

substantially less than the allowable emissions increase assumed from the use 

of residual oil. Thus, the applicant models the actual emissions increase at 

Source A and the allowable emissions increase for the other modeled sources. 

C.69 
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OCTOBER 1990 

This time the modeling is repeated only for the critical time periods and 

receptors. 

The maximum predicted SO2 concentration increases over the baseline 

concentration are as follows: 

! 302 μg/m3

, 3-hour average; 

! 72 μg/m3

, 24-hour average; and 

! 12 μg/m3

, annual average. 

The revised modeling demonstrates compliance with the SO2 increments. Hence, 

no further SO2 modeling is required for the increment analysis. 

The full impact analysis for the NO2 increment is performed by modeling 

Source F--the sole existing NO2 increment-consuming source--and the proposed 

new source. The modeled estimates yield a maximum concentration increase of 

21 μg/m3

, annual average. This increase will not exceed the maximum allowable 

increase of 25 μg/m3 for NO2. 

With the SO2 and NO2 increment portions of the analysis complete, the 

only remaining part is for the particulate matter (TSP) increments. The 

applicant must consider the effects of the four existing increment-consuming 

sources (A, B, C, and E) in addition to ambient TSP concentrations caused by 

the proposed source (including the fugitive emissions). The total increase 

in TSP concentrations resulting from all of these sources is as follows: 

! 28 μg/m3

, 24-hour average; and 

! 13 μg/m3

, annual average. 

The results demonstrate that the proposed source will not cause any violations 

of the TSP increments. 

VI. BIBLIOGRAPHY 

1. U.S. Environmental Protection Agency. Ambient Monitoring Guidelines for 

Prevention of Significant Deterioration (PSD). Research Triangle Park, 

NC. EPA Publication No. EPA-450/4-87-007. May 1987. 

C.70 
D R A F T 

OCTOBER 1990 

2. U.S. Environmental Protection Agency. Guideline on Air Quality Models 

(Revised). Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. EPA Publication No. EPA-450/2-28-027R. 

July 1986. 

3. U.S. Environmental Protection Agency. On-Site Meteorological Programs 

Guidance for Regulatory Modeling Applications. Office of Air Quality 

Planning and Standards, Research Triangle Park, North Carolina. EPA 

Publication No. EPA-450/4-87-013. June 1987. 

4. Finkelstein, P.L., D.A. Mazzarella, T.J. Lockhart, W.J. King and J.H. 

White. Quality Assurance Handbook for Air Pollution Measurement 

Systems, Volume IV: Meteorological Measurements. U.S. Environmental 

Protection Agency, Research Triangle Park, NC. EPA Publication No. EPA600/4-82-060. 1983. 

5. U.S. Environmental Protection Agency. Procedures for Emission Inventory 

Preparation, Volume I: Emission Inventory Fundamentals. Research 

Triangle Park, NC. EPA Publication No. EPA-450/4-81-026a. 

September 1981. 

6. U.S. Environmental Protection Agency. Procedures for Emission Inventory 

Preparation, Volume II: Point Sources. Research Triangle Park, NC. 

EPA Publication No. EPA-450/4-81-026b. September 1981. 

7. U.S. Environmental Protection Agency. Procedures for Emission Inventory 

Preparation, Volume III: Area Sources. Research Triangle Park, NC. 

EPA Publication No. EPA-450/4-81-026c. September 1981. 

8. U.S. Environmental Protection Agency. Procedures for Emissions 

Inventory Preparation, Volume IV: Mobile Sources. Research Triangle 

Park, NC. EPA Publication No. EPA-450/4-81-026d. September 1981. 

9. U.S. Environmental Protection Agency. Procedures for Emissions 

Inventory Preparation, Volume V: Bibliography. Research Triangle 

Park, NC. EPA Publication No. EPA-450/4-81-026e. September 1981. 

10. U.S. Environmental Protection Agency. Example Emission Inventory 

Documentation For Post-1987 Ozone State Implementation Plans (SIP's). 

Office of Air Quality Planning and Standards, Research Triangle Park, 

NC. EPA Publication No. EPA-450/4-89-018. October 1989. 

11. U.S. Environmental Protection Agency. Procedures for Preparation of 

Emission Inventories for Volatile Organic Compounds, Volume I: Emission 

Inventory Requirements Photochemeical Air Simulation Models. Office of 

Air Quality Planning and Standards, NC. EPA Publication No. 

EPA-450/4-79-018. September 1979. 

12. U.S. Environmental Protection Agency. Screening Procedures for 

Estimating Air Quality Impact of Stationary Sources. [Draft for Public 

Comment.] Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. EPA Publication No. EPA 450/4-88-010. August 1988. 

C.71 
D R A F T 

OCTOBER 1990 

13. U.S. Environmental Protection Agency. Interim Procedures for Evaluation 

of Air Quality Models (Revised). Office of Air Quality Planning and 

Standards, Research Triangle Park, NC. EPA Publication No. 

EPA-450/4-84-023. September 1984. 

14. U.S. Environmental Protection Agency. Interim Procedures for Evaluation 

of Air Quality Models: Experience with Implementation. Office of Air 

Quality Planning and Standards, Research Triangle Park, NC. EPA 

Publication No. EPA-450/4-85-006. July 1985. 

15. U.S. Environmental Protection Agency. Guideline for Determination of 

Good Engineering Practice Stack Height (Technical Support Document for 

the Stack Height Regulations), Revised. Office of Air Quality Planning 

and Standards, Research Triangle Park, NC. EPA Publication No. 

EPA 450/4-80-023R. 1985. (NTIS No. PB 85-225241). 

16. U.S. Environmental Protection Agency. Guideline for Use of Fluid 

Modeling to Determine Good Engineering Practice (GEP) Stack Height. 

Office of Air Quality Planning and Standards, Research Triangle Park, 

NC. EPA Publication No. EPA-450/4-81-003. 1981. (NTIS No. 

PB 82-145327).

17. Lawson, Jr., R.E. and W.H. Snyder. Determination of Good Engineering 

Practice Stack Height: A Demonstration Study for a Power Plant. U.S. 

Environmental Protection Agency, Research Triangle Park, NC. EPA 

Publication No. EPA 600/3-83-024. 1983. (NTIS No. PB 83-207407). 

18. Snyder, W.H., and R.E. Lawson, Jr. Fluid Modeling Demonstration of Good 

Engineering-Practice Stack Height in Complex Terrain. U.S. 

Environmental Protection Agency, Research Triangle Park, NC. EPA 

Publication No. EPA-600/3-85-022. 1985. (NTIS No. PB 85-203107). 

19. U.S. Environmental Protection Agency. Workshop on Implementing the 

Stack Height Regulations (Revised). U.S. Environmental Protection 

Agency, Research Triangle Park, NC. 1985. 

20. U.S. Environmental Protection Agency. User's Guide to MOBILE4 (Mobile 

Source Emission Factor Model). Office of Mobile Sources, Ann Arbor, MI. 

EPA Publication No. EPA-AA-TEB-89-01. February 1989. 

21. U.S. Environmental Protection Agency. PM-10 SIP Development Guideline. 

Office of Air Quality Planning and Standards, Research Triangle Park, 

NC. EPA Publication No. EPA-450/2-86-001. June 1987. 

C.72 
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OCTOBER 1990 

VII. INDEX 

................. 1-12, 14-26, 29-38, 40-44, 46-71, 73-75 

actual emissions .......... 7, 8, 10, 11, 33, 47, 48, 63, 65, 66, 70 

air quality analysis ... 1-3, 16, 19, 20, 22-24, 26, 29, 36, 38, 41, 43, 53 

allowable ................... 10, 44, 60, 61, 65, 66, 69, 70 

ambient monitoring data ................... 2, 16, 18-20, 61 

area source .......................... 10, 34, 48, 49 

background .................. 3, 23, 31, 43, 46, 60, 68, 69 

compliance demonstration ..................... 50, 51, 68 

emissions inventory .................. 30, 32-35, 46, 58, 60 

GEP .......................... 11, 41-43, 62, 65, 73 

impact area ...... 18, 23, 26, 28-31, 33-35, 46, 51, 53-59, 61-63, 65, 66 

meteorological data .................. 16, 22, 37, 38, 51, 67 

mobile source ................. 10, 31, 34, 36, 48, 49, 66, 69 

modeling 2, 10, 12, 16, 18-24, 26, 29-31, 36, 37, 40-44, 46, 48, 50, 51, 53, 

58, 60-62, 67-70, 73, 74 

Modeling Guideline ........ 2, 22, 24, 30, 31, 36, 37, 41, 43, 50, 53 

Monitoring Guideline ................. 2, 18, 19, 21, 22, 55 

NAAQS . 1, 3-5, 18-21, 23, 24, 29-31, 36, 40, 41, 43, 44, 50, 51, 53, 55, 56, 

58, 60-62, 67-69 

nearby source ........................... 31, 60, 61 

net emissions increase ............... 1, 3, 16, 23, 26, 50, 51 

non-criteria pollutant ........................ 20, 24 

offset ................................ 51, 52 

offsets .................................. 21 

PSD increment 1, 3, 7, 29, 30, 33, 34, 36, 44, 47, 48, 50-52, 55, 58, 60, 63, 

64, 67, 69 

screening area ........................ 32, 34, 57-59 

secondary emissions ...................... 24, 31, 55, 58 

significant ambient impact ............ 24, 26, 27, 35, 50, 51, 67 

significant monitoring .................... 16-18, 21, 55 

stack height ............... 11, 41-43, 48, 53, 62, 65, 73, 74 

C.73 
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CHAPTER D 

ADDITIONAL IMPACTS ANALYSIS 

I. INTRODUCTION 

All PSD permit applicants must prepare an additional impacts analysis 

for each pollutant subject to regulation under the Act. This analysis 

assesses the impacts of air, ground and water pollution on soils, vegetation, 

and visibility caused by any increase in emissions of any regulated pollutant 

from the source or modification under review, and from associated growth. 

Other impact analysis requirements may also be imposed on a permit 

applicant under local, State or Federal laws which are outside the PSD 

permitting process. Receipt of a PSD permit does not relieve an applicant 

from the responsibility to comply fully with such requirements. For example, 

two Federal laws which may apply on occasion are the Endangered Species Act 

and the National Historic Preservation Act. These regulations may require 

additional analyses (although not as part of the PSD permit) if any federallylisted rare or endangered species, or any site that is included (or is 

eligible to be included) in the National Register of Historic Sites, are 

identified in the source's impact area. 

Although each applicant for a PSD permit must perform an additional 

impacts analysis, the depth of the analysis generally will depend on existing 

air quality, the quantity of emissions, and the sensitivity of local soils, 

vegetation, and visibility in the source's impact area. It is important that 

the analysis fully document all sources of information, underlying 

assumptions, and any agreements made as a part of the analysis. 

D.1 
D R A F T 

OCTOBER 1990 

Generally, small emissions increases in most areas will not have adverse 

impacts on soils, vegetation, or visibility. However, an additional impacts 

analysis still must be performed. Projected emissions from both the new 

source or modification and emissions from associated residential, commercial, 

or industrial growth are combined and modeled for the impacts assessment 

analysis. While this section offers applicants a general approach to an 

additional impacts analysis, the analysis does not lend itself to a "cookbook" 

approach. 

D.2 
D R A F T 

OCTOBER 1990 

II. ELEMENTS OF THE ADDITIONAL IMPACTS ANALYSIS 

The additional impacts analysis generally has three parts, as follows:

(1) growth;

(2) soil and vegetation impacts; and

(3) visibility impairment.

II.A. GROWTH ANALYSIS 

The elements of the growth analysis include: 

(1) a projection of the associated5

 industrial, commercial, and

residential source growth that will occur in the area due to the 

source; and 

(2) an estimate of the air emissions generated by the above associated 

industrial, commercial, and residential growth. 

First, the applicant needs to assess the availability of residential, 

commercial, and industrial services existing in the area. The next step is to 

predict how much new growth is likely to occur to support the source or 

modification under review. The amount of residential growth will depend on 

the size of the available work force, the number of new employees, and the 

availability of housing in the area. Industrial growth is growth in those 

industries providing goods and services, maintenance facilities,and other 

large industries necessary for the operation of the source or modification 

under review. Excluded from consideration as associated sources are mobile 

sources and temporary sources. 

Having completed this portrait of expected growth, the applicant then 

begins developing an estimate of the secondary air pollutant emissions which 

would likely result from this permanent residential, commercial, and 

5 Associated growth is growth that comes about as the result of the 

construction or modification of a source, but is not a part of that source. 

It does not include the growth projections addressed by 40 CFR 

51.166(n)(3)(ii) and 40 CFR 52.21(n)(2)(ii), which have been called nonassociated growth. Emissions attributable to associated growth are classified 

as secondary emissions. 

D.3 
D R A F T 

OCTOBER 1990 

industrial growth. The applicant should generate emissions estimates by 

consulting such sources as manufacturers specifications and guidelines, AP-42, 

other PSD applications, and comparisons with existing sources. 

The applicant next combines the secondary air pollutant emissions 

estimates for the associated growth with the estimates of emissions that are 

expected to be produced directly by the proposed source or modification. The 

combined estimate serves as the input to the air quality modeling analysis, 

and the result is a prediction of the ground-level concentration of pollutants 

generated by the source and any associated growth. 

II.B. AMBIENT AIR QUALITY ANALYSIS 

The ambient air quality analysis projects the air quality which will 

exist in the area of the proposed source or modification during construction 

and after it begins operation. The applicant first combines the air pollutant 

emissions estimates for the associated growth with the estimates of emissions 

from the proposed source or modification. Next, the projected emissions from 

other sources in the area which have been permitted (but are not yet in 

operation) are included as inputs to the modeling analysis. The applicant 

then models the combined emissions estimate and adds the modeling analysis 

results to the background air quality to arrive at an estimate of the total 

ground-level concentrations of pollutants which can be anticipated as a result 

of the construction and operation of the proposed source. 

II.C. SOILS AND VEGETATION ANALYSIS 

The analysis of soil and vegetation air pollution impacts should be 

based on an inventory of the soil and vegetation types found in the impact 

area. This inventory should include all vegetation with any commercial or 

recreational value, and may be available from conservation groups, State 

agencies, and universities. 

For most types of soil and vegetation, ambient concentrations of 

criteria pollutants below the secondary national ambient air quality standards 

D.4 
D R A F T 

OCTOBER 1990 

(NAAQS) will not result in harmful effects. However, there are sensitive 

vegetation species (e.g., soybeans and alfalfa) which may be harmed by longterm exposure to low ambient air concentrations of regulated pollutants for 

which are no NAAQS. For example, exposure of sensitive plant species to 0.5 

micrograms per cubic meter of fluorides (a regulated, non-criteria pollutant) 

for 30 days has resulted in significant foliar necrosis. 

Good references for applicants and reviewers alike include the EPA Air 

Quality Criteria Documents, a U.S. Department of the Interior document 

entitled Impacts of Coal-Fired Plants on Fish, Wildlife, and Their Habitats, 

and the U.S. Forest Service document, A Screening Procedure to Evaluate Air 

Pollution Effects on Class I Wilderness Areas. Another source of reference 

material is the National Park Service report, Air Quality in the National 

Parks, which lists numerous studies on the biological effects of air pollution 

on vegetation. 

II.D. VISIBILITY IMPAIRMENT ANALYSIS 

In the visibility impairment analysis, the applicant is especially 

concerned with impacts that occur within the area affected by applicable 

emissions. Note that the visibility analysis required here is distinct from 

the Class I area visibility analysis requirement. The suggested components of 

a good visibility impairment analysis are: 

D.5 
D R A F T 

OCTOBER 1990 

! a determination of the visual quality of the area, 

! an initial screening of emission sources to assess the possibility 

of visibility impairment, and 

! if warranted, a more in-depth analysis involving computer models. 

To successfully complete a visibility impairments analysis, the 

applicant is referred to an EPA document entitled Workbook for Estimating 

Visibility Impairment or its projected replacement, the Workbook for Plume 

Visual Impact Screening and Analysis. In this workbook, EPA outlines a 

screening procedure designed to expedite the analysis of emissions impacts on 

the visual quality of an area. The workbook was designed for Class I area 

impacts, but the outlined procedures are generally applicable to other areas 

as well. The following sections are a brief synopsis of the screening 

procedures. 

II.D.1. SCREENING PROCEDURES: LEVEL 1 

The Level 1 visibility screening analysis is a series of conservative 

calculations designed to identify those emission sources that have little 

potential of adversely affecting visibility. The VISCREEN model is recommended 

for this first level screen. Calculated values relating source emissions to 

visibility impacts are compared to a standardized screening value. Those 

sources with calculated values greater than the screening criteria are judged 

to have potential visibility impairments. If potential visibility impairments 

are indicated, then the Level 2 analysis is undertaken. 

II.D.2. SCREENING PROCEDURES: LEVEL 2 

The Level 2 screening procedure is similar to the Level 1 analysis in 

that its purpose is to estimate impacts during worst-case meteorological 

conditions; however, more specific information regarding the source, 

topography, regional visual range, and meteorological conditions is assumed to 

be available. The analysis may be performed with the aid of either hand 

D.6 
D R A F T 

OCTOBER 1990 

calculations, reference tables, and figures, or a computer-based visibility 

model called "PLUVUE II." 

