PEeHAN 

5528-B Hempstead Way 

Springfield, VA 22151 

703-81.3-6700 telephone 

703-813-6729 facsimile 

3622 Lyckan Parkway 

Suite 2002 

Durham, NC 27707 

919-493-3144 telephone 

919-493-3182 facsimile 

P.O. Box 1575 

Shingle Springs, CA 95682 

530-672-0441 telephone &. facsimile 

CONTROL MEASURE 

DEVELOPMENT SUPPORT 

ANALYSIS OF OZONE 

TRANSPORT COMMISSION 

MODEL RULES 

Prepared for: 

Ozone Transport Commission 

444 N. Capitol Street, NW 

Suite 638 

Washington, DC 20001 

Prepared by: 

B.H. Pechan &. Associates, Inc. 

5528-B Hempstead Way 

Springfield, VA 22151 

March 31, 2001 

Pechan Rpt. No. 01.02.001/9408.000 
DISCLAIMER 

This report was prepared by E.H. Pechan & Associates, Inc. under contract to the 

Ozone Transport Commission. This document is a product of E.H. Pechan & Associates, 

Inc., and does not reflect views of the Ozone Transport Commission or member States. 
CONTENTS 


Page 

TABLES ................................................................ vii 


FIGURES ................................................................ ix 


ACRONYMS AND ABBREVIATIONS ......................................... xi 


EXECUTIVE SUMMARY .................................................. xiii 


CHAPTER I 


INTRODUCTION .......................................................... 1 


CHAPTER II 


VOC MODEL RULE ANALYSIS METHODS .................................... 3 


A. EXISTING STATE RULES ............................................ 3 


B. CONSUMER PRODUCTS RULE ....................................... 3 


1. Model Rule Summary ............................................ 3 


2. Analysis Methods ................................................ 7 


3. Cost Estimates .................................................. 8 


C. PORTABLE FUEL CONTAINER RULE ................................. 8 


1. Model Rule Summary ............................................ 8 


2. Analysis Methods ................................................ 9 


3. Cost Estimates ................................................. 13 


D. AIM COATINGS RULE ............................................. 14 


1. Model Rule Summary ........................................... 14 


2. Analysis Methods ............................................... 14 


3. Cost Estimates ................................................. 15 


E. MOBILE EQUIPMENT REPAIR AND REFINISHING RULE .............. 15 


1. Model Rule Summary ........................................... 15 


2. Analysis Methods ............................................... 16 


3. Cost Estimates ................................................. 17 


F. SOLVENT CLEANING OPERATIONS RULE ........................... 17 


1. Model Rule Summary ........................................... 17 


2. Analysis Methods ............................................... 18 


3. Cost Estimates ................................................. 19 


G. SUMMARy ....................................................... 20 


CHAPTER III 


NOx MODEL RULE ANALYSIS METHODS .................................... 23 


A. MODEL RULE SUMMARY .......................................... 23 


B. ANALYSIS METHOD ............................................... 23 


1. Data Base And Sources Used In The Analysis ........................ 23 


2. Existing State Rules ............................................ 25 


111 
CONTENTS (continued) 


Page 

C. 	 METHODS APPLIED TO ESTIMATE RULE BENEFITS .................. 25 


1. 	 Exception ..................................................... 34 


2. 	 Sample Calculation ............................................. 34 


D. 	 CEMENT INDUSTRY ANALySIS ..................................... 35 


CHAPTER IV 


EXPECTED 2005/2007 MODEL RULE EMISSION BENEFITS .................... 37 


A. 	 SEVERE OZONE NONATTAINMENT AREA SUMMARIES ............... 37 


B. 	 WITHIN 100 KM SUMMARIES ....................................... 38 


C. 	 OTR-WIDE RESULTS .............................................. 39 


D. 	 SUMMARy ....................................................... 40 


E. 	 VOC MODEL RULE BENEFIT SAMPLE CALCULATION ................. 40 


CHAPTER V 


AIM COATINGS MARKET SURVEY ......................................... 55 


A. 	 SURVEY INSTRUMENT AND METHODS ............................. 55 


1. 	 How Did We Identify the Coating Manufacturers that Distribute these 


Products in the OTR? ............................................ 55 


2. 	 What Data Were Obtained from Survey Respondents? ................. 56 


B. 	 FINDINGS ........................................................ 57 


1. 	 Are Products Available that Meet the Limits? ........................ 57 


2. 	 How do OTC AIM Survey Results Compare to California Results? ....... 57 


CHAPTER VI 


DIESEL FUEL SAMPLING PLAN ............................................ 65 


A. 	 BACKGROUND ................................................... 65 


B. 	 OTC STATES DIESEL FUEL DISTRIBUTION .......................... 66 


C. 	 DIESEL FUEL REGULATIONS ...................................... 69 


D. 	 FUEL REGULATIONS IN OTHER STATES ............................ 71 


1. 	 Georgia Gasoline ............................................... 71 


2. 	 Texas Low Emission Diesel ....................................... 71 


3. 	 Arizona - Cleaner Burning Gasoline ................................ 72 


4. 	 California Diesel Fuel Regulations ................................. 73 


E. 	 CONCLUSIONS ................................................... 75 


CHAPTER VII 


CAVEATS AND UNCERTAINTIES ASSOCIATED WITH THE ANALYSIS .......... 77 


REFERENCES ........................................................... 79 


IV 
CONTENTS (continued) 


Page 

APPENDIX A 

METHODS FOR ESTIMATING PORTABLE FUEL CONTAINER EMISSIONS ...... A-I 

APPENDIXB 

SOURCE CLASSIFICATION CODES AFFECTED BY THE NOx MODEL RULE ..... B-1 

APPENDIXC 

NOx MODEL RULE CONTROL COST SUMMARIES ........................... C-l 

v 
vi 

TABLES 


Page 

ES-1 OTC Model Rule Estimated Benefits for Severe Ozone Nonattainment Areas . xiv 

II-I OTC State VOC Regulations for the Model Rule Categories .................. 4 

II-2 Comparison of OTC and California Emission Estimates .................... 11 

II-3 Summary of 1996 Refueling Emissions for the OTC States, 

and Percent Contribution for Nonroad Equipment Categories ............... 12 

II-4 Estimated Sales Price for Portable Gas Containers ....................... 13 

II-5 Cost of Compliance with Portable Gas Container Rule ..................... 13 

II-6 OTC VOC Model Rule Analysis Assumptions: Emission Factors, Percentage 

Reductions, Day-of-Week Factors, and Seasonality Factors ................. 21 

III-1 NOx Model Rule Summary ........................................... 24 

1II-2 Connecticut NOx RACT Regulations Summary ........................... 26 

1II-3 District of Columbia NOx RACT Regulations Summary .................... 27 

1II-4 Delaware NOx RACT Regulations Summary ............................. 28 

1II-5 Massachusetts NOx RACT Regulations Summary ......................... 29 

1II-6 Maryland NOx RACT Regulations Summary ............................. 30 

1II-7 New Jersey NOx RACT Regulations Summary ........................... 31 

III-8 New York NOx RACT Regulations Summary ............................. 32 

III-9 New Hampshire NOx RACT Regulations Summary ....................... 33 

III-lO United States Cement Company 1998 Clinker Capacities by State 

in the OTC States .................................................. 36 

IV-! OTC Model Rule Estimated Benefits for Severe Ozone Nonattainment Areas .. 42 

IV-2 Model Rule Benefits for Nonattainment Areas by County for 2005 and 2007 ... 43 

IV-3 Nonattainment Area NOx Model Rule Benefits for Affected Sources by 

Source Type and Size ............................................... 44 

IV-4 County Assignments for Analyzing Emission Reduction Benefits 

within 100 km of Nonattainment Areas ................................. 45 

IV-5 Nonattainment Area Model Rule Benefits with 100 km Radius Areas Included . 46 

IV-6 OTC-wide Model Rule Benefits by State for 2005 and 2007 ................. 47 

IV-7 OTC-wide Model Rule Benefits for Affected Sources by Source Type and 

Size for 2005 and 2007 .............................................. 48 

V-I List of AIM Survey Respondents ...................................... 58 

V-2 Example of Data Requested .......................................... 59 

V-3 Summary of the National Rule and Selected OTC Model Rule 

VOC Limits by AIM Category ......................................... 60 

V-4 Summary of Number of Compliant and Non-Compliant Products by 

AIM Category ..................................................... 61 

V-5 VOC Content by AIM Category ....................................... 62 

V-6 Percent Compliant AIM Products for OTC Compared to 1998 ARB Survey Data 63 

Vll 
Vlll 
FIGURES 


Page 

ES-l OTC VOC Model Rule Benefits by State within the OTR for 2005 ............ xv 


ES-2 OTC NOx Model Rule Benefits by State within the OTR for 2005 ........... xvii 


ES-3 Estimated Reductions from Six OTC Model Rules in 2005 . . . . . . . . . . . . . . . . xviii 


IV-1 Nonattainment Area NOx Model Rule Benefits by Source Type and Size ...... 49 


IV-2 OTC Severe Ozone Nonattainment Areas and Nearby Counties within 100 km . 50 


IV-3 OTC Severe Ozone Nonattainment Areas and Expected VOC Model Rule-


Associated Reductions ............................................... 51 


IV-4 OTC VOC Model Rule Benefits by State within the OTR for 2005 ............ 52 


IV-5 OTC NOx Model Rule Benefits by State within the OTR for 2005 ............ 53 


IV-6 Estimated Reductions from Six OTC Model Rules in 2005 .................. 54 


VI-I Highway Diesel Fuel Distribution Chain ................................ 66 


VI-2 Petroleum Administration for Defense Districts (PADD) ................... 67 


IX 
x 

ACRONYMS AND ABBREVIATIONS 


AIM 

ARB 

BEA 

Btus 

CAA 

CBG 

CE 

E-GAS 

EGU 

EIC 

EPA 

FIRE 

gil 

HAP 

km 

lbs/yr/person 

lbs/capita 

MACT 

MERR 

MOU 

NAAQS 

NET96 

NOx 

NPCA 

OTC 

OTR 

PADD 

PM 

ppm 

pSI 

RACT 

RE 

RP 

RVP 

SCAQMD 

SCC 

SCM 

SICs 

SIP 

STAPPAI 

ALAPCO 

TNRCC 

tpd 

VOC 

architectural and industrial maintenance 

Air Resources Board 

Bureau of Economic Analysis 

British thermal units 

Clean Air Act 

Cleaner Burning Gasoline 

control efficiency 

Economic Growth Analysis System 

electricity generating unit 

emission inventory code 

U.S. Environmental Protection Agency 

Factor Information Retrieval 

grams per liter 

hazardous air pollutant 

kilometers 

pounds per year per person 

pounds per capita 

maximum achievable control technology 

mobile equipment repair and refinishing 

Memorandum of Understanding 

National Ambient Air Quality Standards 

1996 National Emission Trends Inventory 

nitrogen oxides 

National Paint and Coatings Association 

Ozone Transport Commission 

Ozone Transport Region 

Petroleum Administration for Defense Districts 

particulate matter 

parts per million 

pounds per square inch 

reasonably available control technology 

rule effectiveness 

rule penetration 

Reid vapor pressure 

South Coast Air Quality Management District 

Source Classification Code 

Suggested Control Measure 

Standard Industrial Classifications 

State Implementation Plan 

State and Territorial Air Pollution Program Administrators/ 

Association of Local Air Pollution Control Officials 

Texas Natural Resource Conservation Commission 

tons per day 

volatile organic compound 

Xl 
Xll 
EXECUTIVE SUMMARY 


The States of the Ozone Transport Commission (OTC) are considering adopting 

additional control measures as part of their attainment and maintenance plans for the 

health-based Federal ozone standard. The analyses in this report provide estimates of the 

emission reductions and associated costs for adopting five volatile organic compound (VOC) 

model rules and one nitrogen oxides (NOJ model rule throughout the Ozone Transport 

Region (OTR). The VOC model rules have the potential to reduce emissions from consumer 

products, portable fuel containers, architectural and industrial maintenance (AIM) 

coatings, mobile equipment refinishing and repair operations, and solvent cleaning 

operations. The NOx model rule has the potential to reduce emissions from stationary 

internal combustion engines, gas turbines, industrial boilers, and cement kilns. This NOx 

model rule will yield additional reductions for smaller NOx sources that are not regulated 

under current regional or Federal NOx programs. 

The analysis for this study assesses additional emission reductions from OTC model 

rules taking into account the expected emissions reduction from current Federal and State 

. regulations and State Implementation Plan (SIP) assumptions; this ensures no double 

counting. Population based emission factors were used for the four VOC source category 

model rules. The portable fuel container analysis was done for residential and commercial 

usage using housing and business indicators. 

The NOx model rule analysis presented in this report is the product of an extensive 


review of available data and a review process with the OTC States during the project 


period. This was important because previous regulatory efforts have focused on NOx 


sources that are larger than those affected by the OTC NOx model rule. 


Table ES-l summarizes the expected model rule emission reductions for the three 

severe ozone nonattainment areas in the Northeast OTR: the Baltimore, Maryland area; 

the Philadelphia-Wilmington-Trenton area; and the New York-Northern New Jersey-Long 

Island-Southwest Connecticut area. The emission reductions listed in this table are either 

for 2005 or 2007, depending on the area's attainment date. 

Figure ES-l shows the OTC VOC model rule expected 2005 emission reductions by 

State. The largest estimated VOC emission reductions are in the most populous States ­

Pennsylvania and New York. Emission reduction estimates for each State are proportional 

to population: those areas with regulation already in place will show smaller reductions. 

Since these rules will yield additional reductions beyond 2005, those States having 2007 

attainment dates will report higher emission reductions for SIP accounting purposes. 

xln 
Table ES-1 


OTe Model Rule Estimated Benefits for Severe Ozone Nonattainment Areas 


,..... 

~ 

<: 

Nonattainment Area Attainment Date Model Rule 

2005/2007 Benefit (tpd) EPA Shortfall (tpd) 

NOx VOC NOx VOC 

Baltimore, MD 2005 NOx Model Rule 

Consumer Products 

Portable Fuel Containers 

AIM Coatings 

Mobile Equipment Refinishing 

Solvent Cleaning Operations 

Total 

5 

0 

0 

0 

0 

0 

5 

0 

4 

2 

8 

0 

0 

13 0 13 

Philadelph ia-Wilmington-Trenton, 

PA-NJ-DE-MD 

2005 NOx Model Rule 

Consumer Products 

6 

0 

0 

9 

Portable Fuel Containers 0 5 

AIM Coatings 

Mobile Equipment Refinishing 

Solvent Cleaning Operations 

Total 

0 

0 

0 

6 

19 

6 

20 

59 3 62 

New York-No New Jersey-Long 

Island, NY-NJ-CT 

2007 NOx Model Rule 

Consumer Products 

Portable Fuel Containers 

22 

0 

0 

0 

26 

25 

AIM Coatings 

Mobile Equipment Refinishing 

Solvent Cleaning Operations 

Total 

0 

0 

0 

22 

42 

20 

7 

120 7 85 

NOTES: Emission benefits estimates in this table are provided as integer values. Any emission benefit of less than 0.5 tpd is listed as a zero in this table. Totals may not 

equal the sum of the individual rule benefits because of rounding. 
Figure ES-1 


OTe voe Model Rule Benefits by State within the OTR for 2005 


(in tons per day) 


135~--------------------------------------------------~ 

120 +I------------------------------------------------~ 

105 

90 1 	 t 

75ll------------------------------------~ 

~ 60 +I--------------------------------~ 

45 1 	 [}]I------l 

30 +1------l 

15+1-------1 

o +r----r-" 

ov~ o 0 ~ .0 ;;\ lJ.. 0 	 fl} 0 ~ 00 0~ ~r§- ~~ ~fl}~ § ~ ~0 -.\0" ~ ~~ 0" o.ff' i$-fl} ~ ~ ",~Cj ~Cj '::,0 ~ _~flj ,~ f.,.~ \~cs o~~ r..e;.'lf "::,..~~ _~flj o· ~ ~ 0 C:>" 00 ~0 ~ o 	 v d­cP ~. ~flj x-.flj ~0 ~ .r:;:.<::' 0 f.,.~ 

oc} ~'l>'0~ ~0~ ~0 "!};.~ ~ ~ Q~ 

mPortable Fuel Containers 

[] Solvent Cleaning Operations 

D Mobile Equipment Refinishing 

mAIM Coatings 

8 Consumer Products 
Figure ES-2 provides a similar display for the NOx model rule. The biggest NOx model 

rule-associated emission reductions are expected in New York, followed by those in New 

Jersey and Pennsylvania. 

Figure ES-3 summarizes the expected voe and NOx emission reductions from the OTe 

model rules for the different geographic areas that have been examined in this analysis. 

The total emission reductions in the three severe ozone nonattainment areas for all of the 

model rules combined in 2005 are 180 tons voe per day and 32 NOx tons per day (tpd). 

Expanding the analysis area to counties within 100 kilometers (km) of these three severe 

ozone nonattainment areas provides an additional 168 tpd in voe emission benefits, and 

another 11 tpd in NOx emission reductions. OTR-wide model rule benefits total 533 voe 

tpd and 65 NOx tpd in 2005. 