II.D.3. SCREENING PROCEDURES: LEVEL 3 

If the Levels 1 and 2 screening analyses indicated the possibility of 

visibility impairment, a still more detailed analysis is undertaken in Level 3 

with the aid of the plume visibility model and meteorological and other 

regional data. The purpose of the Level 3 analysis is to provide an accurate 

description of the magnitude and frequency of occurrence of impact. 

The procedures for utilizing the plume visibility model are described in 

the document User's Manual for the Plume Visibility Model, which is available 

from EPA. 

II.E. CONCLUSIONS 

The additional impacts analysis consists of a growth analysis, a soil 

and vegetation analysis, and a visibility impairment analysis. After 

carefully examining all data on additional impacts, the reviewer must decide 

whether the analyses performed by a particular applicant are satisfactory. 

General criteria for determining the completeness and adequacy of the analyses 

may include the following: 

! whether the applicant has presented a clear and accurate portrait 

of the soils, vegetation, and visibility in the proposed impacted 

area; 

! whether the applicant has provided adequate documentation of the 

potential emissions impacts on soils, vegetation, and visibility; 

and 

! whether the data and conclusions are presented in a logical manner 

understandable by the affected community and interested public. 

D.7 
D R A F T 

OCTOBER 1990 

III. ADDITIONAL IMPACTS ANALYSIS EXAMPLE 

Sections D.1 and D.2 outlined, in general terms, the elements and 

considerations found in a successful additional impacts analysis. To 

demonstrate how this analytic process would be applied to a specific 

situation, a hypothetical case has been developed for a mine mouth power 

plant. This section will summarize how an additional impacts analysis would 

be performed on that facility. 

III.A. EXAMPLE BACKGROUND INFORMATION 

The mine mouth power plant consists of a power plant and an adjoining 

lignite mine, which serves as the plant's source of fuel. The plant is 

capable of generating 1,200 megawatts of power, which is expected to supply a 

utility grid (little is projected to be consumed locally). This project is 

located in a sparsely populated agricultural area in the southwestern United 

States. The population center closest to the plant is the town of 

Clarksville, population 2,500, which is located 20 kilometers from the plant 

site. The next significantly larger town is Milton, which is 130 kilometers 

away and has a population of 20,000. The nearest Class I area is more than 

200 kilometers away from the proposed construction. The applicant has 

determined that within the area under consideration there are no National or 

State forests, no areas which can be described as scenic vistas, and no points 

of special historical interest. 

The applicant has estimated that construction of the power plant and 

development of the mine would require an average work force of 450 people over 

a period of 36 months. After all construction is completed, about 150 workers 

will be needed to operate the facilities. 

D.8 
D R A F T 

OCTOBER 1990 

III.B. GROWTH ANALYSIS 

To perform a growth analysis of this project, the applicant began by 

projecting the growth associated with the operation of the project. 

III.B.1. WORK FORCE 

The applicant consulted the State employment office, local contractors, 

trade union officers, and other sources for information on labor capability 

and availability, and made the following determinations. 

Most of the 450 construction jobs available will be filled by workers 

commuting to the site, some from as far away as Milton. Some workers and 

their families will move to Clarksville for the duration of the construction. 

Of the permanent jobs associated with the project, about 100 will be filled by 

local workers. The remaining 50 permanent positions will be filled by 

nonlocal employees, most of whom are expected to relocate to the vicinity of 

Clarksville. 

III.B.2. HOUSING 

Contacts with local government housing authorities and realtors, and a 

survey of the classified advertisements in the local newspaper indicated that 

the predominant housing unit in the area is the single family house or mobile 

home, and the easy availability of mobile homes and lots provides a local 

capacity for quick expansion. Although there will be some emissions 

associated with the construction of new homes, these emissions will be 

temporary and, because of the limited numbers of new homes expected, are 

considered to be insignificant. 

D.9 
D R A F T 

OCTOBER 1990 

III.B.3. INDUSTRY 

Although new industrial jobs often lead to new support jobs as well 

(i.e., grocers, merchants, cleaners, etc.), the small number of new people 

brought into the community through employment at the plant is not expected to 

generate commercial growth. For example, the proposed source will not require 

an increase in small support industries (i.e., small foundries or rock 

crushing operations). 

As a result of the relatively self-contained nature of mine mouth plant 

operations, no related industrial growth is expected to accompany the 

operation of the plant. Emergency and full maintenance capacity is contained 

within the power-generating station. With no associated commercial or 

industrial growth projected, it then follows that there will be no growthrelated air pollution impacts. 

D.10 
D R A F T 

OCTOBER 1990 

III.C. SOILS AND VEGETATION 

In preparing a soils and vegetation analysis, the applicant acquired a 

list of the soil and vegetation types indigenous to the impact area. The 

vegetation is dominated by pine and hardwood trees consisting of loblolly 

pine, blackjack oak, southern red oak, and sweet gum. Smaller vegetation 

consists of sweetbay and holly. Small farms are found west of the forested 

area. The principal commercial crops grown in the area are soybeans, corn, 

okra, and peas. The soils range in texture from loamy sands to sandy clays. 

The principal soil is sandy loam consisting of 50 percent sand, 15 percent 

silt, and 35 percent clay. 

The applicant, through a literature search and contacts with the local 

universities and experts on local soil and vegetation, determined the 

sensitivity of the various soils and vegetation types to each of the 

applicable pollutants that will be emitted by the facility in significant 

amounts. The applicant then correlated this information with the estimates of 

pollutant concentrations calculated previously in the air quality modeling 

analysis. 

After comparing the predicted ambient air concentrations with soils and 

vegetation in the impact area, only soybeans proved to be potentially 

sensitive. A more careful examination of soybeans revealed that no adverse 

effects were expected at the low concentrations of pollutants predicted by the 

modeling analysis. The predicted sulfur dioxide (SO2) ambient air 

concentration is lower than the level at which major SO2 impacts on soybeans 

have been demonstrated (greater than 0.1 ppm for a 24-hour period). 

Fugitive emissions emitted from the mine and from coal pile storage will 

be deposited on both the soil and leaves of vegetation in the immediate area 

of the plant and mine. Minor leaf necrosis and lower photosynthetic activity 

is expected, and over a period of time the vegetation's community structure 

may change. However, this impact occurs only in an extremely limited, 

nonagricultural area very near the emissions site and therefore is not 

considered to be significant. 

D.11 
D R A F T 

OCTOBER 1990 

The potential impact of limestone preparation and storage also must be 

considered. High relative humidity may produce a crusting effect of the 

fugitive limestone emissions on nearby vegetation. However, because of BACT 

on limestone storage piles, this impact is slight and only occurs very near 

the power plant site. Thus, this impact is judged insignificant. 

D.12 
D R A F T 

OCTOBER 1990 

III.D. VISIBILITY ANALYSIS 

Next, the applicant performed a visibility analysis, beginning with a 

screening procedure similar to that outlined in the EPA document Workbook for 

Estimating Visibility Impairment. The screening procedure is divided into 

three levels. Each level represents a screening technique for an increasing 

possibility of visibility impairment. The applicant executed a Level 1 

analysis involving a series of conservative tests that permitted the analyst 

to eliminate sources having little potential for adverse or significant 

visibility impairment. The applicant performed these calculations for various 

distances from the power plant. In all cases, the results of the calculations 

were numerically below the standardized screening criteria. In preparing the 

suggested visual and aesthetic description of the area under review, the 

applicant noted the absence of scenic vistas. Therefore, the applicant 

concluded that no visibility impairment was expected to occur within the 

source impact area and that the Level 2 and Level 3 analyses were unnecessary. 

III.E. EXAMPLE CONCLUSIONS 

The applicant completed the additional impacts analysis by documenting 

every element of the analysis and preparing the report in straightforward, 

concise language. This step is important, because a primary intention of the 

PSD permit process is to generate public information regarding the potential 

impacts of pollutants emitted by proposed new sources or modifications on 

their impact areas. 

D.13 
D R A F T 

OCTOBER 1990 

NOTE: This example provides only the highlights of an additional impacts 

analysis for a hypothetical mine mouth power plant. An actual analysis would 

contain much more detail, and other types of facilities might produce more 

growth and more, or different, kinds of impacts. For example, the 

construction of a large manufacturing plant could easily generate air qualityrelated growth impacts, such as a large influx of workers into an area and the 

growth of associated industries. In addition, the existence of particularly 

sensitive forms of vegetation, the presence of Class I areas, and the 

existence of particular meteorological conditions would require an analysis of 

much greater scope. 

D.14 
D R A F T 

OCTOBER 1990 

IV. BIBLIOGRAPHY 

1. Dvorak, A.J., et al. Impacts of Coal-fired Power Plants on Fish, 

Wildlife, and their Habitats. Argonne National Laboratory. Argonne, 

Illinois. Fish and Wildlife Service Publication No. FWS/OBS-78/29. 

March 1978. 

2. A Screening Procedure to Evaluate Air Pollution Effects on Class I 

Wilderness Areas, U.S. Forest Service General Technical Report RM-168. 

January, 1989. 

3. Latimer, D.A. and R.G. Iveson. Workbook for Estimating Visibility 

Impairment. U.S. Environmental Protection Agency. Research Triangle 

Park, N.C. EPA Publication No. EPA-450/4-80-031. November, 1980. 

4. Air Quality in the National Parks. National Park Service. Natural 

Resources Report 88-1. July, 1988. 

5. Seigneur, C., et al. User's Manual for the Plume Visibility Model 

(Pluvue II). U.S. Environmental Protection Agency. Research Triangle 

Park, N.C. EPA Publication No. 600/8-84-005. February 1984. 

D.15 
D R A F T 

OCTOBER 1990 

CHAPTER E 

CLASS I AREA IMPACT ANALYSIS 

I. INTRODUCTION 

Class I areas are areas of special national or regional natural, scenic, 

recreational, or historic value for which the PSD regulations provide special 

protection. This section identifies Class I areas, describes the protection 

afforded them under the Clean Air Act (CAA), and discusses the procedures 

involved in preparing and reviewing a permit application for a proposed source 

with potential Class I area air quality impacts. 

E.1 
D R A F T 

OCTOBER 1990 

II. CLASS I AREAS AND THEIR PROTECTION 

Under the CAA, three kinds of Class I areas either have been, or may be, 

designated. These are: 

! mandatory Federal Class I areas; 

! Federal Class I areas; and 

! non-Federal Class I areas. 

Mandatory Federal Class I areas are those specified as Class I by the CAA on 

August 7, 1977, and include the following areas in existence on that date: 

! international parks; 

! national wilderness areas (including certain national wildlife 

refuges, national monuments and national seashores) which exceed 

5,000 acres in size; 

! national memorial parks which exceed 5,000 acres in size; and 

! national parks which exceed 6,000 acres in size. 

Mandatory Federal Class I areas, which may not be reclassified, are listed by 

State in Table E-1. They are managed either by the Forest Service (FS), 

National Park Service (NPS), or Fish and Wildlife Service (FWS). 

The States and Indian governing bodies have the authority to designate 

additional Class I areas. These Class I areas are not "mandatory" and may be 

reclassified if the State or Indian governing body chooses. States may 

reclassify either State or Federal lands as Class I, while Indian governing 

bodies may reclassify only lands within the exterior boundaries of their 

respective reservations. 

E.2 
D R A F T 

OCTOBER 1990 

TABLE E-1. MANDATORY CLASS I AREAS 

______________________________________________________________________________ 

State/Type/Area Managing Agency State/Type/Area Managing Agency 

Alabama 

National Wilderness Areas 

Sipsey 

Alaska 

National Parks 

Denali 

National Wilderness Areas 

Bering Sea 

Simeonof 

Tuxedni 

Arizona 

National Parks 

Grand Canyon 

Petrified Forest 

National Wilderness Areas 

Chiricahua Nat. Monu.

Chiricahua

Galiuro

Mazatzal

Mt. Baldy

Pine Mountain

Saguaro Nat. Monu.

Sierra Ancha

Superstition

Sycamore Canyon

Arkansas 

National Wilderness Areas 

Caney Creek 

Upper Buffalo 

California 

National Parks 

Kings Canyon 

Lassen Volcanic 

Redwood 

Sequoia 

Yosemite 

California - Continued 

National Wilderness Areas 

FS Agua Tibia 

Caribou 

Cucamonga 

Desolation 

NPS Dome Land 

Emigrant 

Hoover 

FWS John Muir 

FWS Joshua Tree 

FWS Kaiser 

Lava Beds 

Marble Mountain 

Minarets 

NPS Mokelumne 

NPS Pinnacles 

Point Reyes 

San Gabriel 

NPS San Gorgonio

FS San Jacinto

FS San Rafael

FS South Warner

FS Thousand Lakes

FS Ventana

NPS Yolla Bolly-Middle-Eel

FS

FS Colorado

FS National Parks

Mesa Verde 

Rocky Mountain 

FS National Wilderness Areas 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

NPS 

FS 

NPS 

FS 

FS 

FS 

NPS 

NPS 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

NPS 

NPS 

FS Black Canyon of the Gunn. NPS 

Eagles Nest 

Flat Tops 

Great Sand Dunes 

NPS La Garita 

NPS Maroon Bells Snowmass 

NPS Mount Zirkel 

NPS Rawah 

NPS Weminuche 

West Elk 

FS 

FS 

NPS 

FS 

FS 

FS 

FS 

FS 

FS 

E.3 
D R A F T 

OCTOBER 1990 

TABLE E-1. Continued 

______________________________________________________________________________ 

State/Type/Area Managing Agency State/Type/Area Managing Agency 

Florida 

National Parks 

Everglades NPS 

National Wilderness Areas 

Bradwell Bay FS 

Chassahowitzka FWS 

Saint Marks FWS 

Georgia 

National Wilderness Areas 

Cohutta FS 

Okefenokee FWS 

Wolf Island FWS 

Hawaii 

National Parks 

Haleakala NPS 

Hawaii Volcanoes NPS 

Idaho 

National Parks 

Yellowstone (See Wyoming) 

National Wilderness Areas 

Craters of the Moon NPS 

Hells Canyon (see Oregon) 

Sawtooth FS 

Selway-Bitterroot FS 

Kentucky 

National Parks 

Mammoth Cave NPS 

Louisiana 

National Wilderness Areas 

Breton FWS 

Maine 

National Parks 

Acadia NPS 

National Wilderness Areas 

Moosehorn FWS 

Michigan 

National Parks 

Isle Royale NPS 

National Wilderness Areas 

Seney FWS 

Minnesota 

National Parks 

Voyageurs NPS 

National Wilderness Areas 

Boundary Waters Canoe Ar. FS 

Missouri 

National Wilderness Areas 

Hercules-Glades 

Mingo 

Montana 

National Parks 

Glacier 

FS 

FWS 

NPS 

Yellowstone (See Wyoming) 

National Wilderness Areas 

Anaconda-Pintlar 

Bob Marshall 

Cabinet Mountains 

Gates of the Mountain 

Medicine Lake 

Mission Mountain 

Red Rock Lakes 

Scapegoat 

FS 

FS 

FS 

FS 

FWS 

FS 

FWS 

FS 

Selway-Bitterroot (see Idaho) 

U.L. Bend FWS 

Nevada 

National Wilderness Areas 

Jarbridge FS 

New Hampshire 

National Wilderness Areas 

Great Gulf FS 

Presidential Range-Dry R.FS 

E.4 
D R A F T 

OCTOBER 1990 

TABLE E-1. Continued 

______________________________________________________________________________ 

State/Type/Area Managing Agency State/Type/Area Managing Agency 

New Jersey 

National Wilderness Areas 

Brigantine 

New Mexico 

National Parks 

Carlsbad Caverns 

National Wilderness Areas 

Bandelier

Bosque del Apache

Gila

Pecos

Salt Creek

San Pedro Parks

Wheeler Peak

White Mountain

North Carolina 

National Parks 

FWS 

NPS 

NPS 

FWS 

FS 

FS 

FWS 

FS 

FS 

FS 

Oregon - Continued 

National Wilderness Areas 

Diamond Peak 

Eagle Cap 

Gearhart Mountain 

Hells Canyon 

Kalmiopsis 

Mountain Lakes 

Mount Hood 

Mount Jefferson 

Mount Washington 

Strawberry Mountain 

Three Sisters 

South Carolina 

National Wilderness Areas 

Cape Romain 

South Dakota 

National Parks 

Wind Cave 

National Wilderness Areas 

Badlands 

Tennessee 

National Parks 

Great Smoky Mountains 

National Wilderness Areas 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

FS 

FWS 

NPS 

NPS 

NPS 

Great Smoky Mountains (see Tennessee) 

National Wilderness Areas 

Joyce Kilmer-Slickrock FS 

Linville Gorge FS 

Shining Rock FS 

Swanquarter FWS 

North Dakota 

National Parks 

Theodore Roosevelt NPS 

National Wilderness Areas 

Lostwood FWS 

Oklahoma 

National Wilderness Areas 

Wichita Mountains FWS 

Oregon 

National Parks 

Crater Lake NPS 

Joyce Kilmer-Slickrock 

(see North Carolina) 

Texas 

National Parks 

Big Bend NPS 

Guadalupe Mountain NPS 

E.5 
D R A F T 

OCTOBER 1990 

TABLE E-1.* Continued 

______________________________________________________________________________ 

State/Type/Area Managing Agency State/Type/Area Managing Agency 

Utah 

National Parks 

Arches 

Bryce Canyon 

Canyonlands 

Capitol Reef 

Vermont 

National Wilderness Areas 

Lye Brook 

Virgin Islands 

National Parks 

Virgin Islands 

Virginia 

National Parks 

Shenandoah 

National Wilderness Areas 

James River Face 

Washington 

National Parks 

Mount Rainier 

North Cascades 

Olypmic 

National Wilderness Areas 

Alpine Lakes 

Glacier Peak 

Goat Rocks 

Mount Adams 

Pasayten 

NPS 

NPS 

NPS 

NPS 

FS 

NPS 

NPS 

FS 

NPS 

NPS 

NPS 

FS 

FS 

FS 

FS 

FS 

West Virginia 

National Wilderness Areas 

Dolly Sods 

Otter Creek 

Wisconsin 

National Wilderness Area 

Rainbow Lake 

Wyoming 

National Parks 

Grand Teton 

Yellowstone 

National Wilderness Areas 

Bridger 

Fitzpatrick 

North Absaroka 

Teton 

Washakie 

International Parks 

Roosevelt-Campobello 

FS 

FS 

FWS 

NPS 

NPS 

FS 

FS 

FS 

FS 

FS 

n/a 

E.6 
D R A F T 

OCTOBER 1990 

Any Federal lands a State so reclassifies are considered Federal Class I 

areas. In so far as these areas are not mandatory Federal Class II areas, 

these areas may be again reclassified at some later date. (there are as of 

the date of this manual, no State-designated Federal Class I areas.) However, 

in accordance with the CAA the following areas may be redesignated only as 

Class I or II. 

an area which as of August 7, 1977, exceeded 10,000 acres in size 

and was a national monument, a national primitive area, a national 

preserve, a national recreation area, a national wild and scenic 

river, a national wildlife refuge, a national lakeshore or 

seashore; and 

a national park or national wilderness area established after 

August 7, 1977, which exceeds 10,000 acres in size. 

Federal Class I areas are managed by the Forest Service (FS), the 

National Park Service (NPS), or the Fish and Wildlife Service (FWS). 

State or Indian lands reclassified as Class I are considered non-Federal 

Class I areas. Four Indian Reservations which are non-Federal Class I areas 

are the Northern Cheyenne, Fort Peck, and Flathead Indian Reservations in 

Montana, and the Spokane Indian Reservation in Washington. 

One way in which air quality degradation is limited in all Class I areas 

is by stringent limits defined by the Class I increments for sulfur dioxides, 

particulate matter [measured as total suspended particulate (TSP)], and 

nitrogen dioxide. As explained previously in Chapter C, Section II.A, PSD 

increments are the maximum increases in ambient pollutant concentrations 

allowed over the baseline concentrations. In addition, the FLM of each Class 

I area is charged with the affirmative responsibility to protect that area’s 

unique attributes, expressed generically as air quality related values 

(AQRV’s). The FLM, including the State or Indian governing body, where 

applicable, is responsible for defining specific AQRV’s for an area and for 

establishing the criteria to determine an adverse impact on the AQRV’s. 

E.7 
D R A F T 

OCTOBER 1990 

Congress intended the Class I increments to serve a special function in 

protecting the air quality and other unique attributes in Class I areas. In 

Class I areas, increments are a means of determining which party, i.e., the 

permit applicant or the FLM, has the burden of proof for demonstrating whether 

the proposed source would not cause or contribute to a Class I increment 

violation, the FLM may demonstrate to EPA, or the appropriate permitting 

authority, that the emissions from a proposed source would have an adverse 

impact on any AQRV’s established for a particular Class I area. 

If, on the other hand, the proposed source would cause or contribute to 

a Class I increment violation, the burden of proof is on the applicant to 

demonstrate to the FLM that the emissions from the source would have no 

adverse impact on the AQRV’s. These concepts are further described in Section 

III.d of this chapter. 

II.A. CLASS I INCREMENTS 

The Class I increments for total suspended particulate matter (TSP), 

SO2, and NO2 are listed in Table E-2. Increments are the maximum increases in 

ambient pollutant concentrations allowed over baseline concentrations. Thus, 

these increments should limit increases in ambient pollutant concentrations 

caused by new major sources or major modifications near Class I areas. 

Increment consumption analyses for Class I areas should include not only 

emissions from the proposed source, but also include increment-consuming 

emissions from other sources. 

E.8 
D R A F T

OCTOBER 1990

TABLE E-2. CLASS I INCREMENTS (ug/m3) 

Pollutant Annual 24-hour 3-hour 

______________________________________________________________________________ 

Sulfur dioxide 2 5 25

Particulate matter (TSP) 5 10 N/A

Nitrogen dioxide 2.5 N/A N/A 

E.9 
D R A F T 

OCTOBER 1990 

II.B. AIR QUALITY-RELATED VALUES (AQRV's) 

The AQRV's are those attributes of a Class I area that deterioration of 

air quality may adversely affect. For example, the Forest Service defines 

AQRV's as "features or properties of a Class I area that made it worthy of 

designation as a wilderness and that could be adversely affected by air 

pollution." Table E-3 presents an extensive (though not exhaustive) list of 

example AQRV's and the parameters that may be used to detect air pollutioncaused changes in them. Adverse impacts on AQRV's in Class I areas may occur 

even if pollutant concentrations do not exceed the Class I increments. 

Air quality-related values generally are expressed in broad terms. The 

impacts of increased pollutant levels on some AQRV's are assessed by measuring 

specific parameters that reflect the AQRV's status. For instance, the 

projected impact on the presence and vitality of certain species of animals or 

plants may indicate the impact of pollutants on AQRV's associated with species 

diversity or with the preservation of certain endangered species. Similarly, 

an AQRV associated with water quality may be measured by the pH of a water 

body or by the level of certain nutrients in the water. The AQRV's of various 

Class I areas differ, depending on the purpose and characteristics of a 

particular area and on assessments by the area's FLM. Also, the concentration 

at which a pollutant adversely impacts an AQRV can vary between Class I areas 

because the sensitivity of the same AQRV often varies between areas. 

When a proposed major source's or major modification's modeled 

emissions may affect a Class I area, the applicant analyzes the source's 

anticipated impact on visibility and provides the information needed to 

determine its effect on the area's other AQRV's. The FLM's have established 

criteria for determining what constitutes an "adverse" impact. For example, 

the NPS 

E.10 
D R A F T 

OCTOBER 1990 

TABLE E-3. EXAMPLES OF AIR QUALITY-RELATED VALUES AND POTENTIAL 

AIR POLLUTION-CAUSED CHANGES 

4444444444444444444444444444444444444444444444444444444444444444444444444444 

Air Quality Related Value Potential Air Pollution-Caused Changes 

____________________________________________________________________________ 

Flora and Fauna Growth, Mortality, Reproduction, 

Diversity, Visible Injury, Succession, 

Productivity, Abundance 

Water Total Alkalinity, Metals Concentration, 

Anion and Cation Concentration, pH, 

Dissolved Oxygen 

Visibility Contrast, Visual Range, Coloration 

Cultural-Archeological 

and Paleontological Decomposition Rate 

Odor Odor 

44444444444444444444444444444444444444444444444444444444444444444444444444444 

E.11 
D R A F T 

OCTOBER 1990 

defines an "adverse impact" as "any impact that: (1) diminishes the area's 

national significance; (2) impairs the structure or functioning of ecosystems; 

or (3) impairs the quality of the visitor experience." If an FLM determines, 

based on any information available, that a source will adversely impact AQRV's 

in a Class I area, the FLM may recommend that the reviewing agency deny 

issuance of the permit, even in cases where no applicable increments would be 

exceeded. 

II.C. FEDERAL LAND MANAGER 

The FLM of a Class I area has an affirmative responsibility to protect 

AQRV's for that area which may be adversely affected by cumulative ambient 

pollutant concentrations. The FLM is responsible for evaluating a source's 

projected impact on the AQRV's and recommending that the reviewing agency 

either approve or disapprove the source's permit application based on 

anticipated impacts. The FLM also may suggest changes or conditions on a 

permit. However, the reviewing agency makes the final decisions on permit 

issuance. The FLM also advises reviewing agencies and permit applicants about 

other FLM concerns, identifies AQRV's and assessment parameters for permit 

applicants, and makes ambient monitoring recommendations. 

The U.S. Departments of Interior (USDI) and Agriculture (USDA) are the 

FLM's responsible for protecting and enhancing AQRV's in Federal Class I 

areas. Those areas in which the USDI has authority are managed by the NPS and 

the FWS, while the USDA Forest Service separately reviews impacts on Federal 

Class I national wildernesses under its jurisdiction. The PSD regulations 

specify that the reviewing authority furnish written notice of any permit 

application for a proposed major stationary source or major modification, the 

emissions from which may affect a Class I area, to the FLM and the official 

charged with direct responsibility for management of any lands within the 

area. Although the Secretaries of Interior and Agriculture are the FLM's for 

Federal Class I areas, they have delegated permit review to specific elements 

within each department. In the USDI, the NPS Air Quality Division reviews PSD 

permits for both the NPS and FWS. Hence, for sources that may affect wildlife 

E.12 
D R A F T 

OCTOBER 1990 

refuges, applicants and reviewing agencies should contact and send 

correspondence to both the NPS and the wildlife refuge manager located at the 

refuge. Table E-4 summarizes the types of Federal Class I areas managed by 

each FLM. In the USDA, the Forest Service has delegated to its regional 

offices (listed in Table E-5) the responsibility for PSD permit application 

review. 

E.13 
D R A F T 

OCTOBER 1990 

TABLE E-4. FEDERAL LAND MANAGERS 

Federal Land Federal Class I Areas 

Manager Managed Address 

National Park National Memorial Parks Air Quality Division 

Service (USDI) National Monuments1 National Park Service - Air 

National Parks P.O. Box 25287 

National Seashores1 Denver, CO 80225-0287 

Fish and Wildlife National Wildlife Send to NPS, above, and 

Service (USDI) Refuges1 to Wildlife Refuge 

Manager. 2 

Forest Service National Wildernesses Send to Forest Service 

(USDA) Regional Office 

(See Table E-5) 

1

Only those national monuments, seashores, and wildlife refuges which also 

were designated wilderness areas as of August 7, 1977 are included as 

mandatory Federal Class I areas. 

2

The Wildlife Refuge Manager is located at or near each refuge. 

E.14 
D R A F T 

OCTOBER 1990 

TABLE E-5. USDA FOREST SERVICE REGIONAL OFFICES 

AND STATES THEY SERVE* 

4444444444444444444444444444444444444444444444444444444444444444444444444444 

USDA Forest Service

Northern Region

Federal Building

P.O. Box 7669

Missoula, MT 59807

[ID, ND, SD, MT]

USDA Forest Service

Southwestern Region

Federal Building

517 Gold Avenue, SW

Albuquerque, NM 87102

[AZ, NM]

USDA Forest Service

Pacific Southwest Region

630 Sansome Street

San Francisco, CA 94111

[CA, HI, GUAM, Trust Terr. of Pacific]

USDA Forest Service

Southern Region

1720 Peachtree Road, NW

Atlanta, GA 30367

[AL, AR, FL, GA, KY, LA, MS, NC, OK,

PR, SC, TN, TX, VI, VA]

USDA Forest Service

Alaska Region

P.O. Box 21628

Juneau, AK 99802-1628

[AK]

USDA Forest Service

Rocky Mountain Region

11177 West 8th Avenue

P.O. Box 25127

Lakewood, CO 80225

[CO, KS, NE, SD, WY]

USDA Forest Service

Intermountain Region

Federal Building

324 25th Street

Ogden, UT 84401

[ID, UT, NV, WY]

USDA Forest Service

Pacific Northwest Region

P.O. Box 3623

Portland, OR 97208

[WA, OR]

USDA Forest Service

Eastern Region

310 W. Wisconsin Avenue, Room 500

Milwaukee, WI 53203

[CT, DE, IL, IN, IA, ME, MD, MA, MI,

MN, MO, NH, NY, NJ, OH, PA, RI, VT,

WV, WI]

4444444444444444444444444444444444444444444444444444444444444444444444444444 

* Some Regions serve only part of a State. 

E.15 
D R A F T 

OCTOBER 1990 

III. CLASS I AREA IMPACT ANALYSIS AND REVIEW 

This section presents the procedures an applicant should follow in 

preparing an analysis of a proposed source's impact on air quality and AQRV's 

in Class I areas, including recommended informal steps. For each participant 

in the analysis - the permit applicant, the FLM, and the permit reviewing 

agency - the section summarizes their role and responsibilities. 

III.A. SOURCE APPLICABILITY 

If a proposed major source or major modification may affect a Class I 

area, the Federal PSD regulations require the reviewing authority to provide 

written notification of any such proposed source to the FLM (and the USDI and 

USDA officials delegated permit review responsibility). The meaning of the 

term "may affect" is interpreted by EPA policy to include all major sources or 

major modifications which propose to locate within 100 kilometers (km) of a 

Class I area. Also, if a major source proposing to locate at a distance 

greater than 100 km is of such size that the reviewing agency or FLM is 

concerned about potential emission impacts on a Class I area, the reviewing 

agency can ask the applicant to perform an analysis of the source's potential 

emissions impacts on the Class I area. This is because certain meteorological 

conditions, or the quantity or type of air emissions from large sources 

locating further than 100 km, may cause adverse impacts on a Class I area's. 

A reviewing agency should exclude no major new source or major modification 

from performing an analysis of the proposed source's impact if there is some 

potential for the source to affect a Class I area's. 

The EPA's policy requires, at a minimum, an AQRV impact analysis of any 

PSD source the emissions from which increase pollutant concentration by more 

than 1 μg/m3

 (24-hour average) in a Class I area. However, certain AQRV's may 

be sensitive to pollutant increases less than 1 μg/m3

. Also, some Class I 

areas may be approaching the threshold for effects by a particular pollutant 

on certain resources and consequently may be sensitive to even small increases 

in pollutant concentrations. For example, in some cases increases in sulfate 

concentration less than 1 μg/m3 may adversely impact visibility. Thus, an 

E.16 
D R A F T 

OCTOBER 1990 

increase of 1 μg/m3 should not absolutely determine whether an AQRV impact 

analysis is needed. The reviewing agency should consult the FLM to determine 

whether to require all the information necessary for a complete AQRV impact 

analysis of a proposed source. 

III.B. PRE-APPLICATION STAGE 

A pre-application meeting between the applicant, the FLM, and the 

reviewing agency to discuss the information required of the source is highly 

recommended. The applicant should contact the appropriate FLM as soon as 

plans are begun for a major new source or modification near a Class I area 

(i.e., generally within 100 km of the Class I area). A preapplication 

meeting, while not required by regulation, helps the permit applicant 

understand the data and analyses needed by the FLM. At this point, given 

preliminary information such as the source's location and the type and 

quantity of projected air emissions, the FLM can: 

! agree on which Class I areas are potentially affected by the 

source; 

! discuss AQRV's for each of the areas(s) and the indicators that 

may be used to measure the source's impact on those AQRV's; 

! advise the source about the scope of the analysis for determining 

whether the source potentially impacts the Class I area(s); 

! discuss which Class I area impact analyses the applicant should 

include in the permit application; and 

! discuss all pre-application monitoring in the Class I area that 

may be necessary to assess the current status of, and effects on, 

AQRV's (this monitoring usually is done by the applicant). 

E.17 
D R A F T 

OCTOBER 1990 

III.C. PREPARATION OF PERMIT APPLICATION 

For each proposed major new source or major modification that may affect 

a Class I area, the applicant is responsible for: 

! identifying all Class I areas within 100 km of the proposed source 

and any other Class I areas potentially affected; 

! performing all necessary Class I increment analyses (including any 

necessary cumulative impact analyses); 

! performing for each Class I area any preliminary analysis required 

by a reviewing agency to find whether the source may increase the 

ambient concentration of any pollutant by 1 μg/m3

 (24-hour 

average) or more; 

! performing for each Class I area an AQRV impact analysis for 

visibility; 

! providing all information necessary to conduct the AQRV impact 

analyses (including any necessary cumulative impact analyses); 

! performing any monitoring within the Class I area required by the 

reviewing agency; and 

! providing the reviewing agency with any additional relevant 

information the agency requests to "complete" the Class I area 

impacts analysis. 

By involving the FLM early in preparation of the Class I area analysis, the 

applicant can identify and address FLM concerns, avoiding delays later during 

permit review. 

The FLM is the AQRV expert for Class I areas. As such, the FLM can 

recommend to the applicant: 

! the AQRV's the applicant should address in the PSD permit 

application's Class I area impact analysis; 

! techniques for analyzing pollutant effects on AQRV's; 

! the criteria the FLM will use to determine whether the emissions 

from the proposed source would have an adverse impact on any AQRV; 

E.18 
D R A F T 

OCTOBER 1990 

! the pre-construction and post-construction AQRV monitoring the FLM 

will request that the reviewing agency require of the applicant; 

and 

! the monitoring, analysis, and quality assurance/quality control 

techniques the permit applicant should use in conducting the AQRV 

monitoring. 

The permit applicant and the FLM also should keep the reviewing agency 

apprised of all discussions concerning a proposed source. 