XVI 
Figure ES-2 

OTC NOx Model Rule Benefits by State within the OTR for 2005 

(in tons per day) 

18+1----------------------------------------------------~ 

16+1--------------------------------------------------~ 

14+1----------------------------------------------------~ 

12+1----------------------------------------------------

10 +I------------------------------------------------~ 

8+1----------------------------------------------~ 

6 +I------------------------~ 

4 +1--------1 

2 +1--------1 

o +I----r-..... 

BNOx Model 

Rule 

20r---------------------~~~~~--------------~ 

:>< 

;5.

,.... 

~ ~,fb­ ~~~0 ~fb-~ 0~v ~~0 o # .~0 ~fb- 0 ~o ~ .~fb­ ~,><$' _~fb-~ ~,>g ~ A0~ ~ ~~I?} ~fb-~ ~~ ~'7j ~. f))v ~~ ')0--- 4.0 ~<ff. 0,g ~r§ ..s.~C>J c.,o 9 rI;-~ cP & _~fb-cfjJ ~I?} ~0~ ~0~ £)0~ o~ ~ <F ·cr ~. ~0 ~~ ~o~ <j{3 
Figure ES-3 


Estimated Reductions from Six OTe Model Rules in 2005 


(in tons per day) 


600 


500 


400 


~ 

S: 	 300 


200 


100 


o~ 

Shortfalls in 3 NAAs 100 km 

aVOC 

.NOx 

Total Reductions NAAs plus OTR-Wide 

CHAPTER I 

INTRODUCTION 

The OTC was formed by Congress through the Clean Air Act (CAA) Amendments of 

1990 to help coordinate control plans for reducing ground-level ozone in the Northeast and 

mid-Atlantic States. Since its inception, OTC has focused on a number of tasks, including: 

assessing the nature and magnitude of the ozone problem in the region, evaluating 

potential control approaches, and recommending regional control measures. Twelve States 

and the District of Columbia are represented in the OTC. 

OTC States continue to work individually and collectively to ensure attainment and 

maintenance of the National Ambient Air Quality Standards (NAAQS). This includes 

identifying any remaining control measures that may be necessary to attain and maintain 

the one-hour NAAQS, as well as to start reducing eight-hour average ozone levels. Six 

States (Connecticut, Delaware, Maryland, New Jersey, New York, and Pennsylvania) in 

particular are focusing on additional control measures as a part of their one-hour 

attainment demonstrations. However, all States will benefit from additional emission 

reductions of ozone precursors for purposes of maintaining the one-hour standard. 

The analysis in this report provides estimates of the emission reductions and 

associated costs for adopting five VOC model rules and one NOx model rule throughout the 

Northeast OTR. The VOC model rules have the potential to reduce emissions from 

consumer products, portable fuel containers, AIM coatings, mobile equipment refinishing 

and repair operations, and solvent cleaning operations. The NOx model rule has the 

potential to reduce emissions from stationary internal combustion engines, gas turbines, 

industrial boilers, and cement kilns. This NOx model rule will yield additional reductions 

for smaller NOx sources that are not covered under current regional NOx programs. 

Chapter II describes the methods used to estimate the emission benefits of the VOC 

model rules. This chapter delineates the existing OTC State regulations that affect VOC 

emissions from the model rule source categories. It has separate sections that describe 

analysis methods for each of the individual VOC model rules. 

NOx model rule analysis methods are described in Chapter III. Existing State 

regulations affecting NOx emissions from industrial boilers, internal combustion engines, 

gas turbines, and cement kilns are presented in the first section of this chapter. This 

chapter also describes the data bases that were developed and applied in this analysis, and 

the methods used to estimate model rule benefits. 

Chapter IV presents estimates of the expected 2005/2007 model rule emission benefits. 

Estimated emission benefits are presented first for the three severe ozone nonattainment 

areas within the Northeast OTR. These are the areas for which the U.S. Environmental 

Protection Agency (EPA) has estimated emission shortfalls. Because the model rules may 

not achieve all of the needed VOC and NOx emission reductions to meet these shortfalls, 

1 

the analysis also examines the expected emission benefits within 100 km of these severe 

ozone nonattainment areas. 

Chapter V provides the results of an AIM coatings market survey, which was 

performed to investigate the availability of AIM coatings that comply with the VOC limits 

of the OTC Model Rule. Chapter VI is the diesel fuel sampling plan. Caveats and 

uncertainties associated with this analysis are described in Chapter VII. 

2 

CHAPTER II 


VOC MODEL RULE ANALYSIS METHODS 


Base and future year VOC emission estimates for the consumer products rule, the AIM 

coatings rule, the mobile equipment refinishing and repair rule, and the solvent cleaning 

rule use per capita emission factors. U.S. Census Bureau 1996 County Population 

Estimates were used to estimate 1996 VOC emissions for these States (Census, 2000). The 

July 1, 1996 population estimates were used for each OTC State. The U.S. Census Bureau 

released these population estimates to the public in March 2000. They contain revisions of 

estimates from previous years and the results of special censuses and test censuses 

conducted by the U.S. Census Bureau. 

The Economic Growth Analysis System (E-GAS) model was run to obtain specific 

growth factors for both the nonattainment areas and remaining counties in a State. These 

growth factors were then applied to 1996 population to project county-level populations for 

2005 and 2007. 

A. EXISTING STATE RULES 

Table II-I summarizes OTC State VOC regulations for four of the source categories 

whose emissions are potentially affected by the OTC draft model VOC rules. If no 

regulation is listed in Table II-I, then the future VOC emissions from that source category 

are limited by the applicable Federal rule. There are no State regulations that affect 

portable fuel container VOC emissions, so this source category is not included in the table. 

B. CONSUMER PRODUCTS RULE 

1. Model Rule Summary 

The Federal consumer product rule became effective in December 1998 (63FR48819, 

1998). It regulates 24 product categories representing 48 percent of the consumer products 

inventory, nationally, and reduces VOC emissions from those product categories by 20 

percent. Over one-half of the inventory is unregulated in the OTR. In order to capture 

additional emission reductions from this sector, the OTC is developing a model rule for this 

source category. 

The OTC model rule regulates approximately 80 consumer product categories, and 

uses more stringent VOC content limits than the Federal rule. Some of the limits are 

currently in effect in California, and are known to be technologically feasible; others have 

future effective dates. The proposed compliance date for the model rule limits is January 

1, 2005. Manufacturers are to ensure compliance with the limits by reformulating 

3 

..,.. 


Table 11-1 


eTC State vec Regulations for the Model Rule Categories 


State Consumer Products AIM Coating Solvent Cleaning Operations 

Mobile Equipment Repair 

and Refinishing 

Connecticut nfa nfa - MERR sources can opt in to 

a general permit which 

requires the use of HVLP 

sprayers, electrostatic 

equipment, or other 

application methods 

guaranteed to achieve at 

least 65% transfer efficiency. 

Closed applicator cleaning 

devices and work practices 

minimizing solvent losses are 

also required. vac limits are 

not specified, but total vac 

emissions are limited to 5 tpy 

(facilities constructedf 

modified after 1998) or major 

source thresholds (facilities 

constructedfmodified through 

1998). Many eligible sources 

have opted into the general 

permit. 

- No previous SIP credit has 

been requested for this 

permitting program. 

nfa 

District of Columbia nfa nfa nfa nfa 

Maine nfa nfa nfa nfa 

Delaware nfa 

-­

nfa 

---­

- Regulation #24, Section 33 

- Effective May 31, 1995 

- Standards for cold cleaning, 

open top vapor degreasing, 

and conveyorized degreasing 

- Regulation #24, Section11 

- Effective April 1, 1996 

- This rule sets limits on 

vac content of the 

coatings 

- vac limits similar to 

National Rule 
01 

Table 11-1 (continued) 

State Consumer Products AIM Coating Solvent Cleaning Operations 

Mobile Equipment Repair 

and Refinishing 

Maryland n/a n/a - CaMAR 26.11.19.09 

- Final State Implementation 

Plan (SIP) rule was effective 

in 1997 

- After May 15, 1996, a person 

may not use any vac 

degreasing material that has 

a vapor pressure greater 

than 1 millimeter mercury at 

20° C. - The use of any 

halogenated substance that 

is a vac is prohibited. 

- The use of vac degreasing 

material is prohibited, unless 

the vapor degreaser is 

equipped with a condenser or 

a pollution control device with 

an overall control efficiency 

of at least 90% 

- CaMAR 26.11.19.23 

- Final SIP rule was effective 

in 1997 

- The rule establishes 

standards for vehicle 

refinishing based on VOC 

content of coatings 

- Requires both the use of 

HVLP spray guns and 

enclosures for cleaning 

spray guns and lines 

- This rule sets a vac limit 

for precoat coatings, which 

is not included in the 

National Rule 

Massachusetts - 310 CMR 7.25 (12) 

- Effective 1995 

- vac limits similar to NY/NJ 

Rule and National Rule 

- National Rule covers more 

product categories than the 

MA Rule 

- Provision in MA Rule stating 

that EPA vac limits will 

override MA vac limits 

- 310 CMR 7.25 (11) 

- Effective 1995 

- vac limits similar to NJ Rule 

- National Rules covers more AIM 

Coatings categories than the MA 

Rule 

- For some categories, the MA Rule 

has more stringent vac limits than 

the National Rule, and vice versa 

- Provision in MA Rule stating that 

EPA vac limits will override MA 

vac limits 

- EPA's Compliance Technical 

Guideline 

- Effective early 1980s 

- 310 CMR 7.18 (28) 

- Effective 1995 

- vac limits similar to 

National Rule 

- HVLP guns and enclosed 

gun cleaning requirements 

or equivalent. 

I 

New Hampshire n/a n/a n/a nLa --­
Table 11-1 (continued) 

~ 

State Consumer Products AIM Coating Solvent Cleaning Op_erations 

Mobile Equipment Repair 

and Refinishing 

New Jersey - Title 7, Chapter 27, 

Subchapter 24 

- Effective 1995 

- Rule covers entire State 

- VOC limits similar to National 

Rule 

- Provision in NJ Rule stating 

that EPA VOC limits will 

override NJ VOC limits 

- Title 7, Chapter 27, Subchapter 23 

- Effective 1989 

- Rule covers entire State 

- VOC limits similar to National Rule 

and NY Rule 

- National Rules covers more AIM 

Coatings categories than the NJ 

Rule 

- For some categories, the NJ Rule 

has more stringent VOC limits than 

the National Rule, and vice versa 

- Title 7, Chapter 27 

Subchapter 16 

- EPA's Compliance Technical 

Guideline effective 1986 

n/a 

New York - 6 NYCRR Part 235 

- Effective 1996 (last amended) 

- Rule covers entire State 

- VOC limits similar to National 

Rule 

- National Rule covers more 

product categories than the 

NY Rule 

- 6 NYCRR Part 205 

- Effective 1989 

- Rule covers only NYC metropolitan 

area 

- VOC limits similar to National Rule 

- National Rules covers more AIM 

Coatings categories than the NY 

Rule 

- For some categories, the NY Rule 

has more stringent VOC limits than 

the National Rule, and vice versa 

- 6 NYCRR Part 226 

- Effective in the NYC 

metropolitan area for 1990 

and 1996 

- This rule implements good 

housekeeping procedures for 

surface cleaning operations 

- In 1999, the NYC 

metropolitan area will be 

subject to the NESHAP for 

Solvent Cleaning (40 CFR 

63,460, Subpart T, Vol. 59, 

No. 231) 

- 6 NYCRR Part 228 

- Effective 1990 for the NYC 

metropolitan area/LOCMA 

- In 1996, the entire State 

will be effected by the 

National Rule 

Pennsylvania n/a n/a - Section 129.63 - Section 129.75 adopted 

Oegreasing Operations November 24, 1999, 

effective November 27, 

1999 

Rhode Island - Regulation #31 

- Effective 1994 

(last amended 1996) 

- VOC limits similar to National 

Rule 

- Regulation #33 

- Effective 1996 

- VOC limits similar to NJ Rule 

- National Rules covers more AIM 

Coatings categories than the RI 

Rule 

- For some categories, the RI Rule 

has more stringent VOC limits than 

the National Rule, and vice versa 

- EPA's Compliance Technical 

Guideline-Effective 1979 

- Organic Solvent Cleaning 

NESHAP-Effective 1996 

- Regulation #30 

- Effective 1994 

(last amended 1996) 

- VOC limits similar to 

National Rule 

- HVLP guns and enclosed 

gun cleaning requirements or 

equivalent 

Vermont n/a n/a n/a n/a 

Virqinia n/a --­ n/a n/a - n/a 

NOTE: Portable fuel containers are not included in this table because they are not currently regulated by any OTe States. 
products and substituting products with compliant products that are already on the 

market. 

The OTC model rule contains requirements for approximately 80 product categories. 

Examples include aerosol adhesives, floor wax strippers, dry cleaning fluids, and general 

purpose cleaners. It also contains administrative requirements for labeling, reporting, 

code-dating, and a "most restrictive limit" scenario. There is a reporting requirement, such 

that manufacturers may be required to submit information to the State upon written 

notice. 

A California Air Resources Board (ARB) test method would be primarily used to 

demonstrate compliance. Alternative accepted test methods are also allowed. 

Enforcement with the product VOC content limits and other requirements would be 

performed on a State-by-State basis. 

If complying with the VOC content limits becomes difficult, flexibility options are 

provided for in the draft model rule. These include an innovative product exemption (e.g., 

a non-compliant product with a delivery system that puts it in compliance with the limits); 

variances; exemptions; an alternative control plan; and a provision that allows products to 

be sold that are manufactured before the rule applicability date. 

2. Analysis Methods 

The VOC emission reductions in 2005 and 2007 attributable to the EPA final rule 

regulating consumer products were estimated using the EPA guidance that was issued 

June 22, 1995 (Seitz, 1995a). At that time, development of a Federal consumer products 

rule was still in progress. The purpose of the Seitz memo was to provide guidance 

concerning credit that could be taken in rate-of-progress plans for reductions associated 

with the consumer products rule. 

The memorandum said that the States were allowed to take credit for a 20 percent 

reduction from the national consumer products rule. Based on EPA's study, baseline 

emissions from the categories covered by this rule (i.e., a subset of all consumer products) 

were estimated to be approximately 3.9 pounds per capita annually. A 20 percent 

reduction would be about 0.8 pounds per capita annually. A control efficiency (CE) of 14.2 

percent was developed from the 20 percent reduction anticipated from the Federal 

regulation. A rule effectiveness (RE) value of 100 percent was applied because any Federal 

rule would require all products to comply. A rule penetration (RP) value of 48.6 percent 

was applied in the analysis because VOC content limits only apply to that portion of the 

potentially affected products. 

The equation for computing the VOC emission factor for consumer products after 

control by the National/Federal Rule is listed below: 

Post-control emission factor =Pre-control emission factor [l-CE(RP)(RE)] 

Post-control emission factor =7.84 pounds per capita (lbs/capita) [1-(.2)(1.00)(0.486)] 

=7.06Ibs/capita 

7 
The OTC model rule requires manufacturers of particular products to reformulate 

them to meet VOC limits. The VOC limits in the model rule are based on rules adopted or 

under consideration by ARB. Consumer product emission reductions for the OTC model 

rule are estimated to be 14.2 percent of the total consumer product inventory of the 

national rule reduction. These estimated reductions were based on information in the ARB 

staff report and surveys (ARB, 1989; 1999a). Recent information can be found on the ARB 

website Consumer Products Program section 

(http://www.arb.ca.gov/consprod/consprod.htm). A rule penetration value of 100 percent is 

applied for the OTC model rule because the estimated 14.2 percent control efficiency 

accounts for the percentage of affected projects. Rule effectiveness is 100 percent because 

compliance is via product reformulation. 

The credit for the OTC model rule affecting consumer products relative to the National 

Rule was computed as shown below: 

Post OTC model rule control emission factor 	=7.06lbs/capita [1-(0.142)(1.00)(1.00)] 

=6.06lbs/capita 

3. 	 Cost Estimates 

ARB has estimated the cost of their rule to be $800 per ton (ARB, 1999a). Since the 

OTC model rule emission limits are based on California's, this value should be approximate 

costs that would be incurred to meet the same limits in the OTC States. However, because 

compliance costs are spread over a larger portion of sales in the OTC than in California, 

costs incurred by manufacturers are expected to be lower than $800 per ton. 

C. 	 PORTABLE FUEL CONTAINER RULE 

1. 	 Model Rule Summary 

This draft model rule addresses VOC emissions from portable fuel containers. The 

rule specifies performance standards for portable fuel containers and/or spouts which are 

intended to reduce emissions from storage, transport and refueling activities. The rule 

states that any portable fuel container and/or spout must provide the following: 

• 	 only one opening for both filling and pouring; 

• 	 an automatic shut-off to prevent overfill during refueling; 

• 	 automatic closing and sealing ofthe container and/or spout when not dispensing 

fuel; 

• 	 a fuel flow rate and fill level as specified in the rule; 

• 	 a permeation rate of less than or equal to 0.4 grams per gallon per day; and 

• 	 a warranty by the manufacturer as specified in the rule. 

The draft model rule applies to any person or entity who will sell, supply, offer for sale 

or manufacture for sale portable fuel containers and/or spouts on or after January 1, 2003. 

Manufacturers of portable fuel containers are required to verify compliance through testing 

and record-keeping. The rule also specifies administrative and labeling requirements. The 

rule affects all portable fuel containers and/or spouts except: 

8 

• 	 containers with a capacity of less than or equal to one quart; 

• 	 rapid refueling devices with capacities greater than or equal to four gallons; 

• 	 safety cans and portable marine fuel tanks that operate in conjunction with 

outboard engines; and 

• 	 products which result in cumulative VOC emissions below those of a 


representative container and/or spout. 


2. 	 Analysis Methods 

Base case emissions were calculated by accounting for emissions from five different 

components related to gas container use, including permeation, diurnal, transport-spillage, 

spillage and vapor displacement emissions for two sectors: residential and commercial. 

Emission estimation methodologies for portable fuel containers were obtained from ARB's 

Mailout MSC 99-25, "Public Meeting to Consider Approval of CA's Portable GasolineContainer Emissions Inventory," (ARB, 1999b). The estimated portable fuel container 

population and usage data for both residential and commercial sectors were developed 

using survey information collected by ARB. Emission rates were based on tests conducted 

by ARB and EPA for various portable fuel container activities. 

To estimate permeation, diurnal, and transport-spillage emissions, the number of 

portable fuel containers for both residential and commercial sectors was used as activity 

data. Spillage and vapor displacement emissions are estimated using data on the 

population of nonroad equipment assumed to be refueled with portable fuel containers. 

The method for estimating activity data for each of these is discussed below. 

The number of residential containers in the OTR was estimated using the number of 

housing units as an indicator. Occupied housing units by county were obtained for the year 

1990 from the U.S. Census Bureau (Census, 1999). These data were then grown to 1996 

using the change in U.S. Census Bureau estimates of county-level population estimates 

between 1990 and 1996. The 1996 occupied housing units by county were then projected to 

the years 2005 and 2007 using population as an indicator. Growth factors corresponding to 

the change in population between 1996 and 2005, as well as between 1996 and 2007 were 

obtained from the E-GAS model. The expected number of containers per household, the 

portable gas can material, amount of fuel stored and storage condition (open/closed) were 

based on the ARB survey results. 

The number of portable fuel containers used by commercial businesses was estimated 

using the number of establishments expected to have at least one gas can. The number of 

establishments for 1996 was taken from the Dun & Bradstreet Marketplace3.0 Database. 

Establishment data for all counties within the OTR were compiled for the following 

Standard Industrial Classifications (SICs), which are the establishments most likely to 

own and use portable gasoline containers: 

• 	 01 - Agricultural Crops 

• 	 02 - Agricultural Livestock 

• 	 07 - Agricultural Service (except 074 and 075) 

• 	 08 - Forestry 

• 	 15, 16, 17 - Construction 

• 	 55 - Automotive Dealers and Gasoline Service Stations 

9 
• 75 - Automotive Repair, Services and Parking 

Establishment data were then projected from 1996 to 2005 and 2007 using employment 

projections from the U.S. Department of Labor's Bureau of Labor Statistics (BLS, 1999). 

Employment projections were only available for the years 1998 and 2008. Employment in 

2005 and 2007 was estimated using linear interpolation. Growth factors were developed 

for all of the above SIC codes, and then weighted based on the number of establishments 

within each SIC. A weighted growth factor was then applied to the number of total 

establishments per county in all of the above SIC codes. The expected number of 

containers per commercial business, the portable gas can material, amount of fuel stored, 

and storage condition (open/closed) were obtained from the ARB survey results. 

Spillage and vapor displacement emissions are estimated using data on the population 

of nonroad equipment assumed to be refueled with gas cans. Data on the characteristics of 

nonroad engines were used as the activity (e.g., amount of fuel consumed per day, fuel tank 

size). The calculations only account for equipment likely to be refueled with a gas can, 

instead of at the pump. Daily fuel consumption estimates by county were obtained from 

EPA's NONROAD model for the years 1996 and 2007 (EPA, 2000a). Fuel consumption 

estimates for 2005 were estimated by applying an average annual rate of change each year 

from 1996 to 2007. 

Baseline emissions for permeation, diurnal, transport-spillage, spillage and vapor 

displacement emissions were then calculated for the years 1996, 2005 and 2007. Emission 

estimates were calculated using the emission rates and equations developed by ARB. For 

the vapor displacement emission factor, an average Reid vapor pressure (RVP) of 7.8 

pounds per square inch (psi) and an average temperature of 88°F were assumed. These 

values were based on RVP and temperature values used to estimate highway vehicle 

emissions in the Philadelphia, P A SIP. 

Table 11-2 compares the emissions estimates calculated for the OTC to those calculated 

for California. The region of New York, New Jersey and Connecticut was selected for the 

comparison since they have similar residential housing unit and commercial business 

populations to California. The emission estimates for permeation, diurnal, and transportspillage for both the residential and commercial sectors are similar to those estimated for 

California. Spillage and refueling vapor displacement are estimated for both residential 

and commercial simultaneously using combined fuel consumption data calculated from the 

NONROAD model. The emission estimates for spillage and vapor displacement for NY, 

NJ, and CT are significantly higher than the emission estimates produced for California. 

This is due to higher fuel consumption estimates produced by the NONROAD model 

compared to fuel consumption from ARB's Off-Highway Emissions Estimate Model 

(OFFROAD). 

10 

Table 11-2 


Comparison of OTC and California Emission Estimates 


Residential Emissions Commercial Emissions Total by Emissions 

(tons per day [tpdD (tpd) Type (tpd) 

CT, NJ, NY CA CT, NJ, NY CA CT, NJ, NY CA 

Population 10,812,566 11 ,390,000 193,928 84,712 

Emission Type 

Permeation 6.6 6.8 1.0 0.4 7.6 7.2 

Diurnal 57.4 59.1 10.1 5.2 67.5 64.3 

Transport-Spillage 3.1 3.2 6.1 2.6 9.2 5.8 

Spillage 27.7 6.9 

Refuel Vapor Displace 7.6 2.3 

Total 67,2 69.1 17.1 8,2 119.6 86.5 

The OTC model rule requires manufacturers to comply with the requirements by 

January 1, 2003. Rule penetration can be assessed through sales and container turnover 

as consumers buy new compliant fuel containers to replace existing ones. California 

conducted an industry survey on portable fuel container sales, and determined that there 

is a five-year turnover rate for fuel containers. For the purpose of this analysis, the OTC 

chose to assume a more conservative ten-year turnover rate, with 100 percent rule 

penetration by January 1, 2013. 

For the purposes of this analysis, a constant rate of turnover was assumed (i.e., every 

year after 2003, 1110 of the total fuel containers would be replaced, until all are replaced by 

2013). Therefore, the emission benefits were calculated for July of 2005 and 2007, 2-112 

and 4-112 years, respectively, from the compliance date. The number of replaced units was 

assumed to be 0.25 and 0.45 of the total number of containers in the base year of 1996. 

ARB has identified gasoline containers as a potentially significant source of VOC 

emissions during the ozone season. Emission estimates for the five evaporative 

components (permeation, diurnal, transport-spillage, spillage and vapor displacement 

emissions) need to be allocated to a specific Source Classification Code (SCC) for reporting 

in the inventory. 

Spillage and vapor displacement emissions occur during the refueling of some nonroad 

equipment with gas cans. Spillage emissions result when fuel is spilled during the 

refueling process, and vapor displacement emissions result when new liquid added to a fuel 

tank displaces fuel vapors already present in the tank. EPA's NONROAD model calculates 

spillage and vapor displacement emissions (in addition to diurnal emissions from fuel 

present in the equipment tank). Therefore, if a State is using NONROAD to develop their 

emission inventory, evaporative VOC emissions for spillage and vapor displacement during 

nonroad equipment refueling with gas cans is already taken into account. If a State then 

added emission estimates for these components developed using ARB's method to their 

nonroad inventory, double counting of refueling emissions may occur. For States not using 

EPA's NONROAD model, the SCC-level estimates that were generated for this analysis 

using the ARB methodology can be used directly. 

11 
If a State developed VOC exhaust emission estimates for specific nonroad SCC's using 

a method besides the NONROAD model, potential overlapping SCCs reporting exhaust and 

refueling emissions would need to be identified. In these cases, the evaporative VOC 

component would need to be added to the exhaust VOC component to estimate total VOC 

emissions. The NONROAD model automatically adds the exhaust and evaporative VOC 

emissions together to estimate total VOC. 

Diurnal and permeation emissions associated with the fuel present in stored gas cans, 

and transport-spillage emissions associated with refueling of a gas can at the gasoline 

pump are not modeled in NONROAD. These emissions result during gas can storage and 

transport and are not tied directly to nonroad equipment. An EPA SCC is not available for 

gas container evaporative emissions. In the absence of an existing SCC, the diurnal, 

permeation, and transport-spillage emissions could be reported under nonroad equipment 

SCCs based on the contribution of nonroad categories to refueling emissions. Table 11-3 

shows the VOC refueling emission estimates calculated for the OTR for this analysis using 

ARB methods. The percentage contribution for each nonroad category is also presented. 

For some categories, the percent contribution is less than 1 percent. When assigning the 

remaining non-refueling emissions to SCCs, these categories could be ignored. States could 

also evaluate the refueling emissions for their own State and calculate their own refueling 

emissions distribution. If EPA's NONROAD model is used, the NONROAD model 

refueling estimates could also be used to calculate the appropriate allocation percentages. 

Table 11-3 


Summary of 1996 Refueling Emissions for the OTC States, 


and Percent Contribution for Nonroad Equipment Categories 


see see Description 

Spillage 

Emissions 

(tpd) 

Vapor 

Displacement 

Emissions 

(tpd) 

Total 

Refueling 

Emissions 

(tpd) 

% 

Refueling 

Total 

2260001 xxx 2-stroke gasoline recreational 0.197 0.163 0.360 0% 

2260003xxx 2-stroke gasoline industrial 0.000 0.001 0.001 0% 

2260004xxx 2-stroke gasoline lawn and garden 24.114 1.601 25.715 28% 

2260006xxx 2-stroke gasoline light commercial 0.189 0.049 0.237 0% 

2260007xxx 2-stroke gasoline logging 5.834 0.427 6.260 7% 

2265001 xxx 4-stroke gasoline recreational 0.021 0.043 0.064 0% 

2265003xxx 4-stroke gasoline industrial 0.097 0.503 0.601 1% 

2265004xxx 4-stroke gasoline lawn and garden 34.683 13.374 48.057 53% 

2265006xxx 4-stroke gasoline light commercial 6.389 2.119 8.509 9% 

2265007xxx 4-stroke gasoline logging 0.041 0.014 0.054 0% 

2282xxxxxx Gasoline recreational marine 0.184 0.493 0.677 1% 

Total 71.8 18.8 90.5 100% 

ARB accounts for gasoline container diurnal, permeation and transport-spillage 

emissions under a separate emission inventory code (EIC). ARB's EIC system is 

comparable to EPA's SCC reporting system. Calculations for estimating these three 

components are modeled in their OFFROAD model, which also estimates the nonroad 

equipment spillage and vapor displacement emissions. Since the emissions from a 

12 
particular gas can could potentially be associated with multiple nonroad equipment types, 

especially for residential uses, ARB decided to create a separate ErC for gasoline 

containers. 

Additional information about the ARB emission estimation methods for portable fuel 

containers is provided in Appendix A. 

3. Cost Estimates 

Sales prices of portable fuel containers were based on the ARB staff report (ARB, 

1999c). The ARB report includes both average sales prices of existing portable fuel 

containers and estimates of sales prices for containers which meet the draft model rule 

performance specifications. Costs vary based on container size. These cost estimates are 

presented in Table II-4. 

Table 11-4 


Estimated Sales Price for Portable Gas Containers 


Estimated Unit Cost of Incremental 

Average Unit Cost Container which Meets Cost to 

Size of Container Percent of Total of Container Rule Specifications Meet Rule 

(gallons) Containers (1998 $) (1998 $) Requirements 

1 - 1.5 39% $2.62 $9.00 $6.38 

2 - 2.5 36% $3.79 $12.00 $8.21 

5-6 25% $7.44 $18.00 $10.56 

The annual gas can population turnover and the estimated sales prices for each 

container are used to calculate the incremental cost of the draft model rule on an annual 

basis. The total VOC reductions for 2007 and the annual incremental cost were used to 

calculate the cost of compliance in dollars per ton. Table II-5 presents the cost of 

compliance in 1998 dollars. 

Table 11-5 


Cost of Compliance with Portable Gas Container Rule 


Estimate of 

Containers Sold in Incremental Cost VOC Reductions Cost of Compliance 

OTR Annually ($/year) (tons/year) ($/ton) 

2,282,330 $18,452,882 31,752 581 

13 

D. AIM COATINGS RULE 

1. Model Rule Summary 

The OTC Model Rule for AIM Coatings (AIM OTC Model Rule) requires manufacturers 

to reformulate coatings to meet specified VOC content limits, which are specified in grams 

per liter. The VOC content limits contained in the AIM OTC Model Rule are based on the 

Suggested Control Measure (SCM) adopted by ARB, and the State and Territorial Air 

Pollution Program Administrators/Association of Local Air Pollution Control Officials 

(STAPPAIALAPCO) model rule for AIM Coatings. 

All products manufactured for sale or use within an OTC State after January 1, 2005 

would need to comply with the VOC content limits in the AIM OTC Model Rule. A 

provision allows products to be sold that are manufactured before the rule applicability 

date. Testing to demonstrate compliance will primarily be done in accordance with EPA 

Method 24, although alternative test methods may be allowed. 

2. Analysis Methods 

Emissions for 1996 were estimated using an emission factor of 6.7 lbs/capita/yr, 

applied to county-level populations. The emission factor of 6.7 lbs/capita/yr represents a 

combined value for architectural coatings, traffic markings, and two subcategories of 

industrial maintenance coatings, including high-performance maintenance and other 

special purpose coatings. These emission factor values were obtained from EPA guidance 

(EPA, 1991). 

In 1985, the New York Department of Environmental Conservation performed an AIM 

survey in the New York Metropolitan area, and used the survey results to derive an 

emission factor of 3.1Ibs/capita. This VOC emission factor is lower than the national 

emission factor, in part, because of the high population density in New York City. This 3.1 

lbs/capita VOC emission factor was used to estimate baseline and Federal rule emission 

rates for New York counties within the New York ozone nonattainment area. Ozone 

season daily emissions were estimated by dividing annual emission estimates by 365 days 

per year. The emission generating activity is estimated to occur 7 days per week during 

the ozone season. A seasonality factor of 1.3 is applied to this source category to reflect 

higher ozone season activity for coating applications. A 1.3 factor means that average daily 

emissions are multiplied by 1.3 to estimate ozone season daily emissions. 

For 2005 and 2007, the National Rule is estimated to yield VOC reductions of 20 

percent. This value is consistent with policy issued by EPA (Seitz, 1995b), which 

recommends that States claim a 20 percent emission reduction credit for this rule. For this 

analysis, a 20 percent control effectiveness was assumed, which seems justifiable given 

that water-borne coating technology is resulting in products with VOC contents well below 

the National Rule limits. Rule penetration and rule effectiveness values are both 100 

percent for this source category, reflecting the compliance and distribution practices of this 

industry. 

14 

The equation for computing the VOC emission for AIM coatings after control by the 

National/Federal Rule is listed below: 

Post-control emission factor =Pre-control emission factor [1-CE(RP)(RE)] 


Post-control emission factor =6.7lbs/capita [1-(.2)(1.00)(1.00)] 


=5.36 lbs/capita 


The AIM Coatings model rule is estimated to provide a 31 percent VOC emissions 

reduction from the National/Federal Rule. This reduction was computed using information 

from data provided by the Industry Insights Survey for the National Paints and Coatings 

Association (Industry Insights, 1993). This same data set was used in the regulatory 

negotiation process by EPA and stakeholders when the Federal architectural coatings rule 

was established. OTC model rule emission reductions were computed on a constant solids 

basis. 

The credit for the OTC model rule affecting AIM coatings relative to the National/ 

Federal Rule was computed as shown below: 

Post OTC model rule control factor =5.36lbs/capita [1-(0.31)(1.00)(1.00)] 


=3.7 lbs/capita 


A survey of manufacturers in the OTR is presently being conducted to investigate the 

availability of AIM coatings that are compliant with the VOC limits of the AIM OTC Model 

Rule. Once final survey results are compiled and analyzed, this information may be used 

to refine the estimated AIM coatings rule benefits. Preliminary survey findings to date are 

summarized in Chapter V of this report. 

3. Cost Estimates 

A cost of $6,400 per ton ofVOC reduced was estimated based on ARB's SCM cost 

analysis. This average cost-effectiveness was weighted by emission reductions across all 

the proposed limits. Details on the assumptions used for ARB's cost analysis are provided 

in the "Staff Report for the Proposed Suggested Control Measure for Architectural 

Coatings," (ARB, 2000a). 

E. MOBILE EQUIPMENT REPAIR AND REFINISHING RULE 

1. Model Rule Summary 

The OTC has developed a model rule that addresses VOC emissions from mobile 

equipment repair and refinishing operations. The rule includes VOC limits for paints used 

in the industry that are consistent with the Federal limits for mobile equipment refinishing 

materials. The rule also establishes requirements for using improved transfer efficiency 

application equipment and enclosed spray gun cleaning, and requires minimal training. 