III.D. PERMIT APPLICATION REVIEW 

Where a reviewing agency anticipates that a proposed source may affect a 

Class I area, the reviewing agency is responsible for: 

! sending the FLM a copy of any advance notification that an 

applicant submits within 30 days of receiving such notification; 

! sending EPA a copy of each permit application and a copy of any 

action relating to the source; 

! sending the FLM a complete copy of all information relevant to the 

permit application, including the Class I visibility impacts 

analysis, within 30 days of receiving it and at least 60 days 

before any public hearing on the proposed source (the reviewing 

agency may wish to request that the applicant furnish 2 copies of 

the permit application); 

! providing the FLM a copy of the preliminary determination 

document; and 

! making a final determination whether construction should be 

approved, approved with conditions, or disapproved. 

A reviewing agency's policy regarding Class I area impact analyses can 

ensure FLM involvement as well as aid permit applicants. Some recommended 

policies for reviewing agencies are: 

! not considering a permit application complete until the FLM 

certifies that it is "complete" in the sense that it contains 

adequate information to assess adverse impacts on AQRV's; 

E.19 
D R A F T 

OCTOBER 1990 

! recommending that the applicant agree with the FLM (usually well 

before the application is received) on the type and scope of AQRV 

analyses to be done; 

! deferring to the FLM's adverse impact determination, i.e., denying 

permits based on FLM adverse impact certifications; and 

! where appropriate, incorporating permit conditions (e.g., 

monitoring program) which will assure protection of AQRV's. Such 

conditions may be most appropriate when the full extent of the 

AQRV impacts is uncertain. 

In addition, the reviewing agency can serve as an arbitrator and advisor in 

FLM/applicant agreements, especially at meetings and in drafting any written 

agreements. 

While the FLM's review of a permit application focuses on emissions 

impacts on visibility and other AQRV's, the FLM may comment on all other 

aspects of the permit application. The FLM should be given sufficient time 

(at least 30 days) to thoroughly perform or review a Class I area impact 

analysis and should receive a copy of the permit application either at the 

same time as the reviewing agency or as soon after the reviewing agency as 

possible. 

E.20 
D R A F T 

OCTOBER 1990 

The FLM can make one of two decisions on a permit application: (1) no 

adverse impacts; or (2) adverse impact based on any available information. 

Where a proposed major source or major modification adversely impacts a 

Class I area's AQRV's, the FLM can recommend that the reviewing agency deny 

the permit request based on the source's projected adverse impact on the 

area's AQRV's. However, rather than recommending denial at this point, the 

FLM may work with the reviewing agency to identify possible permit conditions 

that, if agreed to by the applicant, would make the source's effect on AQRV's 

acceptable. In cases where the permit application contains insufficient 

information for the FLM to determine AQRV impacts, the FLM should notify the 

reviewing agency that the application is incomplete. 

During the public comment period, the FLM can have two roles: 1) final 

determination on the source's impact on AQRV's with a formal recommendation to 

the reviewing agency; and 2) a commenter on other aspects of the permit 

application (best available control technology, modeling, etc.). Even for PSD 

permit applications where a proposed source's emissions clearly would not 

cause or contribute to exceedances of any Class I increment, the FLM may 

demonstrate to the reviewing agency that emissions from the proposed source or 

modification would adversely impact AQRV's of a mandatory Federal Class I area 

and recommend denial. Conversely, a permit applicant may demonstrate to the 

FLM that a proposed source's emissions do not adversely affect a mandatory 

Federal Class I area's AQRV's even though the modeled emissions would cause an 

exceedance of a Class I increment. Where a Class I increment is 

exceeded, the burden of proving no adverse impact on AQRV's is on the 

applicant. If the FLM concurs with this demonstration, the FLM may recommend 

approval of the permit to the reviewing agency and such a permit may be issued 

despite projected Class I increment exceedances. 

E.21 
D R A F T 

OCTOBER 1990 

IV. VISIBILITY IMPACT ANALYSIS AND REVIEW 

Visibility is singled out in the regulations for special protection and 

enhancement in accordance with the national goal of preventing any future, and 

remedying any existing, impairment of visibility in Class I areas caused by 

man-made air pollution. The visibility regulations for new source review 

(40 CFR 51.307 and 52.27) require visibility impact analysis in PSD areas for 

major new sources or major modifications that have the potential to impair 

visibility in any Federal Class I area. Information on screening models 

available for visibility analysis can be found in the manual "Workbook for 

Plume Visual Impact Screening and Analysis," EPA-450/4-88-015 (9/88). 

IV.A VISIBILITY ANALYSIS 

An "adverse impact on visibility" means visibility impairment which 

interferes with the management, protection, preservation, or enjoyment of a 

visitor's visual experience of the Federal Class I area. The FLM makes the 

determination of an adverse impact on a case-by-case basis taking into account 

the geographic extent, duration, intensity, frequency and time of visibility 

impairment, and how these factors correlate with (1) times of visitor use of 

the Federal Class I area, and (2) the frequency and timing of natural 

conditions that reduce visibility. Visibility perception research indicates 

that the visual effects of a change in air quality requires consideration of 

the features of the particular vista as well as what is in the air, and that 

measurement of visibility usually reflects the change in color, texture, and 

form of a scene. The reviewing agency may require visibility monitoring in 

any Federal Class I area near a proposed new major source or modification as 

the agency deems appropriate. 

An integral vista is a view perceived from within a mandatory Class I 

Federal area of a specific landmark or panorama located outside of the 

mandatory Class I Federal area. A visibility impact analysis is required for 

the integral vistas identified at 40 CFR 81, Subpart D, and for any other 

integral vista identified in a SIP. 

E.22 
D R A F T 

OCTOBER 1990 

IV.B PROCEDURAL REQUIREMENTS 

When the reviewing agency receives advance notification (e.g., early 

consultation with the source prior to submission of the application) of a 

permit application for a source that may affect visibility in a Federal 

Class I area, the agency must notify the appropriate FLM within 30 days of 

receiving the notification. The reviewing agency must, upon receiving a 

permit application for a source that may affect Federal Class I area 

visibility, notify the FLM in writing within 30 days of receiving it and at 

least 60 days prior to the public hearing on the permit application. This 

written notification must include an analysis of the source's anticipated 

impact on visibility in any Federal Class I area and all other information 

relevant to the permit application. The FLM has 30 days after receipt of the 

visibility impact analysis and other relevant information to submit to the 

reviewing agency a finding that the source will adversely impact visibility in 

a Federal Class I area. 

If the FLM determines that a proposed source will adversely impact 

visibility in a Federal Class I area and the reviewing agency concurs, the 

permit may not be issued. Where the reviewing agency does not agree with the 

FLM's finding of an adverse impact on visibility the agency must, in the 

notice of public hearing, either explain its decision or indicate where the 

explanation can be obtained. 

E.23 
D R A F T 

OCTOBER 1990 

V. BIBLIOGRAPHY 

1. Workbook for Plume Visual Impact Screening and Analysis. U.S. 

Environmental Protection Agency, Research Triangle Park, NC. 

EPA-450/4-88-015. September 1988. 

2. Workbook for Estimating Visibility Impairment. U.S. Environmental 

Protection Agency. Research Triangle Park, NC. EPA-450/4-80-031. 

November 1980. (NTIS No. PB 81-157885). 

3. USDA Forest Service (1987a) Air Resource Management Handbook, FSH 

2509.19. 

4. USDA Forest Service (1987b) Protocols for Establishing Current Physical, 

Chemical, and Biological Conditions of Remote Alpine and Subalpine 

Ecosystems, Rocky Mountain Forest and Range Experiment Station General 

Technical Report No. 46, Fort Collins, Colorado. 

5. USDA Forest Service (1987c). A Screening Procedure to Evaluate Air 

Pollution Effects on Class I Wilderness Areas. Rocky Mountain Forest 

and Range Experiment Station GTR 168. Fort Collins, Colorado. 

6. USDI (1982) "Internal Procedures for Determinations of Adverse Impact 

Under Section 165(d)(2)(C)(ii) and (iii) of the Clean Air Act" 47 FR 

30226, July 12, 1982. 

7. USDI National Park Service (1985) Permit Application Guidance for New 

Air Pollution Sources, Natural Resources Report Series 85-2, National 

Park Service, Air Quality Division, Permit Review and Technical Support 

Branch, Denver, Colorado. 

8. USDI National Park Service, Air Resource Management Manual, National 

Park Service, Air Quality Division, Permit Review and Technical Support 

Branch, Denver, Colorado. 

CHAPTER F

E.24 
D R A F T 

OCTOBER 1990 

CHAPTER F 

NONATTAINMENT AREA APPLICABILITY 

I. INTRODUCTION 

Many of the elements and procedures for source applicability under the 

nonattainment area NSR applicability provisions are similar to those of PSD 

applicability. The reader is therefore encouraged to become familiar with the 

terms, definitions and procedures from Part I.A., "PSD Applicability," in this 

manual. Important differences occur, however, in three key elements that are 

common to applicability determinations for new sources or modifications of 

existing sources located in attainment (PSD) and nonattainment areas. Those 

elements are: 

! Definition of "source,"

! Pollutants that must be evaluated (geographic effects); and

! Applicability thresholds

Consequently, this section will focus on these three elements in the context 

of a nonattaiment area NSR program. Note that the two latter elements, 

pollutants that must be evaluated for nonattainment NSR due to the location of 

the source in designated nonattainment areas (geographic effects) and 

applicability thresholds, are not independent. They will, therefore, be 

discussed in section III. 

F.1 
D R A F T 

OCTOBER 1990 

II. DEFINITION OF SOURCE 

The original NSR regulations required that a source be evaluated 

according to a dual source definition. On October 14, 1981, however, the EPA 

revised the new source review regulations to give a State the option of 

adopting a plantwide definition of stationary source in nonattainment areas, 

if the State's SIP did not rely on the more stringent "dual" definition in its 

attainment demonstration. Consequently, there are two stationary source 

definitions for nonattainment major source permitting: a "plantwide" 

definition and a "dual" source definition. The permit application must use, 

and be reviewed according to, whichever of the two definitions is used to 

define a stationary source in the applicable SIP. 

II.A. "PLANTWIDE" STATIONARY SOURCE DEFINITION 

The EPA definition of stationary source for nonattainment major source 

permitting uses the "plantwide" definition, which is the same as that used in 

PSD. A complete discussion of the concepts associated with the plantwide 

definition of source are presented in the PSD part of this manual (see 

section II). In essence, this definition provides that only physical or 

operation changes that result in a significant net emissions increase at the 

entire plant are considered a major modification to an existing major source 

(see sections II and III). 

For example, if an existing major source proposes to increase 

emissions by constructing a new emissions unit but plans to reduce 

actual emissions by the same amount at another emissions unit at 

the plant (assuming the reduction is federally enforceable and is 

the only contemporaneous and creditable emissions change at the 

source), then there would be no net increase in emissions at the 

plant and therefore no "major" modification to the stationary 

source. 

F.2 
D R A F T 

OCTOBER 1990 

II.B. "DUAL SOURCE" DEFINITION OF STATIONARY SOURCE 

The "dual" definition of stationary source defines the term stationary 

source as ". . . any building, structure, facility, or installation which 

emits or has the potential to emit any air pollutant subject to regulation 

under the Clean Air Act." Under this definition, the three terms building, 

structure, or facility are defined as a single term meaning all of the 

pollutant-emitting activities which belong to the same industrial grouping 

(i.e.,same two-digit SIC code), are located on one or more adjacent 

properties, and are under the control of the same owner or operator. The 

fourth term, installation, means an identifiable piece of process equipment. 

Therefore, a stationary source is both: 

! a building, structure, or facility (plantwide); and 

! an installation (individual piece of equipment). 

In other words, the "dual source" definition of stationary source treats 

each emissions unit as (1) a separate, independent stationary source, and (2) 

a component of the entire stationary source. 

For example, in the case of a power plant with three large boilers 

each emitting major amounts (i.e., >100 tpy) of NOx, each of the 

three boilers is an individual stationary source and all three 

boilers together constitute a stationary source. [Note that the 

power plant would be seen only as a single stationary source under 

the plantwide definition (all three boilers together as one 

stationary source)]. 

Consequently, under the dual source definition, the emissions from each 

physical or operational change at a plant are reviewed both with and without 

regard to reductions elsewhere at the plant. 

For example, a power plant is an existing major SO2 source in an 

SO2 nonattainment area. The power plant proposes to 1) install 

SO2 scrubbers on an existing boiler and 2) construct a new boiler 

at the same facility. Under the "plantwide" definition, the SO2 

reductions from the scrubber installation could be considered, 

along with other contemporaneous emissions changes at the plant 

and the new emissions increase of the new boiler to arrive at the 

source's net emission increase. This might result in a net 

F.3 
D R A F T 

OCTOBER 1990 

emissions change which would be below the SO2 significance level 

and the new boiler would "net" out of review as major 

modification. Under the dual source definition, however, the new 

boiler would be regarded as a individual source and would be 

subject to nonattainment NSR requirements if its potential 

emissions exceed the 100 tpy threshold. The emissions reduction 

from the scrubber could not be used to reduce net source 

emissions, but would instead be regarded as an SO2 emissions 

reduction from a separate source. 

The following examples are provided to further clarify the application 

of the dual source definition to determine if a modification to an existing 

major source is major and, therefore, subject to major source NSR permitting 

requirements. 

Example 1 An existing major stationary source is located in a 

x

definition applies, and has the following emissions units: 

nonattainment area for NO where the "dual source" 

Unit #1 with a potential to emit of 120 tpy of NOx 

Unit #2 with a potential to emit of 80 tpy of NOx 

Unit #3 with a potential to emit of 120 tpy of NOx 

Unit #4 with a potential to emit of 130 tpy of NOx 

Case 1 A modification planned for Unit #1 will result in an emissions 

increase of 45 tpy of NOx. The following emissions changes are 

contemporaneous with the proposed modification (all case examples 

assume that increases and decreases are creditable and will be 

made federally enforceable by the reviewing authority when the 

modification is permitted and will occur before construction of 

the modification): 

Unit #3 had an actual decrease of 10 tpy NOx 

Unit #4 had an actual decrease of 10 tpy NOx 

F.4 
D R A F T 

OCTOBER 1990 

Only contemporaneous emissions changes at Unit #1 are considered because Unit 

#1 is a major source of NOx by itself (i.e., potential emissions of NOx are 

greater than 100 tpy). The proposed increase at unit #1 of 45 tpy is greater 

than the 40 tpy 

NOx significant emissions rate since the emissions changes at the other 

units are not considered. Consequently, the proposed modification to 

Unit #1 is major under the dual source definition. 

Case 2 A modification to unit #2 is planned which will result in an emissions 

x . The following emissions changes are 

contemporaneous with the proposed modification: 

increase of 45 tpy of N0

Unit #1 had an actual decrease of 10 tpy 

Unit #3 had an actual decrease of 10 tpy 

Unit #2 is not a major stationary source in and of itself (i.e., 

its potential to emission of 80 tpy NOx is less than the 100 tpy 

major source threshold). Therefore, the major stationary source 

being modified is the whole plant and the emissions decreases at 

units #1 and #3 are considered in calculating the net emissions 

change at the source. The net emissions change of 25 tpy (the sum 

of +45, -10, and -10) at the source is less than the applicable 40 

tpy NOx significant emissions rate. Consequently, the proposed 

modification is not major. 

Case 3 A brand new unit #5 with a potential to emission of 45 tpy of NOx 

(note that potential emissions are less than the 100 tpy major 

source cutoff) is being added to the plant. The following 

emissions changes are contemporaneous with the proposed 

modification: 

Unit #1 had an actual decrease of 15 tpy 

Unit #2 had an actual increase of 25 tpy 

Unit #3 had an actual decrease of 20 tpy 

The new unit #5 is not a major stationary source in and of itself. 

Therefore, the major stationary source being modified is the whole 

plant and the emissions decreases at units #1, #2 and #3 are 

considered in calculating the net emissions change at the source. 

The net emissions change of 35 tpy (the sum of + 45, -15, +25, and 

-20) at the source is less than the applicable 40 tpy NOx 

significance level. Therefore, the proposed unit #5 is not a 

major modification. 

Case 4 A brand new unit #6 with a potential to emit of NO

being added to the plant. Because the new unit is, by itself, a 

x

x of 120 tpy is 

new major source (i.e., potential NO emissions are greater than 

F.5 
D R A F T 

OCTOBER 1990 

the 100 tpy major source cutoff), it cannot net out of review 

(using emissions reductions achieved at other emissions units at 

the plant) under the dual source definition. 

Example 2 An existing plant has only two emissions units. The units have a 

potential to emit of 25 tpy and 40 tpy. Here, any modification to 

the plant would have to have a potential to emit greater than 100 

tpy before the modification is major and subject to review. This 

is because neither of the two existing emissions units (at 25 tpy 

and 40 tpy), nor the total plant (at 65 tpy) are considered to be 

a major source (i.e., existing potential emissions do not exceed 

100 tpy). If, however, a third unit with potential emissions of 

110 tpy were added, that unit would be subject to review 

regardless of any emissions reductions from the two existing 

units. 