In addition to requiring that refinishing materials meet the Federal VOC limits, the 

model rule proposes a number of pollution prevention initiatives. For example, the coating 

application requirements specify using improved transfer efficiency spray equipment such 

15 

as high volume-low pressure (HVLP) equipment. Using higher transfer efficiency 

equipment would reduce paint use and consequently reduce painting-related emissions. 

Reduced "overspray" from painting operations would reduce the frequency of booth filter 

replacement and related disposal and replacement costs, making operations more 

economical for the facility owners. 

Operators would be required to use spray gun cleaning equipment that minimizes 

solvent loss. While commercially available spray gun cleaners are desirable, the proposal 

would allow other containers for spray gun cleaning to be used, as long as the container is 

closed when not in use. 

Operators would be required to complete minimum training in proper use of equipment 

and materials, and maintain a record of the training. The training requirement could be 

met through attending formalized training centers or through information provided by 

paint and equipment representatives during routine shop visits. 

2. Analysis Methods 

The 1996 emissions for mobile equipment repair and refinishing were estimated using 

a per capita emission factor of 2.3 pounds VOC per capita per year. This emission factor 

was obtained from 1991 EPA guidance (EPA, 1991). The National Rule promulgated in 

1998 called for VOC limits that have been incorporated into the OTC model rule. Similar 

limits are already in place in some OTC States (e.g., PA Rule 129.75). EPA estimated a 37 

percent reduction for the National Rule (Seitz, 1994). Because this rule affects 

manufacturers, a 100 percent rule-effectiveness is used, which assumes that instructions 

on how to apply the coatings are followed. In addition, rule penetration is 100 percent 

because the rule affects all sources within the category. Ozone season daily emissions were 

estimated by dividing annual emission estimates by 365, and assuming 5 days per week of 

operation. The 5 days per week assumption is applied by multiplying average daily 

emissions by 7/5. 

The equation for computing the VOC emission factor for mobile equipment repair and 

refinishing after control by the National/Federal Rule is listed below: 

Post-control emission factor =Pre-control emission factor [l-CE(RP)(RE)] 


Post-control emission factor =2.30 Ibs/capita [1-(.37)(1.00)(1.00)] 


=1.45 Ibs/capita 


Incremental to the National Rule, the OTC model rule requires the use of high 

transfer-efficiency painting methods (e.g., high volume low pressure spray guns), and 

controls on emissions from equipment (e.g., spray gun) cleaning, housekeeping activities 

(e.g., use of sealed containers for clean-up rags), and operator training. An incremental 

control effectiveness of 38 percent was estimated for the OTC model rule relative to the 

National Rule. This estimate includes a 35 percent reduction from the use of high transferefficiency spray guns and another 3 percent from the use of enclosed spray gun cleaners. 

The credit for the OTC model rule affecting mobile equipment refinishing and repair 

relative to the National Rule was computed as shown below: 

16 
Post OTC model rule control emission factor 	=1.45 Ibs/capita [1-(.38)(1.00)(1.00)] 

=0.90 Ibs/capita 

In addition, the State of Maryland had SIP rules in place by 1996 that affected all 

serious and severe nonattainment area counties, which contain limits and requirements 

comparable to the National Rule and the OTC model rule. As such, the per capita emission 

factor for these counties was adjusted for 1996, as well as for the 2005 and 2007 base cases. 

Therefore, no OTC model rule emission benefits were estimated for these Maryland 

counties. The State of Delaware had a rule for mobile equipment repair and refinishing in 

place in 1997 that affected all counties in that State. This Delaware rule contains VOC 

limits that are the same as those in the OTC model rule, but the operating requirements 

were different. Therefore, the additional requirements in the OTC model rule will yield 

VOC benefits. 

3. Cost Estimates 

A cost of $1,534 per ton of VOC reduced was estimated based on the use of HVLP spray 

guns and a gun cleaning system, as estimated for Pennsylvania for Rule 129.75. 

F. SOLVENT CLEANING OPERATIONS RULE 

1. Model Rule Summary 

The Solvent Cleaning Operations draft model rule establishes hardware and operating 

requirements and alternative compliance options for vapor cleaning machines used to clean 

metal parts. These requirements are based on the Federal maximum achievable control 

technology (MACT) standard for chlorinated solvent vapor degreasers. The requirements 

implement higher levels of technology than required under most existing State 

requirements, based on EPA's Control Technique Guidance. The cold cleaner solvent 

volatility provisions are based on regulatory programs in place in several States, including 

Maryland and Illinois. 

Vapor cleaning machines are generally used in manufacturing operations to clean soils, 

including grease, oil, waxes, and the like, from parts where the highest level of cleanliness 

is necessary. Such manufacturing operations include the electronics industry and high 

quality metal machining and finishing operations. Typically, these machines have used 

VOC and hazardous air pollutant (HAP) solvents, but as the MACT standard is 

implemented, there are indications that VOC/HAP solvents are being replaced with nonHAP VOCs. The proposed requirements would apply to operators of vapor cleaning 

machines with a solvent surface area greater than one square foot. 

In contrast, cold cleaners are used less frequently in manufacturing operations. They 

are more typically used in automobile repair and maintenance facilities, and in industrial 

maintenance shops. It is estimated that in excess of 50 percent of cold cleaning units are 

in automotive maintenance facilities. These units are either small remote reservoir 

machines or small immersion cleaning machines. The machines are useful in removing 

heavy soils where extreme cleanliness is not required. 

17 
The cold cleaner provisions would primarily affect small business and solvent 

suppliers. Most of the cold cleaning machines are provided to users through contract with 

regional and national companies. The machine providers would be responsible for assuring 

that the cold cleaner solvent meets the volatility limit. In other cases, the users and 

solvent providers would have to assure that the solvent meets the required limit. Alllimits 

would apply only to cold cleaners containing greater than one liter of solvent. 

Overall, the requirements would apply only to cold cleaners and vapor cleaning 

machines cleaning metal parts. Exemptions would be provided in situations where safety 

concerns result from using low volatility cold cleaning solvents. 

2. Analysis Methods 

Emissions for 1996 were estimated using per capita emission factors for the different 

solvent cleaning categories as follows: 

Cold Cleaning 

• Automotive Repair - 2.5 pounds per year per person (lbs/yr/person); and 

• Manufacturing - 1.1Ibs/yr/person. 

These emission factors were taken from 1991 EPA procedures guidance (EPA, 1991). 

Ozone season daily emissions were estimated by dividing annual emission estimates by 

365, and assuming 5 operating days per week. The 5 days per week assumption is applied 

by multiplying average daily emissions by 7/5. 

A MACT standard is in place that controls HAPs from this category. For this analysis, 

the VOC emission reductions due to the Federal standard are assumed to be minimal to 

negligible (e.g., most of the HAPs covered are not considered to be VOC). 

The OTC model rule establishes hardware and operating requirements for specified 

vapor cleaning machines, as well as solvent volatility limits and operating practices for cold 

cleaners. An incremental control effectiveness of 66 percent was estimated for the OTC 

model rule relative to the base case. This value is based on: (1) a previous estimate made 

by the State of Maryland for the emission reduction benefits of their solvent cleaning rule 

(mentioned below) and claimed in their SIP; and (2) an assessment made by Pechan of the 

impacts that lower vapor pressure limits will have in reducing the use of petroleum 

distillate solvents (e.g., mineral spirits). Rule penetration and rule effectiveness values are 

both 100 percent for this source category, because there are a small number of firms that 

supply the affected solvents, so a high level of compliance is expected. 

Comments received on the control effectiveness estimates above include concerns on 

the use of RP and RE values of 100 percent. The 66 percent control effectiveness reflects 

anticipated emission reductions from the cold cleaning portion of the source category which 

will be gained from the lower volatility requirements (i.e., the minimal additional emission 

benefits for vapor degreasers and from cold cleaning operating requirements were not 

factored in). Further, based on previous experience with this source category, exempt cold 

cleaners (containing less than 1 liter of solvent) are believed to contribute a negligible 

amount of the total emissions. 

18 
Another comment was on the incorporation of the effects of existing requirements (e.g., 

CTG) into the base case emission factors. As described in the following paragraphs, the 

effects of existing state rules were factored in to the base case emission factors shown in 

Table II-6. Further, since the CTG only included operating requirements for cold cleaners, 

the emission reductions attributable to it are thought to be small. 

The equation for computing the VOC emission factor for solvent cleaning after control 

by the OTC model rule is listed below: 

Post-control emission factor =Pre-control emission factor [l-CE(RP)(RE)] 


Post-control emission factor =3.6Ibs/capita [1-(0.66)(1.00)(1.00)] 


= 1.2 lbs/capita 


The credits for rules affecting solvent cleaning differed by geographic area according to 

local surveys that have been performed to quantify emissions, and when and where State 

regulations have already been implemented. 

Pechan examined 1989 EPA solvent consumption data, which many States based their 

1990 emission estimates on. These data showed that mineral spirits made up 56 percent of 

the VOC solvents (petroleum distillate solvents, such as mineral spirits, will be phased out 

based on their vapor pressure of about 40 millimeters mercury). There will also be 

additional smaller emission reductions associated with the phase out of other high vapor 

pressure VOC solvents (e.g., alcohols, ketones) and with the operating requirements for 

both cold cleaning and vapor degreasing. These smaller reductions could net another 10 to 

30 percent reductions based on the 1989 EPA solvent consumption data. Since it is not 

known what products solvent suppliers will use in the OTC to replace the popular 

petroleum distillate-based products, there is some uncertainty as to the upper end of the 

control effectiveness estimate. For example, aqueous solvents may still contain small 

amounts of VOC that can be emitted during drag out from the solvent tank. However, 66 

percent appears to be a reasonable estimate for an overall control efficiency for the model 

rule. 

In addition, the States of Maryland and Delaware had SIP rules in place by 1996 that 

apply to all serious and severe nonattainment area counties, and requires the same vapor 

pressure limits (i.e., 1 millimeter mercury) as the OTC model rule. The State of Delaware 

has a rule for solvent cleaning operations in place in 1993 that affects all Delaware 

counties. This rule is not specific to any category, but applies to all solvent degreasing 

equipment, and has no vapor pressure limit. For Maryland, the per capita emission factor 

for nonattainment area counties was adjusted by 66 percent for 1996, as well as for 2005 

and 2007 base case. Therefore, no emission benefits were estimated for these Maryland 

areas. 

3. Cost Estimates 

A cost effectiveness of $1,400 per ton ofVOC reduced was estimated based on the 

South Coast Air Quality Management District's (SCAQMD's) cost analysis for their solvent 

cleaning rule (Rule 1122) (SCAQMD, 1997). These costs correspond to the capital costs for 

aqueous cleaning technologies for batch-loaded cold cleaners (e.g., heated baths, dryers, 

rinse tanks, and skimmers). According to SCAQMD staff (Leibel, 1999), costs for the auto 

19 

repair (service station) industry, which constitutes a large fraction of this source category, 

will be close to zero based on what has occurred to date in the South Coast of California. 

G. SUMMARY 

Table II-6 summarizes the voe emission factors used in the voe model rules analyses 

for all of the affected categories except portable fuel containers. Portable fuel container 

emission estimation methods are more complex, and are summarized earlier in this 

chapter. Table II-6lists VOC emission factors for a baseline case (which is typical of 1996 

emission rates in most areas), National/Federal Rule emission factors, and OTe model rule 

emission factors. This indicates areas within the OTC where baseline, and National/ 

Federal Rule emission factors are expected to differ from the norm. 

The day-of-week and seasonality factors listed in Table II-6 are used to provide a best 

estimate of ozone season weekday emissions. 

20 

Table 11-6 


OTe voe Model Rule Analysis Assumptions: Emission Factors, Percentage 


Reductions, Day-ot-Week Factors, and Seasonality Factors 


Nationall Percent 

Baseline Federal Rule Reduction OTC Model Percent 

(1990) (EIIP) (EIIP from Rule Reduction (OTC Day-ofEmission Emission 1990 Emission Model Rule Week Seasonality 

Model Rule Factor Factor Baselinel Factor from EIIPl Factor Factor 

Mobile Equipment 

Repair & Refinishing 

2.3 1.45 

1.2 - DE only 

37% 0.9 38% 7/5 

AIM Coatings 6.7 5.36 20% 3.7 31% 7/7 1.3 

3.1 - NYC 

only 

3.1 - NYC only N/A - NYC 

only 

2.14 - NYC 

only 

Solvent Cleaning 3.6 3.6 Various 1.2 66% 7/5 

1.44 - NJ 

only 

1.44 - NJ only 

1.2 - NYC only 

2.16 - DE NC' 

3.16 - DE 

K&S" 

Consumer Products 7.84 7.06 20% 

(assumes 

48.6% rule 

penetration) 

6.06 14.2% 7/7 

NOTES: 	 VOC emission factors are in pounds per capita per year. 

Unless otherwise noted, emission and other factors are for all OTC counties included in the analysis. 

'Delaware New Castle County only. 

"Delaware Kent and Sussex Counties only. 

21 

22 

CHAPTER III 


NOx MODEL RULE ANALYSIS METHODS 


A. MODEL RULE SUMMARY 

The NOx Model Rule affects NOx emissions from industrial boiler, stationary 

combustion turbine, cement kiln, and internal combustion engine sources in the OTC. This 

model rule is intended to address the one-hour ozone standard NOx emission shortfalls 

identified by EPA and to make progress towards reducing eight-hour ozone levels. The 

rule is intended to achieve NOx reductions from stationary point sources that are not 

expected to be regulated by either the EPA NOx SIP Call or Phase III of the OTC NOx 

Memorandum of Understanding (MOD). 

The model rule proposes to reduce NOx emissions from many sources ranging in size 

from large to very small. These sources are numerous, and most emit high levels of NOx on 

a per-hour or per-unit of energy basis. Affected sources include: (1) boilers that are used 

to heat institutional, commercial, and large residential building complexes, and for heat 

and power in industrial applications; (2) small to large internal combustion engines that 

can be used as stand-alone power generation units and at pipeline compressor stations; (3) 

turbines that are typically used as on-site backup electric power generators; and (4) cement 

kilns. 

NOx emission reductions are achieved by establishing NOx emission rate limits or 

requirements for percentage NOx reductions for source categories based on size (i.e., 

number of British thermal units [Btus] per hour heat input). Table III-1 summarizes the 

OTC NOx Model Rule and provides the emission rates and size cut-offs. 

B. ANALYSIS METHOD 

1. Data Base And Sources Used In The Analysis 

The point source emission inventory that serves as the starting point for Pechan's 

analysis is version 3.12 of EPA's 1996 National Emission Trends Inventory (NET96). This 

national inventory contains process specific emission estimates for all point sources in the 

United States. State data from the NET96 inventory were provided to the States for 

review and comment. Emission inventory updates were provided by Delaware, the District 

of Columbia, New Jersey, New York, Pennsylvania, and Rhode Island. These States 

supplied Pechan with new emission inventories that were used to replace the EPA data. In 

addition, Connecticut, Maryland, Massachusetts, New Hampshire, New York, 

Pennsylvania, Vermont, and Virginia provided additional information about their point 

source inventories that included updates to emissions, additional capacity information, 

identification of sources affected by the NOx SIP Call or OTC MOU, and case-by-case 

reasonably available control technology (RACT) limits (where applicable). The data base 

23 

Table 111-1 


NOx Model Rule Summary 


Percent NO. 

Applicability Reduction 

Source Category Threshold Emission Rate Limit Required 

Industrial Boilers MMBtu/hr heat input Ibs/MMBtu heat input 

Smallest 5-50 None Tune-up Only 

Small 50-100 Gas-fired: 0.10 Ibs 50% 

Oil, Coal-fired: 0.30 Ibs 

Large 100-250 Gas-fired: 0.10 Ibs 50% 

Oil, Coal-fired: 0.20 Ibs 

Largest >250· Gas-fired: 0.171bs 50% 

Oil, Coal-fired: 0.17 Ibs 

Stationary Combustion Turbines·· 

Simple Cycle: 

Gas-fired without oil back-up 

Gas-fired with oil back-up 

Oil-fired 

Combined or Regenerative Cycle: 

Gas-fired without oil back-up 

Gas-fired with oil back-up 

Oil-fired 

Stationary IC Engines 

Spark-ignited Rich Burn 

Spark-ignited Lean Burn 

Compression Ignition Diesel Fuel 

Compression Ignition Dual-fuel 

Landfill Gas or Digester Gas 

Cement Kilns 

Long Dry 

Long Wet 

Preheater 1 

Preheater 2 

MMBtu/hr heat input 

>25 

>25 

>25 

>25 

>25 

>25 

ppm dry volume corrected to 


15% oxygen 


Ibs/MWhr 


2.2 55 

2.2 On Gas: 55 

3.0 On Oil: 75 

3.0 75 

1.3 42 

1.3 On Gas: 42 

2.0 On Oil: 65 

2.0 65 

>200 hp 

>200-2000 hp 

.:=.2000 hp 

>200 hp 

>200 hp 

>200 hp 

tons/hr 

12 

10 

16 

22 

g/bhp-hr 

1.5 

1.5 80% 

1.5 90% 

2.3 

2.3 

2.0 

Control Options: Low NOx burners installed and 

operating, or Mid-kiln firing utilized when 

operating, or 30% NOx emission reduction 

achieved, or equivalent or greater NOx removal 

efficiency. 

NOTES: 	 ·Only for boilers not subject to EPA's NOx SIP Call. 

**Emergency generators and load shaving units would not be subject to these requirements unless the combined 

potential NOx emissions of all emission units at a facility exceed the major source threshold for the specific 

nonattainment area. 

24 

was then modified by excluding the source types that are not subject to the regulation 

under the OTC draft model rule. The SCCs that were determined to be affected by the NOx 

Model Rule are listed in Appendix B. 

An evaluation of the updated emission inventory showed that several data records had 

missing emission factors and design capacities. These data elements are required for this 

analysis, since they are used to determine if and how a source is affected by the model rule. 

Missing emission factors were obtained by SCC from EPA's Factor Information Retrieval 

(FIRE) Data System (Version 6.23). Emission factors were set to the RACT emission 

limits for sources determined to be affected by State RACT requirements. Missing design 

capacities (applicability thresholds) were calculated using the emission factors and tpd NOx 

emission estimates assuming 24-hour per day operation. The NOx SIP Call affected 

sources were identified using the EPA NOx SIP Call data base, information supplied by the 

States, and where necessary, calculated design capacities. This was necessary, since it is 

assumed that the model rule does not apply to units affected by the NOx SIP Call. 

2. Existing State Rules 

State regulations affecting stationary source non-electricity generating unit (EGU) NOx 

emissions were researched and summarized in Tables 111-2 through 111-9. State regulation 

summaries were prepared for Connecticut, Delaware, District of Columbia, Maryland, 

Massachusetts, New Hampshire, New Jersey, and New York. The States of Maine, Rhode 

Island, Vermont, and Virginia were not examined for the purposes of this analysis. 

Pennsylvania regulations were examined but determined to be a case-by-case situation. 

The focus was on States that are in, or near, the three severe ozone nonattainment areas in 

the Northeast OTR. 

In several cases, State rules are expressed in units that differ from those units used to 

express model rule emission limits in Table 111-1. For these cases, conversion factors were 

applied as follows: 

Gas Turbines - Natural Gas (lbsIMMBtu) * 250 =Gas Turbines - Natural Gas (ppm) 

Gas Turbines - Oil (lbsIMMBtu) * 272 =Gas Turbines - Oil (ppm) 

Note that Tables 111-2 through 111-9 are organized using a common format for each 

State to efficiently include the State-by-State differences in these regulations in the NOx 

model rule analysis. In some instances, this organization may seem to over simplify the 

source categories and size limitations that differ from State-to-State. This structure 

matches the organization of the emission data bases being used in the analysis. 

C. METHODS APPLIED TO ESTIMATE RULE BENEFITS 

The 1996 NOx emission estimates were projected to 2005 and 2007 using the expected 

NOx SIP Call emission control levels, where applicable (e.g., 60 percent NOx control for 

industrial boilers), and SIC code based growth factors (BEA, 1995). The emissions benefits 

of the model rule were then estimated by comparing the actual source emission limits with 

the limits imposed by adoption of the model rule. The least stringent of the emission limit, 

or the percentage reduction was used to estimate the rule benefits at each unit. 

25 
Table 111-2 


Connecticut NOx RACT Regulations Summary 


State 10 Nonattainment Area Pod nox Pod Name 

Emission Limits by Size 

Size 1 Size 2 Size 3 Size 4 Units

09 50 Gas Turbines - Jet Fuel 55.00 55.00 244.80 244.80 ppm 

24 Gas Turbines - Natural Gas 75.00 75.00 225.00 225.00 ppm 

23 Gas Turbines - Oil 55.00 55.00 244.80 244.80 ppm 

14 ICI Boilers - Coal/Cyclone 0.43 0.43 0.43 0.43 Ibs/MMBtu I 

12 ICI Boilers - Coal/FBC 0.29 0.29 0.29 0.29 Ibs/MMBtu 

13 ICI Boilers - Coal/Stoker 0.38 0.38 0.38 0.38 Ibs/MMBtu 

11 ICI Boilers - CoallWall-face wet bottom 0.38 0.38 0.38 0.38 Ibs/MMBtu 

. ICI Boilers - CoallWall-face dry bottom 0.38 0.38 0.38 0.38 Ibs/MMBtu 

ICI Boilers - Coal-tangential-dry bottom 0.38 0.38 0.38 0.38 Ibs/MMBtu 

42 ICI Boilers - Coke NL NL NL NL Ibs/MMBtu 

16 ICI Boilers - Distillate Oil 0.20 0.20 0.20 0.20 Ibs/MMBtu 

45 ICI Boilers - Liquid Waste NL NL NL NL Ibs/MMBtu 

43 ICI Boilers - LPG 0.20 0.20 0.20 0.20 Ibs/MMBtu 

20 ICI Boilers - MSW/Stoker 0.20 0.20 0.20 NL Ibs/MMBtu 

17 ICI Boilers - Natural Gas 0.20 0.20 0.20 0.20 Ibs/MMBtu 

41 ICI Boilers - Process Gas 0.20 0.20 0.20 0.20 Ibs/MMBtu 

15 ICI Boilers - Residual Oil 0.25 0.25 0.25 0.25 Ibs/MMBtu 

18 ICI Boilers - Wood/Bark/Stoker NL NL NL NL Ibs/MMBtu 

22 Internal Combustion Engines - Gas-Rich Burn 2.50 2.50 2.50 2.50 g/bhp-hr 

Internal Combustion Engines - Gas-Lean Burn 2.50 2.50 2.50 2.50 g/bhp-hr 

21 Internal Combustion Engines - Oil 8.00 8.00 8.00 8.00 g/bhp-hr 

46 IC Engines - Gas Diesel LPG 8.00 8.00 8.00 8.00 g/bhp-hr 

t-:> 

0":> 

NOTES: For boilers, Size 1 =? 250 MMBtu/hour, Size 2 = 100-250 MMBtu/hour, Size 3 = 50-100 MMBtu/hour, Size 4 = 5-50 MMBtu/hour 

For turbines, Size 1 =? 250 MMBtu/hour, Size 2 = 100-250 MMBtu/hour, Size 3 = 25-100 MMBtu/hour, Size 4 = 5-25 MMBtu/hour 

For IC engines, Size 1 = ? 4,400 hp, Size 2 = 2,000-4,400 hp, Size 3 = 500-2,000 hp, Size 4 = 200-500 hp 

NL =No Limit 

The gas turbine regulations listed above apply to simple cycle turbines only. CT State regulations should be consulted for information about applicable emission limits 

for combined cycle. 
Table 111-3 


District of Columbia NOx RACT Regulations Summary 


State 10 Nonattainment Area Pod_nox Pod Name 

Emission Limits by Size 

Size 1 Size 2 Size 3 Size 4 Units

11 50 Gas Turbines - Jet Fuel 75.00 75.00 NL NL ppm 

23 Gas Turbines - Oil 75.00 75.00 NL NL ppm 

13 ICI Boilers - Coal/Stoker 0.43 0.43 NL NL Ibs/MMBtu 

ICI Boilers - CoallWall-face dry bottom 0.43 0.43 NL NL Ibs/MMBtu 

ICI Boilers - Coal-tangential-dry bottom --­

0.43 0.43 NL NL Ibs/MMBtu -­

NOTES: For boilers, Size 1 =~ 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =50-100 MMBtu/hour, Size 4 =5-50 MMBtu/hour 

For turbines, Size 1 =~ 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =25-100 MMBtu/hour, Size 4 =5-25 MMBtu/hour 

For IC engines, Size 1 =~ 4,400 hp, Size 2 =2,000-4,400 hp, Size 3 =500-2,000 hp, Size 4 =200-500 hp 

NL =No Limit 

t>:l 

-.:J 
Table 111-4 


Delaware NOx RACT Regulations Summary 


State 10 Nonattainment Area Pod_nox Pod Name 

Emission Limits by Size 

Size 1 Size 2 Size 3 Size 4 Units

10 50 Gas Turbines - Jet Fuel 88.00 88.00 88.00 88.00 ppm 

24 . Gas Turbines - Natural Gas 42.00 42.00 42.00 42.00 ppm 

23 Gas Turbines - Oil 88.00 88.00 88.00 88.00 ppm 

13 ICI Boilers - Coal/Stoker 0.40 0.40 NL NL Ibs/MMBtu 

11 ICI Boilers - CoallWall-face dry bottom 0.38 0.38 NL NL Ibs/MMBtu 

ICI Boilers - Coal-tangential-dry bottom 0.38 0.38 NL NL Ibs/MMBtu 

16 ICI Boilers - Distillate Oil 0.25 0.25 NL NL Ibs/MMBtu 

43 ICI Boilers - LPG 0.25 0.25 NL NL Ibs/MMBtu 

17 ICI Boilers - Natural Gas 0.25 0.25 NL NL Ibs/MMBtu 

41 ICI Boilers - Process Gas 0.25 0.25 NL NL Ibs/MMBtu 

15 ICI Boilers - Residual Oil 0.25 0.25 NL NL Ibs/MMBtu 

~ 

00 

NOTES: 	 For boilers, Size 1 =::: 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =50-100 MMBtu/hour, Size 4 =5-50 MMBtu/hour 

For turbines, Size 1 =::: 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =25-100 MMBtu/hour, Size 4 =5-25 MMBtu/hour 

For IC engines, Size 1 =::: 4,400 hp, Size 2 =2,000-4,400 hp, Size 3 =500-2,000 hp, Size 4 =200-500 hp 

NL = No Limit 
Table 111-5 


Massachusetts NOx RACT Regulations Summary 


State 10 Nonattainment Area Pod_nox Pod Name 

Emission Limits by Size 

Size 1 Size 2 Size 3 Size 4 Units

25 50 Gas Turbines - Jet Fuel 100.00 100.00 100.00 NL ppm 

24 Gas Turbines - Natural Gas 65.00 65.00 65.00 NL ppm 

23 Gas Turbines - Oil 100.00 100.00 100.00 NL ppm 

14 ICI Boilers - Coal/Cyclone NL NL NL NL Ibs/MMBtu 

13 Coal Stoker 0.33 0.33 0.43 NL Ibs/MMBtu 

11 ICI Boilers - CoallWall-face wet bottom NL NL NL NL Ibs/MMBtu 

ICI Boilers - CoallWall-face dry bottom 0.45 0.45 0.43 NL Ibs/MMBtu 

ICI Boilers - Coal-tangential-dry bottom 0.38 0.38 0.43 NL Ibs/MMBtu 

16 ICI Boilers - Distillate Oil 0.30 0.30 0.12 NL Ibs/MMBtu 

43 ICI Boilers - LPG 0.30 0.30 0.30 NL Ibs/MMBtu 

17 ICI Boilers - Natural Gas 0.20 0.20 0.10 NL Ibs/MMBtu 

41 ICI Boilers - Process Gas 0.20 0.20 0.10 NL Ibs/MMBtu 

15 ICI Boilers - Residual Oil 0.28 0.30 0.30 NL Ibs/MMBtu 

22 Internal Combustion Engines - Gas-Rich Burn 1.50 1.50 1.50 NL g/bhp-hr 

Internal Combustion Engines - Gas-Lean Burn 3.00 3.00 3.00 NL g/bhp-hr 

21 Internal Combustion Engines - Oil 9.00 9.00 9.00 NL g/bhp-hr 

46 IC Engines - Gas, Diesel, LPG --_. ----­ - -

9.00 9.00 -9.00 _. NL g/bhp-hr 

I'V 

co 

NOTES: 	 For boilers, Size 1 =:::: 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =50-100 MMBtu/hour, Size 4 =5-50 MMBtu/hour 

For turbines, Size 1 =:::: 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =25-100 MMBtu/hour, Size 4 =5-25 MMBtu/hour 

For IC engines, Size 1 =:::: 4,400 hp, Size 2 =2,000-4,400 hp, Size 3 =500-2,000 hp, Size 4 =200-500 hp 

NL =No Limit 
Table 111-6 


Maryland NOx RAeT Regulations Summary 


State 10 Nonattainment Area Pod_nox Pod Name 

Emission Limits by Size 

Size 1 Size 2 Size 3 Size 4 Units

24 14 ICI Boilers - Coal/Cyclone 0.70* 0.50 NL NL Ibs/MMBtu I 

11 ICI Boilers - CoallWall-face wet bottom 0.70* 0.50 NL NL Ibs/MMBtu ' 

ICI Boilers - CoallWall-face dry bottom 0.70* 0.50 NL NL Ibs/MMBtu 

ICI Boilers - Coal-tangential-dry bottom 0.70* 0.50 NL NL Ibs/MMBtu 

16 ICI Boilers - Distillate Oil 0.70* 0.25 NL NL Ibs/MMBtu 

17 ICI Boilers - Natural Gas 0.70* 0.20 NL NL Ibs/MMBtu 

41 ICI Boilers - Process Gas 0.70* 0.20 NL NL Ibs/MMBtu 

15 ICI Boilers - Residual Oil 0.70* 0.25 NL NL Ibs/MMBtu 

2:5 	 NOTES: For boilers, Size 1 =.:: 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =50-100 MMBtu/hour, Size 4 =5-50 MMBtu/hour 

For turbines, Size 1 =.:: 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =25-100 MMBtu/hour, Size 4 =5-25 MMBtu/hour 

For Ie engines, Size 1 =.:: 4,400 hp, Size 2 =2,000-4,400 hp, Size 3 =500-2,000 hp, Size 4 =200-500 hp 

NL =No Limit but subject to combustion optimization requirements 

*Non EGUs limited to: 0.70 Ibs/MMBtu during ozone season; and 0.99 during non-ozone season 

Regulations apply to person who owns or operates an installation that causes emissions of NOx and is located at premises that have total potential to emit: 

> 25 tons in Nonattainment Area 0720 (Baltimore, MD) and 6161 (Philadelphia- Wilmington-Trenton, PA-NJ-DE-MD) 


> 50 tons in Nonattainment Area 8842 (Washington, DC-MD-VA) 


> 100 tons in Nonattainment Areas 3805 (Kent & Queen Anne's Co, MD) and remainder of State of Maryland 

Table 111-7 


New Jersey NOx RACT Regulations Summary 


State 10 

34 

Nonattainment Area Pod_nox 

50 

24 

23 

14 

11 

16 

43 

17 

41 

15 

22 

21 

46 

Pod Name 

Gas Turbines - Jet Fuel 

Gas Turbines - Natural Gas 

Gas Turbines - Oil 

ICI Boilers - Coal/Cyclone 

ICI Boilers - CoallWall-face wet bottom 

ICI Boilers - CoallWall-face dry bottom 

ICI Boilers - Coal-tangential-dry bottom 

ICI Boilers - Distillate Oil 

ICI Boilers - LPG 

ICI Boilers - Natural Gas 

ICI Boilers - Process Gas 

ICI Boilers - Residual Oil 

Internal Combustion Engines - Gas-Rich Burn 

Internal Combustion Engines - Gas-Lean Burn 

Internal Combustion Engines - Oil 

IC Engines - Gas, Diesel, LPG 

Emission Limits by Size 

Units 

ppm 

ppm 

ppm 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

g/bhp-hr 

g/bhp-hr 

g/bhp-hr 

g/bhp-hr 

Size 1 

108.80 

50.00 

108.80 

0.55 

1.00 

0.45 

0.38 

0.28 

0.20 

0.20 

NL 

0.28 

1.50 

2.50 

8.00 

NL 

Size 2 

108.80 

50.00 

108.80 

0.55 

1.00 

0.45 

0.38 

0.28 

0.20 

0.20 

NL 

0.28 

1.50 

2.50 

8.00 

NL 

Size 3 

108.80 

50.00 

108.80 

0.55 

1.00 

0.43 

0.38 

0.12 

NL 

0.10 

NL 

0.30 

1.50 

2.50 

8.00 

NL 

Size 4 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

w 

"'"' 

NOTES: 	 For boilers, Size 1 =~ 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =50-100 MMBtu/hour, Size 4 =5-50 MMBtu/hour 

For turbines, Size 1 =~ 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =25-100 MMBtu/hour, Size 4 =5-25 MMBtu/hour 

For IC engines, Size 1 = 4,400 hp, Size 2 =2,000-4,400 hp, Size 3 =500-2,000 hp, Size 4 =200-500 hp 