F.6 
D R A F T 

OCTOBER 1990 

III. POLLUTANTS ELIGIBLE FOR REVIEW AND APPLICABILITY THRESHOLDS 

III.A. POLLUTANTS ELIGIBLE FOR REVIEW (GEOGRAPHIC CONSIDERATIONS) 

A new source will be subject to nonattainment area preconstruction 

review requirements only if it will emit, or will have the potential to emit, 

in major amounts any criteria pollutant for which the area has been designated 

nonattainment. Similarly, only if a modification results in a significant 

increase (and significant net emissions increase under the plantwide source 

definition) of a pollutant, for which the source is major and for which the 

area is designated nonattainment, do nonattainment requirements apply. 

III.B. MAJOR SOURCE THRESHOLD 

For the purposes of nonattainment NSR, a major stationary source is 

! any stationary source which emits or has the potential 

to emit 100 tpy of any [criteria] pollutant subject to 

regulation under the CAA, or 

! any physical change or change in method of operation at an 

existing non-major source that constitutes a major 

stationary source by itself. 

Note that the 100 tpy threshold applies to all sources. The alternate 

250 tpy major source threshold [for PSD sources not classified under one of 

the 28 regulated source categories identified in Section 169 of the CAA (See 

Section I.A.2.3 and Table I-A-1) as being subject to a 100 tpy threshold] does 

not exist for nonattainment area sources. 

F.7 
D R A F T 

OCTOBER 1990 

III.C. MAJOR MODIFICATION THRESHOLDS 

Major modification thresholds for nonattainment areas are those same 

significant emissions values used to determine if a modification is major for 

PSD. Remember, however, that only criteria pollutants for which the location 

of the source has been designated nonattainment are eligible for evaluation. 

F.8 
D R A F T 

OCTOBER 1990 

IV. NONATTAINMENT APPLICABILITY EXAMPLE 

The following example illustrates the criteria presented in sections II 

and III above. 

Construction of a new plant with potential emissions of 500 tpy SO2, 50 

tpy VOC and 30 tpy NOx is proposed for an area designated nonattainment 

for SO2 and ozone and attainment for NOx. (Recall that VOC is the 

regulated surrogate pollutant for ozone.) The new plant is major for 

SO2 and therefore would be subject to nonattainment requirements for SO2 

only. Even though the VOC emissions are significant, the source is 

minor for VOC, and according to nonattainment regulations, is not 

subject to major source review. For purposes of PSD, the NOx emissions 

are neither major nor significant and are, therefore, not subject to PSD 

review. 

Two years after construction on the new plant commences, a modification 

of this plant is proposed that will result in an emissions increase of 

60 tpy VOC and 35 tpy NOx without any creditable contemporaneous 

emissions reductions. Again, the VOC emissions increase would not be 

subject, because the existing source is not major for VOC. The 

emissions increase of 35 tpy NOx is not significant and again, is not 

subject to PSD review. Note, however, that the plant would be 

considered a major source of VOC in subsequent applicability 

determinations. 

One year later, the plant proposes another increase in VOC emissions by 

75 tpy and NOx by another 45 tpy, again with no contemporaneous 

emissions reductions. Because the existing plant is now major for VOC 

and will experience a significant net emissions increase of that 

pollutant, it will be subject to nonattainment NSR for VOC. Because the 

source is major for a regulated pollutant (VOC) and will experience a 

significant net emissions increase of an attainment pollutant (NOx), it 

will also be subject to PSD review. 

F.9 
D R A F T 

OCTOBER 1990 

CHAPTER G 

NONATTAINMENT AREA REQUIREMENTS 

I. INTRODUCTION 

The preconstruction review requirements for major new sources or major 

modifications locating in designated nonattainment areas differ from 

prevention of significant deterioration (PSD) requirements. First, the 

emissions control requirement for nonattainment areas, lowest achievable 

emission rate (LAER), is defined differently than the best available control 

technology (BACT) emissions control requirement. Second, before construction 

of a nonattainment area source can be approved, the source must obtain 

emissions reductions (offsets) of the nonattainment pollutant from other 

sources which impact the same area as the proposed source. Third, the 

applicant must certify that all other sources owned by the applicant in the 

State are complying with all applicable requirements of the CAA, including all 

applicable requirements in the State implementation plan (SIP). Fourth, such 

sources impacting visibility in mandatory class I Federal areas must be 

reviewed by the appropriate Federal land manager (FLM). 

G.1 
D R A F T 

OCTOBER 1990 

II. LOWEST ACHIEVABLE EMISSION RATE (LAER) 

For major new sources and major modifications in nonattainment areas, 

LAER is the most stringent emission limitation derived from either of the 

following: 

! the most stringent emission limitation contained in the 

implementation plan of any State for such class or category of 

source; or 

! the most stringent emission limitation achieved in practice by 

such class or category of source. 

The most stringent emissions limitation contained in a SIP for a class or 

category of source must be considered LAER, unless (1) a more stringent 

emissions limitation has been achieved in practice, or (2) the SIP limitation 

is demonstrated by the applicant to be unachievable. By definition LAER can 

not be less stringent than any applicable new source performance standard 

(NSPS). 

There is, of course, a range of certainty in such a definition. The 

greatest certainty for a proposed LAER limit exists when that limit is 

actually being achieved by a source. However, a SIP limit, even if it has not 

yet been applied to a source, should be considered initially to be the product 

of careful investigation and, therefore, achievable. A SIP limit's 

credibility diminishes if a) no sources exist to which it applies; b) it is 

generally acknowledged that sources are unable to comply with the limit and 

the State is in the process of changing the limit; or c) the State has relaxed 

the original SIP limit. Case-by-case evaluations need to be made in these 

situations to determine the SIP limit's achievability. 

The same logic applies to SIP limits to which sources are subject but 

with which they are not in compliance. Noncompliance by a source with a SIP 

limit, even if it is the only source subject to that specific limit, does not 

automatically constitute a demonstration that the limit is unachievable. The 

specific reasons for noncompliance must be determined, and the ability of the 

source to comply assessed. However, such noncompliance may prove to be an 

G.2 
D R A F T 

OCTOBER 1990 

indication of nonachievability, so the achievability of such a SIP limitation 

should be carefully studied before it is used as the basis of a LAER 

determination. Some recommended sources of information for determining LAER 

are: 

! SIP limits for that particular class or category of sources; 

! preconstruction or operating permits issued in other 

nonattainment areas; and 

! the BACT/LAER Clearinghouse. 

Several technological considerations are involved in selecting LAER. 

The LAER is an emissions rate specific to each emissions unit including 

fugitive emissions sources. The emissions rate may result from a combination 

of emissions-limiting measures such as (1) a change in the raw material 

processed, (2) a process modification, and (3) add-on controls. The 

reviewing agency determines for each new source whether a single control 

measure is appropriate for LAER or whether a combination of emissions-limiting 

techniques should be considered. 

The reviewing agency also can require consideration of technology 

transfer. There are two types of potentially transferable control 

technologies: (1) gas stream controls, and (2) process controls and 

modifications. For the first type of transfer, classes or categories of 

sources to consider are those producing similar gas streams that could be 

controlled by the same or similar technology. For the second type of 

transfer, process similarity governs the decision. 

Unlike BACT, the LAER requirement does not consider economic, energy, or 

other environmental factors. A LAER is not considered achievable if the cost 

of control is so great that a major new source could not be built or operated. 

This applies generically, i.e., if no new plants could be built in that 

industry if emission limits were based on a particular control technology. If 

some other plant in the same (or comparable) industry uses that control 

technology, then such use constitutes evidence that the cost to the industry 

of that control is not prohibitive. Thus, for a new source, LAER costs are 

considered only to the degree that they reflect unusual circumstances which in 

G.3 
D R A F T 

OCTOBER 1990 

some manner differentiate the cost of control for that source from control 

costs for the rest of the industry. When discussing costs, therefore, 

applicants should compare control costs for the proposed source to the costs 

for sources already using that control. 

Where technically feasible, LAER generally is specified as both a 

numerical emissions limit (e.g., lb/MMBtu) and an emissions rate (e.g., 

lb/hr). Where numerical levels reflect assumptions about the performance of a 

control technology, the permit should specify both the numerical emissions 

rate and limitation and the control technology. In some cases where 

enforcement of a numerical limitation is judged to be technically infeasible, 

the permit may specify a design, operational, or equipment standard; however, 

such standards must be clearly enforceable, and the reviewing agency must 

still make an estimate of the resulting emissions for offset purposes. 

G.4 
D R A F T 

OCTOBER 1990 

III. EMISSIONS REDUCTIONS "OFFSETS" 

A major source or major modification planned in a nonattainment area 

must obtain emissions reductions as a condition for approval. These 

emissions reductions, generally obtained from existing sources located in the 

vicinity of a proposed source, must (1) offset the emissions increase from the 

new source or modification and (2) provide a net air quality benefit. The 

obvious purpose of acquiring offsetting emissions decreases is to allow an 

area to move towards attainment of the NAAQS while still allowing some 

industrial growth. Air quality improvement may not be realized if all 

emissions increases are not accounted for and if emissions offsets are not 

real. 

In evaluating a nonattainment NSR permit, the reviewing agency ensures 

that offsets are developed in accordance with the provisions of the applicable 

State or local nonattainment NSR rules. The following factors are considered 

in reviewing offsets : 

- the pollutants requiring offsets and amount of offset required; 

- the location of offsets relative to the proposed source; 

- the allowable sources for offsets; 

- the "baseline" for calculating emissions reduction credits; and 

- the enforceability of proposed offsets. 

Each of these factors should be discussed with the reviewing agency to ensure 

that the specific requirements of that agency are met. 

The offset requirement applies to each pollutant which triggered 

nonattainment NSR applicability. For example, a permit for a proposed 

petroleum refinery which will emit more than 100 tpy of sulfur dioxide (SO2) 

and particulate matter in a SO2 and particulate matter nonattainment area is 

required to obtain offsetting emissions reductions of SO2 and particulate 

matter. 

G.5 
D R A F T 

OCTOBER 1990 

III.A. CRITERIA FOR EVALUATING EMISSIONS OFFSETS 

Emissions reductions obtained to offset new source emissions in a 

nonattainment area must meet two important objectives: 

! ensure reasonable progress toward attainment of the NAAQS; and 

! provide a positive net air quality benefit in the area affected by 

the proposed source. 

States have latitude in determining what requirements offsets must meet to 

achieve these NAA program objectives. The EPA has set forth minimum 

considerations under the Interpretive Ruling (40 CFR 51, Appendix S). 

Acceptable offsets also must be creditable, quantifiable, federally 

enforceable, and permanent. 

While an emissions offset must always result in reasonable progress 

toward attainment of the NAAQS, it need not show that the area will attain the 

NAAQS. Therefore, the ratio of required emissions offset to the proposed 

source's emissions must be greater than one. The State determines what offset 

ratio is appropriate for a proposed source, taking into account the location 

of the offsets, i.e., how close the offsets are to the proposed source. 

To satisfy the criterion of a net air quality benefit does not mean that 

the applicant must show an air quality improvement at every location affected 

by the proposed source. Sources involved in an offset situation should impact 

air quality in the same general area as the proposed source, but the net air 

quality benefit test should be made "on balance" for the area affected by the 

new source. Generally, offsets for VOC's are acceptable if obtained from 

within the same air quality control region as the new source or from other 

nearby areas which may be contributing to an ozone nonattainment problem. For 

all pollutants, offsets should be located as close to the proposed site as 

possible. Applicants should always discuss the location of potential offsets 

with the reviewing agency to determine whether the offsets are acceptable. 

G.6 
D R A F T 

OCTOBER 1990 

III.B. AVAILABLE SOURCES OF OFFSETS 

In general, emissions reductions which have resulted from some other 

regulatory action are not available as offsets. For example, emissions 

reductions already required by a SIP cannot be counted as offsets. Also, 

sources subject to an NSPS in an area with less stringent SIP limits cannot 

use the difference between the SIP and NSPS limits as an offset. In addition, 

any emissions reductions already counted in major modification "netting" may 

not be used as offsets. However, emissions reductions validly "banked" under 

an approved SIP may be used as offsets. 

III.C. CALCULATION OF OFFSET BASELINE 

A critical element in the development or review of nonattainment area 

new source permits is to determine the appropriate baseline of the source from 

which offsetting emissions reductions are obtained. In most cases the SIP 

emissions limit in effect at the time that the permit application is filed may 

be used. This means that offsets will be based on emissions reductions below 

these SIP limits. Where there is no meaningful or applicable SIP requirement, 

the applicant be required to use actual emissions as the baseline emissions 

level. 

G.7 
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OCTOBER 1990 

III.D. ENFORCEABILITY OF PROPOSED OFFSETS 

The reviewing agency ensures that all offsets are federally enforceable. 

Offsets should be specifically stated and appear in the permit, regulation or 

other document which establishes a Federal enforceability requirement for the 

emissions reduction. External offsets must be established by conditions in 

the operating permit of the other plant or in a SIP revision. 

G.8 
D R A F T 

OCTOBER 1990 

IV. OTHER REQUIREMENTS 

An applicant proposing a major new source or major modification in a 

nonattainment area must certify that all major stationary sources owned or 

operated by the applicant (or by any entity controlling, controlled by, or 

under common control with the applicant) in that State are in compliance with 

all applicable emissions limitations and standards under the CAA. This 

includes all regulations in an EPA-approved SIP, including those more 

stringent than Federal requirements. 

Any major new source or major modification proposed for a nonattainment 

area that may impact visibility in a mandatory class I Federal area is subject 

to review by the appropriate Federal land manager (FLM). The reviewing agency 

for any nonattainment area should ensure that the FLM of such mandatory class 

I Federal area receives appropriate notification and copies of all documents 

relating to the permit application received by the agency. 

G.9 
D R A F T 

OCTOBER 1990 

CHAPTER H 

ELEMENTS OF AN EFFECTIVE PERMIT 

I. INTRODUCTION 

An effective permit is the legal tool used to establish all the source 

limitations deemed necessary by the reviewing agency during review of the 

permit application, as described in Parts I and II of this manual, and is the 

primary basis for enforcement of NSR requirements. In essence, the permit may 

be viewed as an extension of the regulations. It defines as clearly as 

possible what is expected of the source and reflects the outcome of the permit 

review process. A permit may limit the emissions rate from various emissions 

units or limit operating parameters such as hours of operation and amount or 

type of materials processed, stored, or combusted. Operational limitations 

frequently are used to establish a new potential to emit or to implement a 

desired emissions rate. The permit must be a "stand-alone" document that: 

! identifies the emissions units to be regulated; 

! establishes emissions standards or other operational limits to be 

met; 

! specifies methods for determining compliance and/or excess 

emissions, 

including reporting and recordkeeping requirements; and 

! outlines the procedures necessary to maintain continuous compliance 

with the emission limits. 

To achieve these goals, the permit, which is in effect a contract between the 

source and the regulatory agency, must contain specific, clear, concise, and 

enforceable conditions. 

This part of the manual gives a brief overview of the development of a 

permit, which ensures that major new sources and modifications will be 

constructed and operated in compliance with the applicable new source review 

(NSR) regulations [including prevention of signification deterioration (PSD) 

H.1 
D R A F T 

OCTOBER 1990 

and nonattainment area (NAA) review], new source performance standards (NSPS), 

national emissions standards for hazardous air pollutants (NESHAP), and 

applicable state implementation plan (SIP) requirements. In particular, a 

permit contains the specific conditions and limitations which ensure that: 

! an otherwise major source will remain minor; 

! all contemporaneous emissions increases and decreases are creditable 

and federally-enforceable; and 

! where appropriate, emissions offset transactions are documented 

clearly and offsets are real, creditable, quantifiable, 

permanent and federally-enforceable. 

For a more in-depth study, refer to the Air Pollution Training Institute 

(APTI) course SI 454 (or Workshop course 454 given by APTI) entitled 

"Effective Permit Writing." This course is highly recommended for all permit 

writers and reviewers. 

H.2 
D R A F T 

OCTOBER 1990 

II. TYPICAL CONSTRUCTION PERMIT ELEMENTS 

While each final permit is unique to a particular source due to varying 

emission limits and specific special terms and conditions, every permit must 

also contain certain basic elements: 

! legal authority;

! technical specifications;

! emissions compliance demonstration;

! definition of excess emissions;

! administrative procedures; and

! other specific conditions.

Although many of these elements are inherent in the authority to issue permits 

under the SIP, they must be explicit within the construction of a NSR permit. 

Table H-1 lists a few typical subelements found in each of the above. Some 

permit conditions included in each of these elements can be considered 

standard permit conditions, i.e., they would be included in nearly every 

permit. Others are more specific and vary depending on the individual source. 

II.A. LEGAL AUTHORITY 

In general, the first provision of a permit is the specification of the 

legal authority to issue the permit. This should include a reference to the 

enabling legislation and to the legal authority to issue and enforce the 

conditions contained in the permit and should specify that the application is, 

in essence, a part of the permit. These provisions are common to nearly all 

permits and usually are expressed in standard language included in every 

permit issued by an agency. These provisions articulate the contract-like 

nature of a permit in that the permit allows a source to emit air pollution 

only if certain conditions are met. A specific citation of any applicable 

H.3 
D R A F T 

OCTOBER 1990 

TABLE H.1. SUGGESTED MINIMUM CONTENTS OF AIR EMISSION PERMITS

_____________________________________________________________________________

Permit Category 

Legal Authority 

Technical Specifications 

Emission Compliance Demonstration 

Definition of Excess Emissions 

Administrative 

Other Conditions 

Typical Elements 

Basis--statute, regulation, etc.