NL = No Limit 
Table 111-8 


New York NOx RACT Regulations Summary 


State ID Nonattainment Area Pod_nox Pod Name 

Emission Limits by Size 

Size 1 Size 2 Size 3 Size 4 Units

36 50 Gas Turbines - Jet Fuel 100.00 100.00 100.00 100.00 ppm 

24 Gas Turbines - Natural Gas 50.00 50.00 50.00 50.00 ppm 

23 Gas Turbines - Oil 100.00 100.00 100.00 100.00 ppm 

14 ICI Boilers - Coal/Cyclone 0.60 NL NL NL Ibs/MMBtu 

12 ICI Boilers - Coal/FBC 0.50 0.50 NL NL Ibs/MMBtu 

13 ICI Boilers - Coal/Stoker 0.30 0.30 NL NL Ibs/MMBtu 

11 ICI Boilers - CoallWall-face wet bottom 1.00 NL NL NL Ibs/MMBtu 

ICI Boilers - CoallWall-face dry bottom 0.45 NL NL NL Ibs/MMBtu 

ICI Boilers - Coal-tangential-dry bottom 0.42 NL NL NL Ibs/MMBtu 

16 ICI Boilers - Distillate Oil 0.25 0.30 0.12 NL Ibs/MMBtu 

17 ICI Boilers - Natural Gas 0.20 0.20 0.10 NL Ibs/MMBtu 

41 ICI Boilers - Process Gas 0.20 0.20 0.10 NL Ibs/MMBtu 

15 ICI Boilers - Residual Oil 0.25 0.30 0.30 NL Ibs/MMBtu 

22 Internal Combustion Engines - Gas-Rich Burn 2.00 2.00 2.00 NL g/bhp-hr 

Internal Combustion Engines - Gas-Lean Burn 3.00 3.00 3.00 NL g/bhp-hr 

21 Internal Combustion Engines - Oil 9.00 9.00 9.00 NL g/bhp-hr 

New York City 22 Internal Combustion Engines - Gas-Rich Burn 2.00 2.00 2.00 2.00 g/bhp-hr 

Internal Combustion Engines - Gas-Lean Burn 3.00 3.00 3.00 3.00 g/bhp-hr 

21 Internal Combustion Engines - Oil 9.00 9.00 9.00 9.00 g/bhp-hr 

W 

t-:l 

NOTES: For boilers, Size 1 =~ 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =50-100 MMBtu/hour, Size 4 =5-50 MMBtu/hour 

For turbines, Size 1 =~ 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =25-100 MMBtu/hour, Size 4 =5-25 MMBtu/hour 

For IC engines, Size 1 =~ 4,400 hp, Size 2 = 2,000-4,400 hp, Size 3 =500-2,000 hp, Size 4 =200-500 hp 

NL =No Limit 

The gas turbine regulations above apply to simple cycle turbines only. NY State regulations should be consulted for information about applicable emission limits for 

combined cycle. 
Table 111-9 


New Hampshire NOx RACT Regulations Summary 


State 10 

33 

Nonattainment Area Pod_nox 

50 

24 

23 

14 

13 

11 

16 

17 

15 

22 

21 

46 

Pod Name 

Gas Turbines - Jet Fuel 

Gas Turbines - Natural Gas 

Gas Turbines - Oil 

ICI Boilers - Coal/Cyclone 

ICI Boilers - Coal/Stoker 

ICI Boilers - CoallWall-face wet bottom 

ICI Boilers - CoallWall-face dry bottom 

ICI Boilers - Coal-tangential-dry bottom 

ICI Boilers - Distillate Oil 

ICI Boilers - Natural Gas 

ICI Boilers - Residual Oil 

Internal Combustion Engines - Gas-Rich Burn 

Internal Combustion Engines - Gas-Lean Burn 

Internal Combustion Engines - Oil 

IC Engines - Gas, Diesel, LPG 

Emission Limits by Size 

Units 

ppm 

ppm 

ppm 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

Ibs/MMBtu 

g/bhp-hr 

g/bhp-hr 

g/bhp-hr 

g/bhp-hr 

Size 1 

75.00 

55.00 

75.00 

0.92 

0.30 

1.00 

0.50 

0.38 

0.25 

0.10 

0.30 

1.50 

2.50 

8.00 

8.00 

Size 2 

75.00 

55.00 

75.00 

0.92 

0.30 

1.00 

0.50 

0.38 

0.25 

0.10 

0.30 

1.50 

2.50 

8.00 

8.00 

Size 3 

75.00 

55.00 

75.00 

NL 

0.30 

NL 

0.50 

0.38 

0.12 

0.10 

0.30 

1.50 

2.50 

8.00 

8.00 

Size 4 

75.00 

55.00 

75.00 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

NL 

w 

w 

NOTES: 	 For boilers, Size 1 =~ 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =50-100 MMBtu/hour, Size 4 =5-50 MMBtu/hour 

For turbines, Size 1 =~ 250 MMBtu/hour, Size 2 =100-250 MMBtu/hour, Size 3 =25-100 MMBtu/hour, Size 4 =5-25 MMBtu/hour 

For IC engines, Size 1 =~ 4,400 hp, Size 2 =2,000-4,400 hp, Size 3 =500-2,000 hp, Size 4 =200-500 hp 

NL = No Limit 
1. 	 Exception 

Many aspects of the OTC model rule are already incorporated into the Delaware NOx 

RACT rule. Delaware opted to apply the model rule to fuel switching sources, and limits 

the emission rate to O.llbs NO)MMBtu for sources firing gaseous fuel and 0.2 lbs 

NO)MMBtu for sources firing distillate oil. This requirement does not apply to fuel 

burning equipment with a rated heat input capacity of less than 100 MMBtulhr and any 

source that is equipped with low NOx burner technology. Therefore, the Delaware rule 

applies only to three units (with design capacity of 165 MMBtulhr) at Sun Company Inc. 

Because these three units switch to natural gas during the ozone season, the Delaware rule 

limits the emission rate to O.llbs NOx MMBtu for these three units. 

2. 	 Sample Calculation 

The sample calculation below shows how emissions benefits were calculated for an 

example affected unit. The example shown is for a larger oil-fired boiler source in Coos 

County, New Hampshire. Benefits are estimated for both 2005 and 2007, assuming full 

implementation ofthe rule in 2005. Italics are used to indicate the variable names. 

Inputs provided in 1996 Emission Inventory are as follows: 

• 	 fipsst-fipscnty-plantid-pointid-stackid-segment =33-007-0001-012-912-01 

• 	 SCC =10200401 - External Combustion Boiler; Industrial; Residual Oil; Grade 6 

Oil 

• 	 SIC =2611 

• 	 Design Capacity =155 MMBtulhr - "Large" (see Table III-I) 

• 	 1996 Ozone Season Daily NOx Emission =nox_96 =0.61 tpd 

• 	 New Hampshire RACT Limit =ractlimit =0.3lbslMMBtu (for Size 2, ICI BoilersResidual Oil in Table 1II-9) 

• 	 OTC Model Rule Limit =mrlimit =0.2 IbslMMBtu OR 50 percent NOx reduced 

Step 1 - Calculate 2005 and 2007 Emissions: 

Emissions are grown from 1996 to 2005 and 2007 using Bureau of Economic Analysis 

(BEA) Activity Factors, which are based on State and 2-digit SIC codes. 

• 	 1996 BEA Activity (grow96) =290.5 

• 	 2005 BEA Activity (grow05) =326.4 

• 	 2007 BEA Activity (grow07) =333.8 

2005 Ozone Season Daily NOx (nox_OS) = 


nox_96 * (grow05 / grow96) =0.61 * (326.4/290.5) =0.685 tpd 


2007 Ozone Season Daily NOx (nox_07) = 


nox_96 * (grow07 / grow96) =0.61 * (333.8/290.5) =0.701 tpd 


Step 2 - Calculate Model Rule Benefit 

34 

The control efficiency applied is calculated from the model rule emission limit and the 

emission factor (or RACT limit). 

Applied Control Efficiency (nox_ce) = 1 - (mrlimit / ractlimit) = 1 - (0.2 I 0.3) = 0.33 or 33% 

(Because 33% is less than 50%, the emission rate limit of 0.2 IbslMMBtu (a 33 percent 

reduction) is applied.) 

2005 Model Rule Ozone Season Daily NOx (nox_05rule) = 


nox_05 *(l-nox_ce) =0.685 *(1-0.33) =0.457 tpd 


2005 Model Rule Benefit (nox_05diff) = 


twx_05 * nox_ce = 0.685 * 0.33 = 0.228 tpd 


2007 Model Rule Ozone Season Daily NOx (nox_07rule) = 


nox_07 *(1-nox_ce) =0.701 *(1-0.33) =0.467 tpd 


2007 Model Rule Benefit (nox_07diff) = 


nox_07* nox_ce =0.701 * 0.33 =0.234 tpd 


D. CEMENT INDUSTRY ANALYSIS 

As part of the model rule analysis, Pechan investigated whether there were cement 

kilns in the Northeast OTR that were not affected by the NOx SIP Call, either because they 

were outside the NOx SIP Call area, or within the SIP Call area, but below the size cutoffs 

established for NOx SIP Call rule applicability. This analysis was performed by comparing 

a recent EPA-sponsored study of the cement industry with the information in the NET96 

data base (EC/R, 2000a). Table III-10 summarizes the State-level information about 

cement kilns and clinker capacity from the EPA study. It was found that all cement kilns 

within the SIP Call area are affected by the NOx SIP Call. There is one cement plant (in 

Maine) that is outside the NOx SIP Call area, but inside the Northeast OTR. Therefore, 

the portion of the OTC NOx model rule affecting NOx emissions from cement kilns is 

expected to provide limited NOx reductions within the OTC States. 

35 

Table 111-10 


United States Cement Company 1998 Clinker Capacities by State* 


in the OTC States 


Clinker 

State (1000 tons per year) Number of Facilities Number of Kilns 

Pennsylvania 6,809 10 21 

New York 2,745 3 4 

Maryland 1,719 3 7 

Maine 392 

There are no clinker producing plants in the following States: 

District of Columbia Connecticut 

Massachusetts Vermont 

New Jersey Delaware 

Rhode Island New Hampshire 

Virginia (Northern Virginia portion) 

NOTE: -Includes gray and white plants. 

SOURCE: EC/R, 2000a. 

36 

CHAPTER IV 


EXPECTED 2005/2007 MODEL RULE EMISSION BENEFITS 

This chapter describes the results of the emission benefit calculations for the OTC 

States. For the purposes of this report, the emission reduction benefits have been 

calculated and characterized as follows: (1) emission reduction benefits within the three 

identified nonattainment areas (Baltimore, Philadelphia, and New York); (2) emission 

reduction benefits from nonattainment areas plus nearby counties generally within 100 km 

of the nonattainment areas; and (3) emission reduction benefits for all counties located in 

the OTR (OTR-wide). Emission benefit calculations were performed as described in 

Chapters II and III. 

A. SEVERE OZONE NONATTAINMENT AREA SUMMARIES 

Table IV-1 summarizes the nonattainment area-level analysis of emission benefits by 

model rule for the Baltimore, Maryland area, Philadelphia-Wilmington-Trenton area, and 

New York-Northern New Jersey-Long Island, New York-Connecticut ozone nonattainment 

area. The emission reductions listed in this table are either for 2005, or 2007, depending 

on the area's attainment date. Attainment dates are 2005 for Baltimore and PhiladelphiaWilmington-Trenton, and 2007 for New York-Northern New Jersey-Long Island. 

Expected emission reductions from the VOC model rules in the three severe ozone 

nonattainment areas range from 13 tpd in the Baltimore area to 59 tpd in PhiladelphiaWilmington-Trenton, to 120 tpd in New York-Northern New Jersey-Long Island. The two 

primary factors that affect the estimated VOC model rule emission reductions in Table 

IV-1 are the populations in the respective areas, and the extent to which some of the model 

rule affected source categories are already regulated by States beyond current Federal 

requirements. 

The NOx model rule-associated emission reductions shown in Table IV-1 range from 5 

tpd in the Baltimore area to 6 tpd in Philadelphia-Wilmington-Trenton, to 22 tpd in New 

York-Northern New Jersey-Long Island. As expected, NOx model rule reductions are 

greatest in the areas which have stationary NOx sources in the size ranges to which the 

rule applies. 

Table IV-2 provides county-level emission benefit estimates for the OTC model rules 

for the three severe ozone nonattainment areas. This table shows that for the Baltimore 

ozone nonattainment area, most of the NOx model rule benefit is expected to occur in 

Baltimore City and Howard County. Negligible NOx emission reductions are expected in 

the other Baltimore area nonattainment counties. The AIM coatings rule provides the 

most VOC reduction benefits in the Baltimore area (greater than that of the other four 

VOC rules combined). This occurs in part because mobile equipment refinishing and 

solvent cleaning operations rules have no estimated benefit in the Baltimore area. 

37 

Maryland rules already reduce VOC emissions to the limits contained in the OTC model 

rules. 

For the Philadelphia-Wilmington-Trenton nonattainment area, the solvent cleaning 

and AIM coating rules have the most significant VOC emission reduction benefits. The 

NOx model rules primarily affect industrial boiler and reciprocating internal combustion 

engine emissions in this area. 

For the New York City nonattainment area, model rule emission benefits are fairly 

evenly spread throughout the nonattainment area. The only exception to this is for the 

solvent cleaning operations rule, which has no expected benefit in the New York counties 

because of the VOC emission limits already in-place in that area. 

For industrial boilers in the three severe ozone nonattainment areas, Table IV-3 shows 

that the expected NOx benefit is 6.4 tpd for units between 100 and 250 million Btu per 

hour, and 0.8 tpd for units that are between 50 and 100 million Btu per hour. Thus, more 

than 80 percent of the emission benefit of the industrial boiler rule in the severe 

nonattainment areas is expected to be from units in the size range of 100 to 250 million 

Btu. 

Most of the benefit associated with the NOx model rule affecting gas turbines is found 

in the New York-Northern New Jersey-Long Island nonattainment area. The severe ozone 

nonattainment area emission benefit of the internal combustion engine model rule is 16 

tpd for engines 2,000 hp or above, and 3.4 tpd for engines between 200 and 2,000 hp. As 

with gas turbines, most of this emission benefit is expected in the New York-Northern New 

Jersey-Long Island ozone nonattainment area. No emission benefit from the gas turbine 

rule was found in the Baltimore area. 

The model rule affecting cement kilns does not affect any sources in the three severe 

ozone nonattainment areas of the Northeast OTR. 

Figure IV-1 illustrates the expected NOx emission reductions in each of the three 

severe ozone nonattainment areas organized by the source categories affected by NOx 

model rules. Cement kilns are not reflected in this figure because no emission reductions 

are expected in these areas from the model rule affecting that source category. 

B. WITHIN 100 KM SUMMARIES 

Emission reduction benefits were assessed for nonattainment areas plus nearby 

counties generally within 100 km of each of the nonattainment areas. EPA's Guidance for 

Implementation of the One-Hour Ozone and Pre-existing PMlO NAAQS (December, 1997) 

states that "an area in nonattainment of the one-hour NAAQS should be allowed to take 

credit for emissions reductions obtained from sources outside the designated 

nonattainment area for the post-1999 rate of progress requirement...the geographic area 

for substitution of VOC emission reductions remains at 100 km from the nonattainment 

area and the geographic area for substitution of NOx reductions remains at 200 km from 

the nonattainment area." Figure IV-2 shows which counties within 100 km of each of the 

three nonattainment areas were used for the purposes of this analysis. The respective 

38 

county assignments are shown in Table IV-4. Table IV-5lists the nonattainment area 

model rule benefits with the 100 km radius areas included. 

For the Baltimore, MD ozone nonattainment area, the large additional VOC emission 

benefit from including counties within a 100 km radius occurs because this radius captures 

the additional benefits of the model rules in the Metropolitan Washington area. 

The 100 km radius surrounding the Philadelphia-Wilmington-Trenton ozone 

nonattainment area adds 6 Maryland counties, 1 Delaware county, 10 Pennsylvania 

counties, and 2 northwest New Jersey counties, and provides an additional 35 VOC tpd 

and 1 NOx tpd of emission reductions. 

A 100 km radius around the New York City ozone nonattainment area includes parts 

of Northeast Pennsylvania, Northwest New Jersey, Southern New York State, and all of 

Connecticut and Rhode Island, and provides an additional 58 tpd VOC reduction and 6 tpd 

NOx ' 

Figure IV-3 shows the expected county-level VOC emission benefits in tpd in the 100 

km radius counties. These estimated VOC emission reductions are for the five VOC model 

rules combined. Including these counties in the analysis would gain an additional 6 tons 

NOx and 51 tons VOC for the Baltimore nonattainment area, 7 tons NOx and 94 tons VOC 

in Philadelphia-Wilmington-Trenton, and an additional 28 tons NOx and 178 tons VOC in 

the New York area. 

C. OTR-WIDE RESULTS 

State summaries of OTC model rule emission benefits are presented in Table IV-6. 

The emission benefits listed for Virginia just include the Virginia counties in the 

Washington, DC area (Northern Virginia). Benefit estimates for all other States include 

the entire State. 

Figure IV-4 shows the OTC VOC model rule expected 2005 emission reductions by 

State. The largest estimated VOC emission reductions are in the most populous States ­

Pennsylvania and New York. The height of the bars in Figure IV-4 for each State are 

proportional to population, with less-than-proportional reductions in State and sub-State 

areas that have regulations in-place that approach the stringency of the OTC model rules. 

Figure IV-5 provides a similar display for the NOx model rule. The biggest NOx model 

rule-associated emission reductions are expected in New York, followed by those in New 

Jersey and Pennsylvania. 

Table IV-7 shows the expected State-level emission benefits of the OTC NOx model 

rules by source category. For industrial boilers, the States with the biggest emission 

benefits include Pennsylvania, New York, and Maine. Maine shows a significant emission 

benefit for large boilers because this State is not included in the NOx SIP Call area. The 

vast majority of the emission benefits of this rule are expected for boilers larger than 100 

million Btu. 

39 
The State-level gas turbine results indicate that the expected emission reductions of 

this model rule will be observed in, and around, the New York-Northern New Jersey-Long 

Island nonattainment area. The expected emission reduction associated with that rule in 

areas outside the New York and Philadelphia nonattainment areas is only expected to be 

0.8 NOx tpd. 

Total NOx emission reductions in 2005 for internal combustion engines larger than 

2,000 hp for this rule amount to 23.5 tpd. New York and New Jersey account for 18.8 tpd. 

D. SUMMARY 

Figure IV-6 summarizes the expected VOC and NOx emission reductions from the OTC 

model rules for the different geographic areas that have been examined in this analysis. 

The total emission reductions in the three severe ozone nonattainment areas for all of the 

model rules combined in 2005 are 180 tons VOC per day and 32 NOx tpd. Expanding the 

analysis area to counties within 100 km of these three severe ozone nonattainment areas 

provides an additional 168 tpd in VOC emission benefits, and another 11 tpd in NOx 

emission reductions. OTR-wide model rule benefits total 533 VOC tpd and 65 NOx tpd in 

2005. 

E. VOC MODEL RULE BENEFIT SAMPLE CALCULATION 

This section provides a sample calculation of the VOC model rule benefits for one of the 

VOC rules. This example is provided for Allegheny County, Pennsylvania, which is in the 

Pittsburgh-Beaver Valley, Pennsylvania ozone nonattainment area. The sample 

calculation shown is for the MERR rule. VOC emissions for this source category are 

estimated using a per capita emission factor. The equation for estimating baseline (1996) 

emissions is listed below: 

Baseline VOC emissions (annual) =1996 county population * lbs VOC per capita emission factor 

Baseline VOC emissions (annual) 	 =(1,292,741) * 2.30 lbs VOC per capita 


=2,973,304lbs/year 


= 1,486 tons/year 


The conversion from annual tons to ozone season daily tons for MERR is made by 

dividing annual emissions by the number of days per year (365), and then multiplying this 

product by 7/5, which is the ratio ofthe total number of days in a week (7) to the number of 

days during a week when MERR facilities are expected to be operating (5). The 7/5 ratio 

converts the average daily emissions to an ozone season weekday equivalent. 

For Allegheny County, Pennsylvania, then, baseline ozone season weekday emissions 

are: 

Baseline VOC = (1,486 	tons 365 days) * 7 days/week = 5.67 tpd 

year year 5 weekdays/week 

For the 2005 analysis, MERR emissions in Allegheny County, Pennsylvania are based 

on the expected population in that year. This 2005 population is estimated by multiplying 

the 1996 population by the EGAS 4.0 model growth factor (1996 to 2005) for western 

40 

Pennsylvania. This growth factor is 1.0428. Multiplying this growth factor by the 1996 

population for Allegheny County yields a population estimate of 1,348,329 for 2005. 

In 2005, without any additional OTC rules, VOC emissions in Allegheny County are 

estimated using the national rule VOC emission factor of 1.45 lbs/capita. 

National rule 2005 VOC (annual) =2005 county population * lbs VOC per capita emission factor 

National rule 2005 VOC (annual) =(1,348,329) * (1.45 lbs VOC per capita) 

=1,955,077 lbs/yr 

=978 tons/yr 

The conversion from annual VOC tons to ozone season weekday tons is performed for 

2005 using the same methods shown above for 1996. 

National rule 2005 vac (tpd) = (978 	tons + 365 days)* 7 days/week =3.73 tpd 

year year 5 weekdays/week 

The Allegheny County, Pennsylvania VOC emissions with the OTC model rule applied 

are estimated for 2005 using an emission factor of 0.91bs VOC per capita. 

Model rule 2005 VOC (annual) =(1,348,329) (0.9Ibs VOC per capita) 

=1,213,496 lbs/yr 

=607 tons/yr 

Model rule 2005 vac (tpd) = (607 tons +365 days)* 7 days/week =2.31 tpd 

year year 5 weekdays/ week 

So, the Allegheny County, Pennsylvania VOC emission benefit for the MERR model 

rule is estimated as the national rule 2005 VOC ozone season daily emissions minus the 

model rule 2005 VOC ozone season daily emissions. This emission reduction is shown 

below: 

National rule 2005 VOC (tpd) - Model rule 2005 VOC (tpd) =Model rule associated emission reduction (tpd) 

3.73 tpd - 2.31 tpd =1.41 tpd 

41 

Table IV-1 


OTe Model Rule Estimated Benefits for Severe Ozone Nonattainment Areas 


..,. 

I>:> 

Nonattainment Area Attainment Date Model Rule 

2005/2007 Benefit (tpd) EPA Shortfall (tpd) 

NOx VOC NOx VOC 

Baltimore, MD 2005 NOx Model Rule 5 0 I 

Consumer Products 0 4 

Portable Fuel Containers 0 2 

AIM Coatings 0 8 

Mobile Equipment Refinishing 0 0 

Solvent Cleaning Operations 0 0 

Total 5 13 0 13 

Philadelphia-Wilmington­ 2005 NOx Model Rule 6 0 

Trenton,PA-NJ-DE-MD Consumer Products 0 9 

Portable Fuel Containers 0 5 

AIM Coatings 0 19 

Mobile Equipment Refinishing 0 6 

Solvent Cleaning Operations 0 20 

Total 6 59 3 62 

New York-No New Jersey-Long 2007 NOx Model Rule 22 0 

Island,NY-NJ-CT Consumer Products 0 26 

Portable Fuel Containers 0 25 

AIM Coatings 0 42 

Mobile Equipment Refinishing 0 20 

Solvent Cleaning Operations 0 7 

Total 22 120 7 85 -~- - --­ - -­ --­

NOTES: Emission benefits estimates in this table are provided as integer values. Any emission benefit of less than 0.5 tpd is listed as a zero in this table. Totals may 

not equal the sum of the individual rule benefits because of rounding. 
Table IV-2 

Model Rule Benefits for Nonattainment Areas by County for 2005 and 2007 

Nonattainment Area· Attainment Date 

NOx 

Model 

Rule 

Consumer 

Products 

Model Rule Benefit for 2005 (tons/day) 

Mobile Solvent 

AIM Equipment Cleaning 

Coatings Refinishing Operations 

Portable i Fuel i TOTAL 

Containers i VOC 

NOx 

Model 

Rule 

Consumer 

Products 

Model Rule Benefit for 2007 (tons/day) 

Mobile Solvent 

AIM Equipment Cleaning 

Coatings Refinishing Operations 

Portable I 

Fuel i Containers i 

TOTAL 

VOC 

County State NOx VOC VOC VOC VOC VOC NOx VOC VOC VOC VOC VOC 

Baltimore, MD ·2005 

Anne Arundel Co 

Baltimore Co 

Carroll Co 

Harford Co 

Howard Co 

Baltimore 

Maryland 

Maryland 

Maryland 

Maryland 

Maryland 

Maryland 

0.D1 

0.00 

0.00 

0.00 

3.52 

1.20 

4.74 

0.68 

1.05 

0.21 

0.31 

0.33 

0.99 

3.57 

1047 

2.27 

0045 

0.66 

0.71 

2.13 

7.70 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0043 

0.63 

0.15 

0.18 

0.24 

0.44 

2.08 

I 

I 

2.58 

3.96 

0.82 

1.15 

1.28 

3.55 

13.35 

0.01 

0.00 

0.00 

0.00 

3.64 

1.23 

4.88 

0.69 

1.07 

0.21 

0.31 

0.33 

1.00 

3.62 

1049 

2.30 

0046 

0.67 

0.72 

2.16 

7.80 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.78 

1.15 

0.28 

0.33 

0044 

0.80 

3.77 I 

2.96 

4.52 

0.95 

1.31 

1049 

3.96 

15.19 

Phiiadelphia.Wllmington·Trenton,PA.NJ. 

DE·MD ·2005 

..... 

CiJ 

Kent Co 

New Castle Co 

Cecil Co 

Bunington Co 

Camden Co 

Cumbenand Co 

Gloucester Co 

Mercer Co 

Salem Co 

Bucks Co 

Chester Co 

Delaware Co 

Montgomery Co 

Philadelphia Co 

Delaware 

Delaware 

Maryland 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

Pennsylvania 

Pennsylvania 

Pennsylvania 

Pennsylvania 

Pennsylvania 

0.00 

0.36 

0.00 

0.29 

0.07 

0.80 

0.01 

1.05 

1.02 

0.00 

0046 

0.89 

0.30 

0.59 

5.84 

0.17 

0.68 

0.11 

0.60 

0.72 

0.20 

0.35 

0047 

0.09 

0.83 

0.59 

0.78 

1.02 

2.11 

8.72 

0.38 

1046 

0.24 

1.29 

1.56 

0.44 

0.75 

1.02 

0.20 

1.79 

1.26 

1.69 

2.19 

4.54 

18.82 

0.07 

0.29 

0.00 

0046 

0.56 

0.16 

0.27 

0.36 

0.07 

0.64 

0045 

0.60 

0.78 

1.62 

6.34 

0048 

0.91 

0.00 

0.20 

0.24 

0.07 

0.12 

0.16 

0.03 

2.78 

1.97 

2.63 

3042 

7.07 

20.08 

0043 

0.13 

0.06 

0.33 

0.38 

0.09 

0.19 

0.27 

0.05 

0.56 

0.39 

0.45 

0.78 

0.93 

5.04 

I 

I 

1.53 

3047 

0042 

2.88 

3.47 

0.95 

1.68 

2.29 

0045 

6.60 

4.66 

6.16 

8.19 

16.28 

59.00 

0.00 

0.37 

0.00 

0.30 

0.08 

0.82 

0.01 

1.09 

1.05 

0.00 

0047 

0.91 

0.31 

0.61 

6.00 

0.18 

0.68 

0.11 

0.60 

0.73 

0.20 

0.35 

0048 

0.09 

0.84 

0.59 

0.79 

1.03 

2.12 

8.80 

0.38 

1.48 

0.25 

1.30 

1.57 

0044 

0.76 

1.03 

0.20 

1.80 

1.27 

1.70 

2.21 

4.58 

18.98 

0.07 

0.29 

0.00 

0046 

0.56 

0.16 

0.27 

0.37 

0.07 

0.64 

0045 

0.61 

0.79 

1.63 

6.38 

0048 

0.92 

0.00 

0.20 

0.24 

0.07 

0.12 

0.16 

0.03 

2.81 

1.98 

2.65 

3044 

7.13 

20.25 

0.78 

0.23 

0.11 

0.59 

0.69 

0.16 

0.34 

0049 

0.10 

1.02 

0.70 

0.82 

lAO 

1.69 

9.10 

I 

1.89 

3.60 

0.47 

3.16 

3.80 

1.03 

1.84 

2.52 

0.50 

7.11 

5.00 

6.57 

8.87 

17.16 

63.52 

I 

I 

New York·N. New Jersey·Long tsland,NY· 

NJ-CT ·2007 

Fairfield Co 

Bergen Co 

Essex Co 

Hudson Co 

Hunterdon Co 

Middlesex Co 

Monmouth Co 

Morris Co 

Ocean Co 

Passaic Co 

Somerset Co 

Sussex Co 

Union Co 

Bronx Co 

Kings Co 

Nassau Co 

New York Co 

Orange Co 

Queens Co 

Richmond Co 

Rockland Co 

Suffolk Co 

Westchester Co 

Connecticut 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New Jersey 

New York 

New York 

New York 

New York 

New York 

New York 

New York 

New York 

New York 

New York 

0.20 

0045 

0.74 

0.93 

0.60 

1.17 

0.36 

0.28 

DAD 

0.21 

0.93 

0.05 

1.24 

0.57 

5.97 

0.61 

1.98 

0.12 

1.84 

0.51 

0047 

1.60 

0.18 

21.40 

1.19 

1.21 

1.08 

0.79 

0.17 

1.00 

0.84 

0.64 

0.68 

0.69 

0.39 

0.20 

0.71 

1.70 

3.24 

1.86 

2.19 

0046 

2.82 

0.57 

DAD 

1.93 

1.28 

26.02 

2.56 

2.61 

2.33 

1.70 

0.37 

2.16 

1.82 

1.38 

1047 

1048 

0.83 

0043 

1.53 

2.12 

4.04 

2.32 

2.73 

0.58 

3.51 

0.71 

0049 

2041 

1.59 

41.19 

0.91 

0.93 

0.83 

0.61 

0.13 

0.77 

0.65 

0049 

0.52 

0.53 

0.30 

0.16 

0.55 

1.31 

2.50 

1043 

1.69 

0.36 

2.17 

0044 

0.31 

1049 

0.99 

20.07 

3.99 

0041 

0.36 

0.26 

0.06 

0.34 

0.28 

0.22 

0.23 

0.23 

0.13 

0.07 

0.24 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

6.81 

0.93 

0.84 

0.51 

0.34 

0.12 

0.58 

0.54 

0049 

DAD 

0.34 

0.28 

0.12 

0.37 

0.60 

1.23 

1.04 

1.18 

0.24 

1.16 

0.26 

0.21 

1.26 

0.84 

13.87 

I 

9.58 

6.00 

5.11 

3.70 

0.84 

4.86 

4.13 

3.23 

3.29 

3.27 

1.92 

0.97 

3040 

5.74 

11.01 

6.65 

7.79 

1.64 

9.66 

1.98 

1041 

7.10 

4.70 

107.96 

0.20 

0046 

0.77 

0.96 

0.61 

1.20 

0.36 

0.29 

0041 

0.22 

0.96 

0.05 

1.28 

0.58 

6.08 

0.63 

2.03 

0.12 

1.88 

0.52 

0048 

1.64 

0.18 

21.90 

1.20 

1.22 

1.09 

0.80 

0.17 

1.01 

0.85 

0.65 

0.69 

0.69 

0.39 

0.20 

0.72 

1.72 

3.27 

1.87 

2.21 

0.47 

2.84 

0.57 

DAD 

1.95 

1.29 

26.26 

2.58 

2.64 

2.35 

1.72 

0.37 

2.18 

1.83 

lAO 

1048 

1049 

0.84 

0044 

1.55 

2.14 

4.08 

2.34 

2.76 

0.58 

3.55 

0.72 

0.50 

2043 

1.61 

41.57 

0.92 

0.94 

0.84 

0.61 

0.13 

0.78 

0.65 

0.50 

0.53 

0.53 

0.30 

0.16 

0.55 

1.32 

2.52 

1044 

1.70 

0.36 

2.19 

0044 

0.31 

1.50 

0.99 

20.22 

4.02 

0041 

0.37 

0.27 

0.06 

0.34 

0.29 

0.22 

0.23 

0.23 

0.13 

0.07 

0.24 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

0.00 

6.87 

1.67 

1.52 

0.92 

0.61 

0.21 

1.05 

0.97 

0.89 

0.71 

0.61 

0.50 

0.21 

0.66 

1.09 

2.24 

1.88 

2.14 

0.44 

2.10 

0047 

0.39 

2.28 

1.52 

25.09 

I 

I 

I 

I 

I 

I 

i 

I 

I 

I 

I 

I 

lOAD 

6.73 

5.56 

4.00 

0.94 

5.37 

4.60 

3.65 

3.84 

3.57 

2.16 

1.07 

3.72 

6.27 

12.10 

7.54 

8.81 

1.85 

10.68 

2.20 

1.59 

8.17 

SAl 

120.01 
Table IV-3 


Nonattainment Area NOx Model Rule Benefits for Affected Sources by Source Type and Size 


Industrial Boilers 

Nonattainment Area 

Attainment 

Date 

>250 MMBtu/hr 

200512007 

Number of Baseline Model 

Affected NOx Rule NOx 

Sources (tpd) (tpd) 

NOx 

Benefit 

(tpd) 

100-250 MMBtu/hr 

2005/2007 

Number of Baseline Model 

Affected NOx Rule NOx 

Sources (tpd) (tpd) 

NOx 

Benefit 

(tpd) 

50-100 MMBtu/hr 

2005/2007 

Number of Baseline Model Rule 

Affected NOx NOx 

Sources (tpd) (tpd) 

NOx 

Benefit 

(tpd) 

Total 

Benefit 

~ 

Baltimore, MD 2005 0 0.0 0.0 0.0 18 2.6 1.4 1.2 3 0.4 0.3 0.0 1.3 

Philadelphia-WilmingtonTrenton,PA-NJ-DE-MD 2005 2 0.6 0.3 0.3 14 4.0 2.1 2.0 4 0.8 0.5 0.3 2.5 

New York-No New Jersey-Long 

Island.NY-NJ-CT 2007 4 0.7 0.3 0.3 42 7.4 4.2 3.2 16 2.5 1.9 0.6 4.1 

Total 6 1.3 0.6 0.6 74 14.0 7.7 6.4 23 3.7 2.8 0.8 7.8 

Ie Engines 

Nonattainment Area 

Attainment 

Date 

Number of 

Affected 

Sources 

>2000 HP 

2005/2007 

Baseline Model 

NOx Rule NOx 

(tpd) (tpd) 

NOx 

Benefit 

(tpd) 

Number of 

Affected 

Sources 

200-2000 HP 

2005/2007 

Baseline Model 

NOx Rule NOx 

(tpd) (tpd) 