Conditional Provisions

Effective and expiration dates

Unit operations covered

Identification of emission units

Control equipment efficiency

Design/operation parameters

Equipment design

Process specifications

Operating/maintenance procedures

Emission limits

Initial performance test and methods 

Continuous emission monitoring and 

methods 

Surrogate compliance measures 

- process monitoring 

- equipment design/operations 

- work practice 

Emission limit and averaging time

Surrogate measures

Malfunctions and upsets

Follow-up requirements

Recordkeeping and reporting

procedures

Commence/delay construction

Entry and inspections

Transfer and severability

Post construction monitoring

Emissions offset

______________________________________________________________________________

H.4 
D R A F T 

OCTOBER 1990 

permit effective date and/or expiration date is usually included under the 

legal authority as well. 

II.B. TECHNICAL SPECIFICATIONS 

Overall, the technical specifications may be considered the core of the 

permit in that they specifically identify the emissions unit(s) covered by the 

permit and the corresponding emission limits with which the source must 

comply. Properly identifying each emissions unit is important so that (1) 

inspectors can easily identify the unit in the field and (2) the permit leaves 

no question as to which unit the various permit limitations and conditions 

apply. Identification usually includes a brief description of the source or 

type of equipment, size or capacity, model number or serial number, and the 

source's identification of the unit. 

Emissions and operational limitations are included in the technical 

specifications and must be clearly expressed, easily measurable, and allow no 

subjectivity in their compliance determinations. All limits also must be 

indicated precisely for each emissions point or operation. For clarity, these 

limits are often best expressed in tabular rather than textual form. In 

general, it is best to express the emission limits in two different ways, with 

one value serving as an emissions cap (e.g., lbs/hr.) and the other ensuring 

continuous compliance at any operating capacity (e.g., lbs/MMBtu). The permit 

writer should keep in mind that the source must comply with both values to 

demonstrate compliance. Such limits should be of a short term nature, 

continuous and enforceable. In addition, the limits should be consistent with 

the averaging times used for dispersion modeling and the averaging times for 

compliance testing. Since emissions limitation values incorporated into a 

permit are based on a regulation (SIP, NSPS, NESHAP) or resulting from new 

source review, (i.e., BACT or LAER requirements), a reference to the 

applicable portion of the regulation should be included. 

H.5 
D R A F T 

OCTOBER 1990 

II.C. EMISSIONS COMPLIANCE DEMONSTRATION 

The permit should state how compliance with each limitation will be 

determined, and include, but is not limited to, the test method(s) approved 

for demonstrating compliance. These permit compliance conditions must be very 

clear and enforceable as a practical matter (see Appendix C). The conditions 

must specify: 

! when and what tests should be performed;

! under what conditions tests should be performed;

! the frequency of testing;

! the responsibility for performing the test;

! that the source be constructed to accommodate such testing;

! procedures for establishing exact testing protocol; and

! requirements for regulatory personnel to witness the testing.

Where continuous, quantitative measurements are infeasible, surrogate 

parameters must be expressed in the permit. Examples of surrogate parameters 

include: mass emissions/opacity correlations, maintaining pressure drop 

across a control (e.g., venturi throat of a scrubber), raw material input/mass 

emissions output ratios, and engineering correlations associated with specific 

work practices. These alternate compliance parameters may be used in 

conjunction with measured test data to monitor continuous compliance or may be 

independent compliance measures where source testing is not an option and work 

practice or equipment parameters are specified. Only those parameters that 

exhibit a correlation with source emissions should be used. Identifying and 

quantifying surrogate process or control equipment parameters (such as 

pressure drop) may require initial source testing or may be extracted from 

confirmed design characteristics contained in the permit application. 

Parameters that must be monitored either continuously or periodically 

should be specified in the permit, including averaging time for continuously 

monitored data, and data recording frequency for periodically (continually) 

monitored data. The averaging times should be of a short term nature 

H.6 
D R A F T 

OCTOBER 1990 

consistent with the time periods for which dispersion modeling of the 

respective emissions rate demonstrated compliance with air quality standards, 

and consistent with averaging times used in compliance testing. This 

requirement also applies to surrogate parameters where compliance may be timebased, such as weekly or monthly leak detection and repair programs (also see 

Appendix C). Whenever possible, "never to be exceeded" values should be 

specified for surrogate compliance parameters. Also, operating and 

maintenance (O&M) procedures should be specified for the monitoring 

instruments (such as zero, span, and other periodic checks) to ensure that 

valid data are obtained. Parameters which must be monitored continuously or 

continually are those used by inspectors to determine compliance on a realtime basis and by source personnel to maintain process operations in 

compliance with source emissions limits. 

II.D. DEFINITION OF EXCESS EMISSIONS 

The purpose of defining excess emissions is to prevent a malfunction 

condition from becoming a standard operating condition by requiring the source 

to report and remedy the malfunction. Conditions in this part of the permit: 

! precisely define excess emissions; 

! outline reporting requirements; 

! specify actions the source must take; and 

! indicate time limits for correction by the source. 

H.7 
D R A F T 

OCTOBER 1990 

Permit conditions defining excess emissions may include alternate conditions 

for startup, shutdown, and malfunctions such as maximum emission limits and 

operational practices and limits. These must be as specific as possible since 

such exemptions can be misused. Every effort should be made to include 

adequate definitions of both preventable and nonpreventable malfunctions. 

Preventable malfunctions usually are those which cause excess emissions due to 

negligent maintenance practices. Examples of preventable malfunctions may 

include: leakage or breakage of fabric filter bags; baghouse seal ruptures; 

fires in electrostatic precipitators due to excessive build up of oils or 

other flammable materials; and failure to monitor and replace spent activated 

carbon beds in carbon absorption units. These examples reinforce the need for 

good O&M plans and keeping records of all repairs. Permit requirements 

concerning malfunctions may include: timely reporting of the malfunction 

duration, severity, and cause; taking interim and corrective actions; and 

taking actions to prevent recurrence. 

II.E. ADMINISTRATIVE PROCEDURES 

The administrative elements of permits are usually standard conditions 

informing the source of certain responsibilities. These administrative 

procedures may include: 

! recordkeeping and reporting requirements, including all continuous 

monitoring data, excess emission reports, malfunctions, and 

surrogate compliance data; 

! notification requirements for performance tests, malfunctions, 

commencing or delay of construction; 

! entry and inspection procedures; 

! the need to obtain a permit to operate; and 

! specification of procedures to revoke, suspend, or modify the 

permit. 

Though many of these conditions will be entered into the permit via standard 

permit conditions, the reviewer must ensure the language is adequate to 

establish precisely what is expected or needed from the source, particularly 

the recordkeeping requirements. 

H.8 
D R A F T 

OCTOBER 1990 

II.F. OTHER CONDITIONS 

In some cases, specific permit conditions which do not fit into the 

above elements may need to be outlined. Examples of these are conditions 

requiring: the permanent shutdown of (or reduced emissions rates for) other 

emissions units to create offsets or netting credits; post-construction 

monitoring; continued Statewide compliance; and a water truck to be dedicated 

solely to a haul road. In the case of a portable source, a condition may be 

included to require a copy of the effective permit to be on-site at all times. 

Some O&M procedures, such as requiring a 10 minute warmup for an incinerator, 

would be included in this category, as well as conditions requiring that 

replacement fabric filters and baghouse seals be kept available at all times. 

Any source-specific condition which needs to be included in the permit to 

ensure compliance should be listed here. 

III. SUMMARY 

Assuming a comprehensive review, a permit is only as clear, specific, 

and effective as the conditions it contains. As such, Table H-2 on the 

following page lists guidelines for drafting actual permit conditions. The 

listing specifies how typical permit elements should be written. For further 

discussion on drafting "federally enforceable" permit conditions as a 

practical matter, please refer to Appendix C - "Potential to Emit." 

H.9 
D R A F T 

OCTOBER 1990 

TABLE H.2. GUIDELINES FOR WRITING EFFECTIVE SPECIFIC CONDITIONS IN NSR 

PERMITS 

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1. Make each permit condition simple, clear, and specific such that it 

"stands alone." 

2. Make certain legal authority exists to specify conditions. 

3. Permit conditions should be objective and meaningful. 

4. Provide description of processes, emissions units and control equipment 

covered by the permit, including operating rates and periods. 

5. Clearly identify each permitted emissions unit such that it can be 

located in the field. 

6. Specify allowable emissions (or concentration, etc.) rates for each 

pollutant and emissions unit permitted, and specify each applicable 

emissions standard by name in the permit. 

7. Allowable emissions rates should reflect the conditions of BACT/LAER and 

Air Quality Analyses (e.g., specify limits two ways: maximum mass/unit 

of process and maximum mass/unit time) 

8. Specify for all emissions units (especially fugitive sources) permit 

conditions that require continuous application of BACT/LAER to achieve 

maximum degree of emissions reduction. 

9. Initial and subsequent performance tests should be conducted at worst 

case operating (non-malfunction) conditions for all emissions units. 

Performance tests should determine both emissions and control equipment 

efficiency. 

10. Continual and continuous emissions performance monitoring and 

recordkeeping (direct and/or surrogate) should be specified where 

feasible. 

11. Specify test method (citation) and averaging period by which all 

compliance demonstrations (initial and continuous) are to be made. 

12. Specify what conditions constitute "excess emissions," and what is to be 

done in those cases. 

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H.10 
D R A F T 

OCTOBER 1990 

CHAPTER I 

PERMIT DRAFTING 

I. RECOMMENDED PERMIT DRAFTING STEPS 

This section outlines a recommended five-step permit drafting process 

(see Table I-1). These steps can assist the writer in the orderly preparation 

of air emissions permits following technical review. 

Step 1 concerns the emissions units and requires the listing and 

specification of three things. First, list each new or modified emissions 

unit. Second, specify each associated emissions point. This includes 

fugitive emissions points (e.g., seals, open containers, inefficient capture 

areas, etc.) and fugitive emissions units (e.g., storage piles, materials 

handling, etc.). Be sure also to note emissions units with more than one 

ultimate exhaust and units sharing common exhausts. Third, the writer must 

describe each emissions unit as it may appear in the permit and identify, as 

well as describe, each emissions control unit. Each new or modified emissions 

unit identified in Step 1 that will emit or increase emissions of any 

pollutant is considered in Step 2. 

Step 2 requires the writer to specify each pollutant that will be 

emitted from the new or modified source. Some pollutants may not be subject 

to regulation or are of de minimis amounts such that they do not require major 

source review. All pollutants should be identified in this step and reviewed 

for applicability. Federally enforceable conditions must be identified for 

de minimis pollutants to ensure they do not become significant (see 

Appendix C - Potential to Emit). An understanding of "potential to emit" is 

pertinent to permit review and especially to the drafting process. 

I.1 
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D R A F T 

OCTOBER 1990 

TABLE I-1. FIVE STEPS TO PERMIT DRAFTING 

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STEP 1. SPECIFY EMISSIONS UNITS 

! Identify each new (or modified) emissions unit that will emit (or 

increase) any pollutant. 

! Identify any pollutant and emissions units involved in a netting 

or emissions reduction proposal (i.e., all contemporaneous 

emissions increases and decreases). 

! Include point and fugitive emissions units. 

! Identify and describe emissions unit and emissions control 

equipment. 

STEP 2. SPECIFY POLLUTANTS 

! Pollutants subject to NSR/PSD. 

! Pollutants not subject to NSR/PSD but could reasonably be expected 

to exceed significant emissions levels. Identify conditions that 

ensure de minimis (e.g., shutdowns, operating modes, etc..). 

STEP 3. SPECIFY ALLOWABLE EMISSION RATES AND BACT/LAER REQUIREMENTS 

! Minimum number of allowable emissions rates specified is equal to 

at least two limits per pollutant per emissions unit. 

! One of two allowable limits is unit mass per unit time (lbs/hr) 

which reflects application of emissions controls at maximum 

capacity. 

! Maximum hourly emissions rate must correspond to that used in air 

quality analysis. 

! Specify BACT/LAER emissions control requirements for each 

pollutant/emissions unit pair. 

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I.2 
D R A F T 

OCTOBER 1990 

TABLE I-1. - Continued 

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STEP 4. SPECIFY COMPLIANCE DEMONSTRATION METHODS 

! Continuous, direct emission measurement is preferable. 

! Specify initial and periodic emissions testing where necessary. 

! Specify surrogate (indirect) parameter monitoring and 

recordkeeping where direct monitoring is impractical or in 

conjunction with tested data. 

! Equipment and work practice standards should complement other 

compliance monitoring. 

STEP 5. OTHER PERMIT CONDITIONS 

! Establish the basis upon which permit is granted (legal 

authority). 

! Should be used to minimize "paper" allowable emissions. 

! Federally enforceable permit conditions limiting potential to 

emit. 

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I.3 
D R A F T 

OCTOBER 1990 

Step 3 pools the data collected in the two previous steps. The writer 

should specify the pollutants that will be emitted from each emission unit and 

identify associated emission controls for each pollutant and/or emission unit. 

(Indicate if the control has been determined to be BACT.) The writer also 

must assess the minimum number of allowable emissions rates to be specified in 

the permit. Each emissions unit should have at least two allowable emissions 

rates for each pollutant to be emitted. This is the most concise manner in 

which to present permit allowables and should be consistent with the averaging 

times and emissions ratio used in the air quality analysis. As discussed 

earlier in Section H, the applicable regulation should also be cited as well 

as whether BACT, LAER, or other SIP requirements apply to each pollutant to be 

regulated. 

Step 4 essentially mirrors the items discussed in the previous Chapter 

H, Section IV., Emissions Compliance Demonstration. At this point the writer 

enters into the permit any performance testing required of the source. The 

conditions should specify what emissions test is to be performed and the 

frequency of testing. Any surrogate parameter monitoring must be specified. 

Recordkeeping requirements and any equipment and work practice standards 

needed to monitor the source's compliance should be written into the permit 

in Step 4. Any remaining or additional permit conditions, such as legal 

authority and conditions limiting potential to emit can be identified in 

Step 5. (Other Permit Conditions, see Table I-1.) At this point, the permit 

should be complete. The writer should review the draft to ensure that the 

resultant permit is an effective tool to monitor and enforce source 

compliance. Also, the compliance inspector should review the permit to ensure 

that the permit conditions are enforceable as a practical matter. 

I.4 
D R A F T 

OCTOBER 1990 

II. PERMIT WORKSHEETS AND FILE DOCUMENTATION 

Some agencies use permit drafting worksheets to store all the required 

information that will be incorporated into the permit. The worksheets may be 

helpful and are available at various agencies and in other EPA guidance 

documents. The worksheets serve as a summary of the review process, though 

this summation should appear in the permit file with or without a worksheet. 

Documenting the permit review process in the file cannot be overemphasized. 

The decision-making process which leads to the final permit for a source must 

be clearly traceable through the file. When filing documentation, the 

reviewer must also be aware of any confidential materials. Many agencies have 

special procedures for including confidential information in the permit file. 

The permit reviewer should follow any special procedures and ensure the permit 

file is documented appropriately. 

III. SUMMARY 

Listed below are summary "helpful hints" for the permit writer, which 

should be kept in mind when reviewing and drafting the permit. Many of these 

have been touched on throughout Part III, but are summarized here to help 

ensure that they are not overlooked: 

! Document the review process throughout the file. 

! Be aware of confidentiality items, procedures, and the 

consequences of the release of such information. 

! Ensure the application includes all pertinent review information 

(e.g., has the applicant identified solvents used in some 

coatings; are solvents used, then later recovered; ultimate 

disposal of collected wastes identified; and applicable monitoring 

and modeling results included). 

! Address secondary pollutant formation. 

! Ensure that all applicable regulations and concerns have been 

addressed (e.g., BACT, LAER, NSPS, NESHAP, non-regulated toxics, 

SIP, and visibility). 

I.5 
D R A F T 

OCTOBER 1990 

! Ensure the permit is organized well, e.g., conditions are 

independent of one another, and conditions are grouped so as not 

be cover more than one area at a time. 

! Surrogate parameters listed are clear and obtainable. 

! Emissions limits are clear. In cases of multiple or common 

exhaust, limits should specify if per emissions unit or per 

exhaust. 

! Every permit condition is 1) reasonable, 2) meaningful, 

3) monitorable, and 4) always enforceable as a practical matter. 

I.6 
D R A F T 

OCTOBER 1990 

APPENDIX A - DEFINITION OF SELECTED NSR TERMS 

BACT Best Available Control Technology is the control level required for sources subject to PSD. From 

the regulation (reference 40 CFR 52.21(b)) BACT means "an emissions limitation (including a visible 

emission standard) based on the maximum degree of reduction for each pollutant subject to regulation 

under the Clean Air Act which would be emitted from any proposed major stationary source or major 

modification which the Administrator, on a case-by-case basis, taking into account energy, 

environmental, and economic impacts and other costs, determines is achievable for such source or 

modification through application of production processes or available methods, systems, and 

techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for 

control of such pollutant. In no event shall application of best available control technology 

result in emissions of any pollutant which would exceed the emissions allowed by any applicable 

standard under 40 CFR Parts 60 and 61. If the Administrator determines that technological or 

economic limitations on the application of measurement methodology to a particular emissions unit 

would make the imposition of an emissions standard infeasible, a design, equipment, work practice, 

operational standard, or combination thereof, may be prescribed instead to satisfy the requirement 

for the application of best available control technology. Such standard shall, to the degree 

possible, set forth the emissions reduction achievable by implementation of such design, equipment, 

work practice or operation, and shall provide for compliance by means which achieve equivalent 

results." 

Emission Units The individual emitting facilities at a location that together make up the source. From the 

regulation (reference 40 CFR 52.21(b)), it means "any part of a stationary source which emits or 

would have the potential to emit any pollutant subject to regulation under the Act." 

Increments The maximum permissible level of air quality deterioration that may occur beyond the baseline air 

quality level. Increments were defined statutorily by Congress for SO2 and PM. Recently EPA also 

has promulgated increments for NOx. Increment is consumed or expanded by actual emissions changes 

occurring after the baseline date and by construction related actual emissions changes occurring 

after January 6, 1975, and February 8, 1988 for PM/SO2 and NOx, respectively. 
D R A F T 

OCTOBER 1990 

APPENDIX A - DEFINITION OF SELECTED NSR TERMS (Continued) 

Innovative Control 

Technology From the regulation (reference 40 CFR 52.21(b)(19)) "Innovative control technology" means any system 

of air pollution control that has not been adequately demonstrated in practice, but would have a 

substantial likelihood of achieving greater continuous emissions reduction than any control system 

in current practice or of achieving at least comparable reductions at lower cost in terms of energy, 

economics, or nonair quality environmental impacts. Special delayed compliance provisions exist 

that may be applied when applicants propose innovative control techniques. 

LAER Lowest Achievable Emissions Rate is the control level required of a source subject to nonattainment 

review. From the regulations (reference 40 CFR 51.165(a)), it means for any source "the more 

stringent rate of emissions based on the following: 

(a) The most stringent emissions limitation which is contained in the implementation plan of any

State for such class or category of stationary source, unless the owner or operator of the proposed

stationary source demonstrates that such limitations are not achievable; or

(b) The most stringent emissions limitation which is achieved in practice by such class or category

of stationary sources. This limitation, when applied to a modification, means the lowest achievable

emissions rate of the new or modified emissions units within a stationary source. In no event shall

the application of the term permit a proposed new or modified stationary source to emit any

pollutant in excess of the amount allowable under an applicable new source standard of performance." 

a.2 
D R A F T 

OCTOBER 1990 

APPENDIX A - DEFINITION OF SELECTED NSR TERMS (Continued) 

Major Modification A major modification is a modification to an existing major stationary source resulting in a 

significant net emissions increase (defined elsewhere in this table) that, therefore, is subject to 

PSD review. From the regulation (reference 40 CFR 52.21(b)(2)): 

"(i) `Major modification' means any physical change in or change in the method of operation of a

major stationary source that would result in a significant net emissions increase of any pollutant

subject to regulation under the Act. 

(ii) Any net emissions increase that is significant for volatile organic compounds shall be

considered significant for ozone. 

(iii) A physical change or change in the method of operation shall not include: 

(a) routine maintenance, repair and replacement;

(c) use of an alternative fuel by reason of an order or rule under Section 125 of the Act;

(d) Use of an alternative fuel at a steam generating unit to the extent that the fuel is generated

from municipal solid waste;

(e) Use of an alternative fuel or raw material by a stationary source which:

(1) The source was capable of accommodating before January 6, 1975, unless such change would be

prohibited under any Federally enforceable permit condition which was established after

January 6, 1975, pursuant to 40 CFR 52.21 or under regulations approved pursuant to 40 CFR Subpart I

or 40 CFR 51.166; or

(2) The source is approved to use under any permit issued under 40 CFR 52.21 or under regulations

approved pursuant to 40 CFR 51.166;

(f) an increase in the hours of operation or in the production rate, unless such change would be

prohibited under any federally enforceable permit condition which was established after

January 6, 1975, pursuant to 40 CFR 52.21 or under regulations approved pursuant to 40 CFR Subpart I

or 40 CFR 51.166; or 

(g) any change in ownership at a stationary source." 

a.3 
D R A F T 

OCTOBER 1990 

APPENDIX A - DEFINITION OF SELECTED NSR TERMS (Continued) 

Major Stationary Source A major stationary source is an emissions source of sufficient size to warrant PSD review. 

Major modification to major stationary sources are also subject to PSD review. From the 

regulation (reference 40 CFR 52.21(b)(1)), (i) "Major stationary source" means: 

"(a) Any of the following stationary sources of air pollutant which emits, or has the potential to

emit, 100 tons per year or more of any pollutant subject to regulation under the Act: Fossil fuelfired steam electric plants of more than 250 million British thermal units per hour heat input, coal

cleaning plants (with thermal dryers), Kraft pulp mills, Portland cement plants, primary zinc

smelters, iron and steel mill plants, primary aluminum ore reduction plants, primary aluminum ore

reduction plants, primary copper smelters, municipal incinerators capable of charging more than

250 tons of refuse per day, hydrofluoric, sulfuric, and nitric acid plants, petroleum refineries,

lime plants, phosphate rock processing plants, coke oven batteries, sulfur recovery plants, carbon

black plants (furnace process), primary lead smelters, fuel conversion plants, sintering plants,

secondary metal production plants, chemical process plants, fossil fuel boilers (or combinations

thereof) totaling more than 250 million British thermal units per hour heat input, petroleum storage

and transfer units with a total storage capacity exceeding 300,000 barrels, taconite ore processing

plants, glass fiber processing plants, and charcoal production plants;

(b) Notwithstanding the stationary source size specified in paragraph (b)(1)(i) of this section, any

stationary source which emits, or has the potential to emit, 250 tons per year or more of any air

pollutant subject to regulation under the Act; or

(c) Any physical change that would occur at a stationary source not otherwise qualifying under

paragraph (b)(1) as a major stationary source not otherwise qualifying under paragraph (b)(1) as a

major stationary source, if the changes would constitute a major stationary source by itself. 

(ii) A major stationary source that is major for volatile organic compounds shall be considered

major for ozone." 

NAAQS National Ambient Air Quality Standards are Federal standards for the minimum ambient air quality 

needed to protect public health and welfare. They have been set for six criteria pollutants 

including SO2, PM/PM10, NOx, CO, O3 (VOC), and Pb. 

a.4 
D R A F T 

OCTOBER 1990 

APPENDIX A - DEFINITION OF SELECTED NSR TERMS (Continued) 

NESHAP NESHAP, or National Emission Standard for Hazardous Air Pollutants, is a technology-based standard 

of performance prescribed for hazardous air pollutants from certain stationary source categories 

under Section 112 of the Clean Air Act. Where they apply, NESHAP represent absolute minimum 

requirements for BACT. 

NSPS NSPS, or New Source Performance Standard, is an emission standard prescribed for criteria pollutants 

from certain stationary source categories under Section 111 of the Clean Air Act. Where they apply, 

NSPS represent absolute minimum requirements for BACT. 

PSD Prevention of significant deterioration is a construction air pollution permitting program designed 

to ensure air quality does not degrade beyond the NAAQS levels or beyond specified incremental 

amounts above a prescribed baseline level. PSD also ensures application of BACT to major stationary 

sources and major modifications for regulated pollutants and consideration of soils, vegetation, and 

visibility impacts in the permitting process. 

Regulated Pollutants6 Refers to pollutants that have been regulated under the authority of the Clean Air Act 

(NAAQS, NSPS, NESHAP): 

O3 (VOC)- Ozone, regulated through volatile organic compounds as precursors 

NOx - Nitrogen oxides 

SO2 - Sulfur dioxide 

PM (TSP)- Total suspended particulate matter 

PM (PM10)- Particulate matter with <10 micron aerometric diameter

CO - Carbon monoxide 

Pb - Lead 5 TRS - Total reduced sulfur (including H2S)

As - Asbestos 5 RDS - Reduced Sulfur Compounds (including H2S)

Be - Beryllium 5 Bz - Benzene 

Hg - Mercury 5 Rd - Radionuclides

VC - Vinyl chloride 5 As - Arsenic

F - Fluorides 5 CFC's - Chlorofluorocarbons

H2SO4 - Sulfuric acid mist 5 Rn-222 - Radon-222

H2S - Hydrogen sulfide 5 Halons

6

 The referenced list of regulated pollutants is current as of November 1989. Presently, additional pollutants 

may also be subject to regulation under the Clean Air Act. 

a.5 
D R A F T 

OCTOBER 1990 

APPENDIX A - DEFINITION OF SELECTED NSR TERMS (Continued) 

Significant Emissions Increase For new major stationary sources and major modifications, a significant emissions 

increase triggers PSD review. Review requirements must be met for each pollutant 

undergoing a significant net emissions increase. From the regulation (reference 

40 CFR 52.21(b)(23)). 

(i) "Significant" means, in reference to a net emissions increase from a modified major source or

the potential of a new major source to emit any of the following pollutants, a rate of emissions

that would equal or exceed any of the following rates: 

Carbon monoxide: 100 tons per year (tpy)

Nitrogen oxides: 40 tpy

Sulfur dioxide: 40 tpy

Particulate matter: 25 tpy

PM10: 15 tpy

Ozone: 40 tpy of volatile organic compounds

Lead: 0.6 tpy

Asbestos: 0.007 tpy

Beryllium: 0.0004 tpy

Mercury: 0.1 tpy

Vinyl chloride: 1 tpy

Fluorides: 3 tpy

Sulfuric acid mist: 7 tpy

Hydrogen Sulfide (H2S): 10 tpy

Total reduced sulfur (including H2S): 10 tpy

Reduced sulfur compounds (including H2S): 10 tpy

(ii) "Significant" means, in reference to a net emissions increase or the potential of a source to

emit a pollutant subject to regulation under the Act, that (i) above does not list, any emissions

rate.

(For example, benzene and radionuclides are pollutants falling into the "any emissions rate"

category.) 

(iii) Notwithstanding, paragraph (b)(23)(i) of this section, "significant means any emissions rate

or any net emissions increase associated with a major stationary source or major modification which

would construct within 10 kilometers of a Class I area, and have an impact on such an area equal to

or greater than 1 ug/m3, (24-hour average).

a.6 
D R A F T 

OCTOBER 1990 

APPENDIX A - DEFINITION OF SELECTED NSR TERMS (Continued) 

SIP State Implementation Plan is the federally approved State (or local) air quality management 

authority's statutory plan for attaining and maintaining the NAAQS. Generally, this refers to the 

State/local air quality rules and permitting requirements that have been accepted by EPA as evidence 

of an acceptable control strategy. 

Stationary Source For PSD purposes, refers to all emissions units at one location under common ownership or control. 

From the regulation (reference 40 CFR 52.21(b)(5) and 51.166(b)(5)), it means "any building, 

structure, facility, or installation which emits or may emit any air pollutant subject to regulation 

under the Act." 

"Building, structure, facility, or installation" means all of the pollutant-emitting activities

which belong to the same industrial grouping, are located on one or more contiguous or adjacent

properties, and are under the control of the same person (or person under common control). 

Pollutant-emitting activities shall be considered as part of the same industrial grouping if they

belong to the same "Major Group" (i.e., which have the same first two digit code) as described in

the Standard Industrial Classification Manual, 1972, as amended by the 1977 Supplement

(U.S. Government Printing Office stock numbers 4101-0066 and 003-005-00176-0, respectively). 

a.7 
D R A F T 

OCTOBER 1990 

APPENDIX B

ESTIMATING CONTROL COSTS
D R A F T 

OCTOBER 1990 

APPENDIX B - ESTIMATING CONTROL COSTS 

I. CAPITAL COSTS 

Capital costs include equipment costs, installation costs, indirect 

costs, and working capital (if appropriate). Figure B-4 presents the 

elements of total capital cost and represents a building block approach that 

focuses on the control device as the basic unit of analysis for estimating 

total capital investment. The total capital investment has a role in the 

determination of total annual costs and cost effectiveness. 

One of the most common problems which occurs when comparing costs at 

different facilities is that the battery limits are different. For example, 

the battery limit of the cost of a electrostatic precipitation might be the 

precipitator itself (housing, plates, voltage regulators, transformers, etc.), 

ducting from the source to the precipitator, and the solids handling system. 

The stack would not be included because a stack will be required regardless of 

whether or not controls are applied. Therefore, it should be outside the 

battery limits of the control system. 

Direct installation costs are the costs for the labor and materials to 

install the equipment and includes site preparation, foundations, supports, 

erection and handling of equipment, electrical work, piping, insulation and 

painting. The equipment vendor can usually supply direct installation costs. 

The equipment vendor should be able to supply direct installation costs 

estimates or general installation costs factors. In addition, typical 

installation cost factors for various types of equipment are available in the 

following references. 

b.1

D R A F T 

OCTOBER 1990 

! OAQPS Control Cost Manual (Fourth Edition), January 1990, 

EPA 450/3-90-006 

! Control Technology for Hazardous Air Pollutants (HAPS) Manual, 

September 1986, EPA 625/6-86-014 

! Standards Support Documents 

- Background Information Documents 

- Control Techniques Guidelines Documents 

! Other EPA sponsored costing studies 

! Engineering Cost and Economics Textbooks 

! Other engineering cost publications 

These references should also be used to validate any installation cost factors 

supplied from equipment vendors. 

If standard costing factors are used, they may need to be adjusted due to 

site specific conditions. For example, in Alaska installation costs are on 

the order of 40-50 percent higher than in the contiguous 48 states due to 

higher labor prices, shipping costs, and climate. 

Indirect installation costs include (but are not limited to) engineering, 

construction, start-up, performance tests, and contingency. Estimates of 

these costs may be developed by the applicant for the specific project under 

evaluation. However, if site-specific values are not available, typical 

estimates for these costs or cost factors are available in: 

! OAQPS Control Cost Manual (Fourth Edition), EPA 450/3-90-006 

! Cost Analysis Manual for Standards Support Documents, April 1979 

These references can be used by applicants if they do not have 

site-specific estimates already prepared, and should also be used by the 

reviewing agency to determine if the applicant's estimates are reasonable. 

b.3 
D R A F T 

OCTOBER 1990 

Where an applicant uses different procedures or assumptions for estimating 

control costs than contained in the referenced material or outlined in this 

document, the nature and reason for the differences are to be documented in 

the BACT analysis. 

Working capital is a fund set aside to cover initial costs of fuel, 

chemicals, and other materials and other contingencies. Working capital costs 

for add on control systems are usually relatively small and, therefore, are 

usually not included in cost estimates. 

Table B-11 presents an illustrative example of a capital cost estimate 

developed for an ESP applied to a spreader-stoker coal-fired boiler. This 

estimate shows the minimum level of detail required for these types of 

estimates. If bid costs are available, these can be used rather than study 

cost estimates. 

II. TOTAL ANNUAL COST 

The permit applicant should use the levelized annual cost approach for 

consistency in BACT cost analysis. This approach is also called the 

"Equivalent Uniform Annual Cost" method, or simply "Total Annual Cost" (TAC). 

The components of total annual costs are their relationships are shown in 

Figure B-5. The total annual costs for control systems is comprised of three 

elements: "direct" costs (DC), "indirect costs" (IC), and "recovery credit" 

(RC), which are related by the following equation: 

TAC = DC + IC - RC 

b.4 
D R A F T 

OCTOBER 1990 

TABLE B-11. EXAMPLE OF A CAPITAL COST ESTIMATE FOR AN 

ELECTROSTATIC PRECIPITATOR 

Capital 

cost 

($) 

______________________________________________________________________________ 

Direct Investment 

Equipment cost 

ESP unit 175,800 

Ducting 64,100 

Ash handling system 97,200 

Total equipment cost 337,100 

Installation costs 

ESP unit 175,800 

Ducting 102,600 

Ash handling system 97,200 

Total installation costs 375,600 

Total direct investment (TDI) 712,700 

(equipment + installation) 

Indirect Investment 71,300 

Engineering (10% of TDI) 71,300 

Construction and field expenses (10% of TDI) 71,300 

Construction fees (10% of TDI) 71,300 

Start-up (2% of TDI) 14,300 

Performance tests (minimum $2000) 3,000 

Total indirect investment (TII) 231,200 

Contingencies (20% of TDI + TII) 188,800 

TOTAL TURNKEY COSTS (TDI + TII) 1,132,700 

Working Capital (25% of total direct operating costs)a 21,100 

GRAND TOTAL 1,153,800 

b.5 
D R A F T 

OCTOBER 1990 

+))))))))))))))))))))))))))), 

* o Raw Materials * 

* o Utilities * S))))))))))), 

* - Electricity /))))))))) Variable * 

* - Steam * * 

* - Water * * S)))))))), 

* - Others * * * 

.)))))))))))))))))))))))))))- * Direct * 

/))) Annual * 

+))))))))))))))))))))))))))), * Costs * 

* o Labor * * * 

* - Operating * * * 

* - Supervisory /))))))))) Semivariable * * 

* - Maintenance * S)))))))))))- * 

* o Maintenance materials * + * 

* o Replacement parts * * Total 

.)))))))))))))))))))))))))))- * = Annual 

* Costs 

+)))))))))))))))))))), * 

* o Overhead * Indirect * 

* o Property Taxes /)))))))) Annual * 

* o Insurance * Costs * 

* o Capital Recovery * * 

.))))))))))))))))))))- - * 

+)))))))))))))))))))), * 

* o Recovered Product* Recovery * 

* o Recovered Energy /)))))) Credits * 

* o Useful byproduct * * 

* o Energy Gain * S))))))))-

.))))))))))))))))))))-

FIGURE B-5. Elements of Total Annual Costs 

b.6 
D R A F T 

OCTOBER 1990 

Direct costs are those which tend to be proportional or partially 

proportional to the quantity of exhaust gas processed by the control system 

or, in the case of inherently lower polluting processes, the amount of 

material processed or product manufactured per unit time. These include costs 

for raw materials, utilities (steam, electricity, process and cooling water, 

etc.), and waste treatment and disposal. Semivariable direct costs are only 

partly dependent upon the exhaust or material flowrate. These include all 

associated labor, maintenance materials, and replacement parts. Although 

these costs are a function of the operating rate, they are not linear 

functions. Even while the control system is not operating, some of the 

semivariable costs continue to be incurred. 

Indirect, or "fixed", annual costs are those whose values are relatively 

independent of the exhaust or material flowrate and, in fact, would be 

incurred even if the control system were shut down. They include such 

categories as overhead, property taxes, insurance, and capital recovery. 

Direct and indirect annual costs are offset by recovery credits, taken 

for materials or energy recovered by the control system, which may be sold, 

recycled to the process, or reused elsewhere at the site. These credits, in 

turn, may be offset by the costs necessary for their purification, storage, 

transportation, and any associated costs required to make then reusable or 

resalable. For example, in auto refinishing, a source through the use of 

certain control technologies can save on raw materials (i.e., paint) in 

addition to recovered solvents. A common oversight in BACT analyses is the 

omission of recovery credits where the pollutant itself has some product or 

process value. Examples of control techniques which may produce recovery 

credits are equipment leak detection and repair programs, carbon absorption 

systems, baghouse and electrostatic precipitators for recovery of reusable or 

saleable solids and many inherently lower polluting processes. 

b.7 
D R A F T 

OCTOBER 1990 

Table B-12 presents an example of total annual costs for the control 

system previously discussed. Direct annual costs are estimated based on 

system design power requirements, energy balances, labor requirements, etc., 

and raw materials and fuel costs. Raw materials and other consumable costs 

should be carefully reviewed. The applicant generally should have documented 

delivered costs for most consumables or will be able to provide documented 

estimates. The direct costs should be checked to be sure they are based on 

the same number of hours as the emission estimates and the proposed operating 

schedule. 

Maintenance costs in some cases are estimated as a percentage of 

the total capital investment. Maintenance costs include actual costs to 

repair equipment and also other costs potentially incurred due to any 

increased system downtime which occurs as a result of pollution control system 

maintenance. 

Fixed annual costs include plant overhead, taxes, insurance, and capital 

recovery charges. In the example shown, total plant overhead is calculated as 

the sum of 30 percent of direct labor plus 26 percent of all labor and 

maintenance materials. The OAQPS Control Cost Manual combines payroll and 

plant overhead into a single indirect cost. Consequently, for "study" 

estimates, it is sufficiently accurate to combine payroll and plant overhead 

into a single indirect cost. Total overhead is then calculated as 60 percent 

of the sum of all labor (operating, supervisory, and maintenance) plus 

maintenance materials. 

Property taxes are a percentage of the fixed capital investment. Note 

that some jurisdictions exempt pollution control systems from property taxes. 

Ad valorem tax data are available from local governments. Annual insurance 

charges can be calculated by multiplying the insurance rate for the facility 

by the total capital costs. The typical values used to calculate taxes and 

b.8 
D R A F T 

OCTOBER 1990 

TABLE B-12. EXAMPLE OF A ANNUAL COST ESTIMATE FOR AN ELECTROSTATIC 

PRECIPITATOR APPLIED TO A COAL-FIRED BOILER 

Annual costs 

($/yr) 

_____________________________________________________________________________ 

Direct Costs 

Direct labor at $12.02/man-hour 26,300 

Supervision at $15.63/man-hour 0 

Maintenance labor at $14.63/man-hour 16,000 

Replacement parts 5,200 

Electricity at $0.0258/kWh 3,700 

Water at $0.18/1000 gal 300 

Waste disposal at $15/ton (dry basis) 33,000 

Total direct costs 84,500 

Indirect Costs 

Overhead 

Payroll (30% of direct labor) 7,900 

Plant (26% of all labor and replacement parts) 12,400 

Total overhead costs 20,300 

Capital charges 

G&A taxes and insurance 45,300 

(4% of total turnkey costs) 

Capital recovery factor 133,100 

(11.75% of total turnkey costs) 

Interest on working capital 2,100 

(10% of working capital) 

Total capital charges 180,500 

TOTAL ANNUALIZED COSTS 285,300 

b.9 
D R A F T 

OCTOBER 1990 

insurance is four percent of the total capital investment if specific facility 

data are not readily available. 

The annual costs previously discussed do not account for recovery of the 

capital cost incurred. The capital cost shown in Table B-2 is annualized 

using a capital recovery factor of 11.75 percent. When the capital recovery 

factor is multiplied by the total capital investment the resulting product 

represents the uniform end of year payment necessary to repay the investment 

in "n" years with an interest rate "i". 

The formula for the capital recovery factor is: 

CRF = i (1 + i)n 

(1 + i)n-1 

where: 

CPF = capital recovery factor 

n = economic life of equipment 

i = real interest rate 

The economic life of a control system typically varies between 10 to 20 

years and longer and should be determined consistent with data from EPA cost 

support documents and the IRS Class Life Asset Depreciation Range System. 

From the example shown in Table B-12 the interest rate is 10 percent and 

the equipment life is 20 years. The resulting capital recovery factor is 

11.75 percent. Also shown is interest on working capital, calculated as the 

product of interest rate and the working capital. 

It is important to insure that the labor and materials costs of parts of 

the control system (such as catalyst beds, etc.) that must be replaced before 

the end of the useful life are subtracted from the total capital investment 

b.10 
D R A F T 

OCTOBER 1990 

before it is multiplied by the capital recovery factor. Costs of these parts 

should be accounted for in the maintenance costs. To include the cost of 

those parts in the capital charges would be double counting. The interest 

rate used is a real interest rate (i.e., it does not consider inflation). The 

value used in most control costs analyses is 10 percent in keeping with 

current EPA guidelines and Office of Management and Budget recommendations for 

regulatory analyses. 

It is also recommended that income tax considerations be excluded from 

cost analyses. This simplifies the analysis. Income taxes generally 

represent transfer payments from one segment of society to another and as such 

are not properly part of economic costs. 

III. OTHER COST ITEMS 

Lost production costs are not included in the cost estimate for a new or 

modified source. Other economic parameters (equipment life, cost of capital, 

etc.) should be consistent with estimates for other parts of the project. 

b.11 
D R A F T 

OCTOBER 1990 

APPENDIX C7 

POTENTIAL TO EMIT 

Upon commencing review of a permit application, a reviewer must define 

the source and then determine how much of each regulated pollutant the source 

potentially can emit and whether the source is major or minor (nonmajor). A 

new source is major if its potential to emit exceeds the appropriate major 

emissions threshold, and a change at an existing major source is a major 

modification if the source's net emissions increase is "significant." This 

determination not only quantifies the source's emissions but dictates the 

level of review and applicability of various regulations and new source review 

requirements. The federal regulations, 40 CFR 52.21(b)(4), 51.165(a)(1)(iii), 

and 51.166(b)(4), define the "potential to emit" as: 

"the maximum capacity of a stationary source to emit a pollutant under its 

physical and operational design. Any physical or operational limitation on the 

capacity of the source to emit a pollutant, including air pollution control 

equipment and restrictions on hours of operation or on the type or amount of 

material combusted, stored or processed, shall be treated as part of its design 

if the limitation or the effect it would have on emissions is federally 

enforceable." 

In the absence of federally enforceable restrictions, the potential to emit 

calculations should be based on uncontrolled emissions at maximum design or 

achievable capacity (whichever is higher) and year-round continuous operation 

(8760 hours per year). 

7 This Appendix is based largely on an EPA memorandum "Guidance on 

Limiting Potential to Emit in New Source Permitting," from Terrell E. Hunt, 

Office of Enforcement and Compliance Monitoring, and John S. Seitz, Office of 

Air Quality Planning and Standards, June 13, 1989. 

c.1 
D R A F T 

OCTOBER 1990 

When determining the potential to emit for a source, emissions should be 

estimated for individual emissions units using an engineering approach. These 

individual values should then be summed to arrive at the potential emissions 

for the source. For each emissions unit, the estimate should be based on the 

most representative data available. Methods of estimating potential to emit 

may include: 

! Federally enforceable operational limits, including the effect of 

pollution control equipment; 

! performance test data on similar units; 

! equipment vendor emissions data and guarantees; 

! test data from EPA documents, including background information 

documents for new source performance standards, national emissions 

standards for hazardous air pollutants, and Section 111(d) 

standards for designated pollutants; 

! AP-42 emission factors; 

! emission factors from technical literature; and 

! State emission inventory questionnaires for comparable sources. 

NOTE: Potential to emit values reflecting the use of pollution control 

equipment or operational restrictions are usable only to the extent that the 

unit/process under review utilizes the same control equipment or operational 

constraints and makes them federally enforceable in the permit. 

Calculated emissions will embrace all potential, not actual, emissions 

expected to occur from a source on a continuous or regular basis, including 

fugitive emissions where quantifiable. Where raw materials or fuel vary in 

their pollutant-generating capacity, the most pollutant-generating substance 

must be used in the potential-to-emit calculations unless such materials are 

restricted by federally enforceable operational or usage limits. Historic 

usage rates alone are not sufficient to establish potential-to-emit. 

c.2 
D R A F T 

OCTOBER 1990 

Permit limitations are significant in determining a source's potential 

to emit and, therefore, whether the source is "major" and subject to new 

source review. Permit limitations are the easiest and most common way for a 

source to restrict its potential to emit. A source considered major, based on 

emission calculations assuming 8760 hours per year of operation, can often be 

considered minor simply by accepting a federally enforceable limitation 

restricting hours of operation to an actual schedule of, for example, 8 hours 

per day. A permit does not have to be a major source permit to legally 

restrict potential emissions. Minor source construction permits are often 

federally enforceable. Any limitation can legally restrict potential to emit 

if it meets three criteria: 1) it is federally enforceable as defined by 

40 CFR 52.21(b)(17), 52.24(f)(12), 51.165(a)(1)(xiv), and 51.166(b)(17), i.e., 

contained in a permit issued pursuant to an EPA-approved permitting program or 

a permit directly issued by EPA, or has been submitted to EPA as a revision to 

a State Implementation Plan and approved as such by EPA; 2) it is enforceable 

as a practical matter; and (3) it meets the specific criteria in the 

definition of "potential to emit," (i.e., any physical or operational 

limitation on capacity, including control equipment and restrictions on hours 

of operation or type or amount of material combusted, stored, or processed). 

The second criterion is an implied requirement of the first. A requirement 

may purport to be federally enforceable, but in reality cannot be federally 

enforceable if it cannot be enforced as a practical matter. 

In the absence of dissecting the legal aspects of "federal 

enforceability," the permit writer should always assess the enforceability of 

a permit restriction based upon its practicability. Compliance with any 

limitation must be able to be established at any given time. When drafting 

permit limitations, the writer must always ensure that restrictions are 

written in such a manner that an inspector could verify instantly whether the 

source is or was complying with the permit conditions. Therefore, short-term 

averaging times on limitations are essential. If the writer does this, he or 

she can feel comfortable that limitations incorporated into a permit will be 

federally enforceable, both legally and practically. 

c.3 
D R A F T 

OCTOBER 1990 

The types of limitations that restrict potential to emit are emission 

limits, production limits, and operational limits. Emissions limits should 

reflect operation of the control equipment, be short term, and, where 

feasible, the permit should require a continuous emissions monitor. Blanket 

emissions limits alone (e.g., tons/yr, lb/hr) are virtually impossible to 

verify or enforce, and are therefore not enforceable as a practical matter. 

Production limits restrict the amount of final product which can be 

manufactured or produced at a source. Operational limits include all 

restrictions on the manner in which a source is run, e.g., hours of operation, 

amount of raw material consumed, fuel combusted or stored, or specifications 

for the installation, maintenance and operation of add-on controls operating 

at a specific emission rate or efficiency. All production and operational 

limits except for hours of operation are limits on a source's capacity 

utilization. To appropriately limit potential to emit consistent with a 

previous Court decision [United States v. Louisiana-Pacific Corporation, 

682 F. Supp. 1122 (D. Colo. Oct. 30, 1987) and 682 F. Supp. 1141 (D. Colo. 

March 22, 1988)], all permits issued must contain a production or operational 

limitation in addition to the emissions limitation and emissions averaging 

time in cases where the emission limitation does not reflect the maximum 

emissions of the source operating at full design capacity without pollution 

control equipment. In the permit, these limits must be stated as conditions 

that can be enforced independently of one another. This emphasizes the idea 

of good organization when drafting permit conditions and is discussed in more 

detail in the Part III text. The permit conditions must be clear, concise, 

and independent of one another such that enforceability is never questionable. 

When permits contain production or operational limits, they must also 

have requirements that allow a permitting agency to verify a source's 

compliance with its limits. These additional conditions dictate 

enforceability and usually take the form of recordkeeping requirements. For 

example, permits that contain limits on hours of operation or amount of final 

product should require use of an operating log for recording the hours of 

operation and the amount of final product produced. For organizational 

c.4 
D R A F T 

OCTOBER 1990 

purposes, these limitations would be listed in the permit separately and 

records should be kept on a frequency consistent with that of the emission 

limits. It should be specified that these logs be available for inspection 

should a permitting agency wish to check a source's compliance with the terms 

of its permit. 

When permits require add-on controls operated at a specified efficiency 

level, the writer should include those operating parameters and assumptions 

upon which the permitting agency depended to determine that controls would 

achieve a given efficiency. To be enforceable, the permit must also specify 

that the controls be equipped with monitors and/or recorders measuring the 

specific parameters cited in the permit or those which ensure the efficiency 

of the unit as required in the permit. Only through these monitors could an 

inspector instantaneously measure whether a control was operating within its 

permit requirements and thus determine an emissions unit's compliance. It is 

these types of additional permit conditions that render other permit 

limitations practically and federally enforceable. 

Every permit also should contain emissions limits, but production and 

operational limits are used to ensure that emissions limits expressed in the 

permit are not exceeded. Production limits are most appropriately expressed 

in the shortest time periods as possible and generally should not exceed 

1 month (i.e., pounds per hour or tons per day), because compliance with 

emission limits is most easily established on a short term basis. An 

inspector, for example, could not verify compliance for an emissions unit with 

only monthly and annual production, operational or emission limits if the 

inspection occurred anytime except at the end of a month. In some rare 

situations a 1-month averaging time may not be reasonable. In these cases, a 

limit spanning a longer period is appropriate if it is a rolling average 

limit. However, the limit should not exceed an annual limit rolled on a 

monthly basis. Note also that production and operational recordkeeping 

requirements should be written consistent with the emissions limits. Thus, if 

an emissions unit was limited to a particular tons per day emissions rate, 

c.5 
D R A F T 

OCTOBER 1990 

then production records which monitor compliance with this limit should be 

kept on a daily basis rather than weekly. 

One final matter to be aware of when calculating potential to emit 

involves identifying "sham" permits. A sham permit is a federally enforceable 

permit with operating restrictions limiting a source's potential to emit such 

that potential emissions do not exceed the major or de minimis levels for the 

purpose of allowing construction to commence prior to applying for a major 

source permit. Permits with conditions that do not reflect a source's planned 

mode of operation may be considered void and cannot shield the source from the 

requirement to undergo major source preconstruction review. In other words, 

if a source accepts operational limits to obtain a minor source construction 

permit but intends to operate the source in excess of those limitations once 

the unit is built, the permit is considered a sham. If the source originally 

intended or planned to operate at a production level that would make it a 

major source, and if this can be proven, EPA will seek enforcement action and 

the application of BACT and other requirements of the PSD program. 

Additionally, a permit may be considered a sham permit if it is issued for a 

number of pollution-emitting modules that keep the source minor, but within a 

short period of time an application is submitted for additional modules which 

will make the total source major. The permit writer must be aware of such 

sham permits. If an application for a source is suspected to be a sham, EPA 

enforcement and source personnel should be alerted so details may be worked 

out in the initial review steps such that a sham permit is not issued. The 

possibility of sham permits emphasizes the need, as discussed in the Part III 

text, to organize and document the review process throughout the file. This 

documentation may later prove to be evidence that a sham permit was issued, or 

may serve to refute the notion that a source was seeking a sham permit. 

Overall, the permit writer should understand the extreme importance of 

potential to emit calculations. It must be considered in the initial review 

and continually throughout the review process to ensure accurate emission 

c.6 
D R A F T 

OCTOBER 1990 

limits that are consistent with federally enforceable production and 

operational restrictions. 

c.7