NOx 

Benefit 

(tpd) 

Total Benefit 

~ 

*"" *"" 

Baltimore, MD 

Philadelphia-WilmingtonTrenton,PA-NJ-DE-MD 

2005 

2005 

9 

39 

4.6 

4.6 

2.2 

2.0 

2.4 

2.6 

3 

24 

2.1 

0.7 

1.0 

0.3 

1.1 

0.4 

3.5 

3.0 

New York-No New Jersey-Long 

Island,NY-NJ-CT 2007 164 23.9 10.5 13.4 95 4.3 1.4 2.9 16.3 

Total 212 33.2 14.8 18.4 122 7.1 2.7 4.4 22.8 

Turbines >250 MMBtu/hr 

200512007 

Nonattainment Area 

Attainment 

Date 

Number of 

Affected 

Sources 

Baseline 

NOx 

(tpd) 

Model 

Rule NOx 

(tpd) 

NOx 

Benefit 

(tpd) 

Baltimore, MD 2005 0 0 0 0.0 

Philadelphia-WilmingtonTrenton,PA-NJ-DE-MD 2005 16 1.1 0.7 0.3 

New York-No New Jersey-Long 

Island,NY-NJ-CT 2007 35 4.6 3.1 1.5 

Total 51 5.7 3.9 1.8 
L 

Table IV-4 


County Assignments for Analyzing Emission Reduction Benefits 


within 100 km of Nonattainment Areas 


Baltimore 

VA MD DC 


Arlington Calvert 


Fairfax Charles 


Loudoun Frederick 


Prince William Montgomery 


Stafford Prince Georges 


St. Mary's 

Washington 

Philadelphia-Wilmington-Trenton 

MD DE PA 

Caroline Sussex Adams 

Dorchester Berks 

Kent Cumberland 

Queen Annes Dauphin 

Talbot Lancaster 

Wicomico Lebanon 

Lehigh 

Northampton 

Schuylkill 

York 

New York-Northern New Jersey-Long Island 

PA NJ NY 

Carbon Warren Columbia 

Lackawanna Delaware 

Luzerne Duchess 

Monroe Greene 

Pike Orange 

Wayne Putnam 

Sullivan 

Ulster 

NJ 

Atlantic 

Cape May 

CT RI 

Hartford Kent 

Litchfield Newport 

Middlesex Providence 

New Haven Washington 

New London 

Tolland 

Windham 

45 

--- -------

Nonattainment Area 


Baltimore, MD 


Philadelphia-WilmingtonTrenton,PA-NJ-DE-MD 

,j::.. 

en 

New York-No New Jersey-Long 

Island,NY -NJ-CT 

Table IV-5 


Nonattainment Area Model Rule Benefits with 100 KM Radius Areas Included 


Attainment Date 

2005 

2005 

2007 

Model Rule 

NOx Model Rule 

Consumer Products 

Portable Fuel Containers 

AIM Coatings 

Mobile Equipment Refinishing 

Solvent Cleaning Operations 

Total 

NOx Model Rule 

Consumer Products 

Portable Fuel Containers 

AIM Coatings 

Mobile Equipment Refinishing 

Solvent Cleaning Operations 

Total 

NOx Model Rule 

Consumer Products 

Portable Fuel Containers 

AIM Coatings 

Mobile Equipment Refinishing 

Solvent Cleaning Operations 

Total 

Nonattainment Area 

2005/2007 Benefit (tpd) 

NOx 

5 

0 

0 

0 

0 

0 

5 

6 

0 

0 

0 

0 

0 

6 

22 

0 

0 

0 

0 

0 

22 

voe 

0 


4 


2 


8 


0 


0 


13 


0 


9 


5 


19 


6 


20 


59 


0 


26 


25 


42 


20 


7 


120 


NAA PLUS Additional 100 KM 

AREA 2005/2007 Benefit (tpd) 

NOx 

6 

0 

0 

0 

0 

0 

6 

7 

0 

0 

0 

0 

0 

7 

28 

0 

0 

0 

0 

0 

28 

voe 

0 

10 

6 

21 

3 

11 

51 

0 

13 

8 

29 

10 

34 

94 

0 

33 

33 

57 

26 

30 

178 

EPA Shortfall (tpd) 

NOx 

0 

3 

7 

NOTES: Emission benefits estimates in this table are provided as integer values. Any emission benefit of less than 0.5 tpd is listed as a zero in this table. Totals may not equal the sum of the individual rule 

benefits because of rounding. 

voe 

13 

62 

85 
----------------- - - --- --

Table IV-6 


OTC-wide Model Rule Benefits by State for 2005 and 2007 


Model Rule Benefit for 2005 (tons/day) Model Rule Benefit for 2007 (tons/day) 

Mobile Solvent Portable Mobile Solvent Portable 

NOx Model Consumer AIM Equipment Cleaning Fuel TOTAL NOxModel Consumer AIM Equipment Cleaning Fuel TOTAL 

Rule Products Coatings Refinishing Operations Containers VOC Rule Products Coatings Refinishing Operations Containers VOC 

State NOx voe voe voe voe voe NOx voe voe voe voe voe 


Connecticut 
 4 5 10 4 15 3 36 4 5 10 4 16 5 39 

Delaware 0 1 2 0 2 1 7 0 1 2 0 2 2 7 

DC 0 1 2 1 3 0 6 0 1 2 1 3 0 6 

Maine 7 2 4 1 6 1 14 7 2 4 1 6 2 15 

Maryland 6 7 16 1 3 4 32 6 8 16 1 3 8 36 

Massachusetts 3 9 19 7 29 5 67 3 9 19 7 29 9 72 

New Hampshire 4 2 4 1 6 1 13 4 2 4 1 6 2 14 

New Jersey 11 11 25 9 4 7 56 12 12 25 9 4 12 61 

New York 19 26 40 20 31 13 130 20 26 41 20 31 23 141 

Pennsylvania 11 17 37 13 58 10 135 11 17 37 13 58 18 144 

Rhode Island 1 1 3 1 5 1 11 1 1 3 1 5 1 11 

Vermont 0 1 2 1 3 1 7 0 1 2 1 3 1 7 

>+::­ Northern Virginia 2 3 5 2 9 2 20 2 3 6 2 9 3 22 

-l 

Total 68 85 168 60 172 48 533 70 86 170 60 173 87 575 

NOTES: Emission benefits estimates in this table are provided as integer values. Any emission benefit of less than 0.5 tpd is listed as a zero in this table. Totals may not equal the sum of the individual rule benefits because of rounding. 
Table IV-7 


OTC-Wide Model Rule Benefits for Affected Sources by Source Type and Size for 2005 and 2007 


Industrial Boilers >250 MMBtu/hr ~N~u-m7b-e-ro~f~~2700~5~N~O=x~~2~0~07~NO~x 100-250 MMBtu/hr 

Number of 2005 NOx 2007 NOx 

50-100 MMBtu/hr 

Number of 2005 NOx 2007 NOx 

Affected Benefit Benefit Affected Benefit Benefit Affected Benefit Benefit 

State Sources (tpd) (tpd) Sources (tpd) (tpd) Sources (tpd) (tpd) 

09 Connecticut 0.3 0.3 2 0.4 0.4 5 0.4 0.4 

10 Delaware o 0.0 0.0 3 0.4 0.4 o 0.0 0.0 

11 DC 7 0.0 0.0 12 0.1 0.1 o 0.0 0.0 

23 Maine 20 3.5 3.6 18 1.7 1.7 9 0.1 0.1 

24 Maryland o 0.0 0.0 22 1.3 1.3 4 0.0 0.0 

25 Massachusetts 3 0.1 0.1 53 2.6 2.6 3 0.1 0.1 

33 New Hampshire 2 0.0 0.0 11 1.1 1.1 o 0.0 0.0 

34 New Jersey 1 0.0 0.0 41 1.9 2.0 o 0.0 0.0 

36 New York 8 0.4 0.4 47 5.8 5.9 19 0.7 0.7 

42 Pennsylvania 4 1.4 1.4 31 8.0 8.3 10 0.8 0.8 

44 Rhode Island o 0.0 0.0 5 0.7 0.7 6 0.1 0.1 

50 Vermont o 0.0 0.0 o 0.0 0.0 1 0.0 0.0 

51 Virginia o 0.0 0.0 3 1.2 1.2 o 0.0 0.0 

46 5.7 5.9 248 25.1 25.7 57 2.1 2.1 

IC Engines >2000 HP 200-2000 HP 

Number of 2005 NOx 2007 NOx Number of 2005 NOx 2007 NOx 

Affected Benefit Benefit Affected Benefit Benefit 

State Sources (tpd) (tpd) Sources (tpd) (tpd) 

09 Connecticut 2 1.3 1.4 21 1.3 1.4 

10 Delaware o 0.0 0.0 o 0.0 0.0 

11 DC o 0.0 0.0 o 0.0 0.0 

23 Maine o 0.0 0.0 o 0.0 0.0 

24 Maryland 13 2.6 2.7 18 1.7 1.7 

25 Massachusetts o 0.0 0.0 o 0.0 0.0 

33 New Hampshire 44 1.7 1.8 31 0.7 0.7 

34 New Jersey 164 6.4 6.5 106 1.9 1.9 

36 New York 52 10.0 10.3 23 1.8 1.9 

42 Pennsylvania 5 0.6 0.6 o 0.0 0.0 

44 Rhode Island 6 0.3 0.4 2 0.3 0.3 

50 Vermont o 0.0 0.0 2 0.0 0.1 

51 Virginia 6 0.5 0.5 o 0.0 0.0 

292 23.5 24.1 203 7.B B.O 

Turbines >25 MMBtu/hr 

Number of 2005 NOx 2007 NOx 

Affected Benefit Benefit 

State Sources (tpd) (tpd) 

09 Connecticut 2 0.6 0.6 

10 Delaware o 0.0 0.0 

11 DC o 0.0 0.0 

23 Maine o 0.0 0.0 

24 Maryland o 0.0 0.0 

25 Massachusetts 9 0.1 0.1 

33 New Hampshire o 0.0 0.0 

34 New Jersey 43 1.2 1.2 

36 New York 9 0.6 0.6 

42 Pennsylvania o 0.0 0.0 

44 Rhode Island 2 0.0 0.0 

50 Vermont 0.0 0.0 

51 Virginia o 0.0 0.0 

66 2.5 2.6 

Cement Kilns 

Number of 2005 NOx 2007 NOx 

Affected Benefit Benefit 

State _S::.o::.u:.:r.::c::.es:.....__(>.:tp.::d:.<)__....l:(t.!:.pd;:l),--­

23 Maine 1.6 1.6 

48 

Figure IV-1 


Nonattainment Area NOx Model Rule Benefits by Source Type and Size 


16 

DSmall III Medium • Large 

14 ~ Industrial BoilersLarge - >250 MMBtu/hr 

121 

Medium - 100 - 250 MMBtu/hr 

>; Small - 50 - 100 MMBtu/hr 

C'CI 

"C-U) Turbines ­ I: 

0 10 --

U)

-

00: IC Engines- CI) 

*'" I: Large - >2000 HP \.0 CI) 

m 8 

>< 0 

z 

~ 

::s 

0:: 6 G) 

"C 

0 

:2: 

4 

2 ....--------1 

o 

Baltimore Baltimore Baltimore 

Industrial Boilers Turbines IC Engines 
[This page intentionally left blank.] 
Figure IV-2 


OTC Severe Ozone Nonattainment Areas and Nearby Counties Within 100 km 


01 

o 

, Dotted lines represent 100 km radius 

around respective Nonattainment Areas. 

Yellow: Baltimore Area 

Blue: Philadelphia-Wilmington-Trenton Area 

Green: New York-North New Jersey-Long Island Area 
Figure IV-3 


OTC Severe Ozone Nonattainment Areas and 


Expected voe (tons per day) Model Rule-Associated Reductions 


Ol 

i-' 

IJ, 

Yellow: Baltimore Area 

Blue: Philadelphia-Wilmington-Trenton Area 

Green: New York-North New Jersey-Long Island Area 
Figure IV-4 


OTC VOC Model Rule Benefits by State within the OTR for 2005 


(in tons per day) 


135~----------------------------------------------------------------------------------------------------~ 

120+1----------------------------------------------~ 

105tl--------------------------------------­

90+1----------------------------------------------~ 

75 +I------------------------------------------------~ 

01 

t--:) 60+1------------------------------~ 

45+1------------------------------~ 

30 I I}}I-I----------1 

15 I II 

o +!--------..,........ 


,,0 .1'\.0 ~ .•0 A * .0­ 0 ~ . Ib­ &-0J- ~\~0 '~0- #' ~1t' s§ ~ ~0 ..J,.0' 0-~ ~0-<;:l 0" .~

o~ ~0 r"\~ ~,»':::....:Y' ~ ~0-~ (5:'V' {:'~ ~)0 0~ $ e>Cj ~rb-~ ..s.~C8 o 	 v &cP qflf x-.flf ~0 ~ ~~ o~ ~<::

.C} _""f(j: ~ '" ~0 ~ ~0 ~' ..;;;.0 	 o~ ~" ~ Q~ 

Ell Portable Fuel Containers 

[] Solvent Cleaning Operations 

[J Mobile Equipment Refinishing 

BAlM Coatings 

[] Consumer Products 
[This page intentionally left blank.] 
Figure IV-5 

OTe NOx Model Rule Benefits by State within the OTR for 2005 

(in tons per day) 

20~------------------------------------------------------------------------------~ 

18+1--------------------------------------------------~ 

16+1--------------------------------------------------~ 

14+1--------------------------------------------------~ 

12+1----------------------------------------------------~ 

10+1--------------------------------------------~ 

8 +I----------------------------------------------------~ 

6 +1-----------------------

4 +1----------1 

2 +1----------1 

o +!------r-...,j 

BNOx Model 

Rule 

01 

CJ.:) 

-.t ~1) .~ro o1)<::' ,z;.-!P .f,..ro ~1) 0 ~o ~ .~1) 0&-CJ ~~ro '::,.,.~~ ~~ _",-1)<:'\ ~~g ~ ~ro-\ ~ ~fl} ':!:!.f ~<::' ~flf ~. f])-CJ ~~ ')10 ...l..0 ~cf, 0,g ~,fj ~~&j cP <::)'" £>10<::' o~ rt;.<::­ cP ~# *-<-'" ~ ~0-'1! .c}d- , <F ~~ ~ro ~0{S" Q~ 
Figure IV-6 


Estimated Reductions from Six OTC Model Rules in 2005 


(in tons per day) 


600 


500 


400 


>f>. 

01 	 300 


200 


100 


0--+""1........... 


Shortfalls in 3 NAAs 100 km 

-voe 


.NOx 

Total Reductions NAAs plus OTR-Wide 

CHAPTER V 

AIM COATINGS MARKET SURVEY 

This section presents results of an AIM coatings market survey for the OTR. Starting 

in December 2000, Pechan conducted a survey to investigate the availability of AIM 

coatings that are compliant with the VOC limits of the OTC Model Rule for AIM Coatings. 

A. 	 SURVEY INSTRUMENT AND METHODS 

We focused information gathering efforts on eleven product categories for which new 

VOC limits were proposed in ARB's SCM. These coating categories include: 

• 	 Flat Coatings 

• 	 Non-Flat Coatings (except high gloss) 

• 	 Lacquers (including sanding sealers) 

• 	 Industrial Maintenance Coatings 

• 	 Multi-Color Coatings 

• 	 Primers, Sealers, and Undercoaters 

• 	 Quick Dry Enamels 

• 	 Quick Dry Primers, Sealers, and Undercoaters 

• 	 Stains 

• 	 Swimming Pool Repair and Maintenance Coatings 

• 	 Wood Waterproofing Sealers 

These coating categories account for about 80 percent of the total emissions in California 

(ARB, 2000a), and in the rest of the nation. We concentrated survey efforts on 

manufacturers of flat, non-flat, and industrial maintenance coatings, which are the three 

largest categories. Major national manufacturers were also selected for the smaller 

categories. 

1. 	 How Did We Identify the Coating Manufacturers that Distribute these 

Products in the OTR? 

Based on information received from ARB concerning their 1998 AIM survey, we 

identified the top 31 national manufacturers for the above categories (ARB, 1999d). Using 

sales data compiled by ARB and released to the OTC under a data confidentiality 

agreement, a prioritized list of companies was developed. Mr. Bob Nelson of the National 

Paint and Coatings Association (NPCA) also provided assistance in identifying regional 

(i.e., OTR) AIM coating manufacturers that were not included in ARB's survey. Once a 

target list of companies was developed, survey letters were sent to the appropriate 

contacts, requesting data concerning their AIM products. Table V-I presents a list of 

companies contacted, and indicates which companies responded to the survey. 

55 
2. What Data Were Obtained from Survey Respondents? 

Data elements requested for each product included: product name; VOC content 

(VOC actual and VOC regulatory); percent solids by weight; percent solids by volume; 

density; and performance information. Companies generally provided this information by 

sending material safety data sheets and/or product information sheets. Some companies 

requested that the necessary information be accessed via their company web site. In 

addition to the above data elements, Pechan also requested any available sales data for the 

OTR states, which were ensured to be kept confidential. Table V-2 shows examples ofthe 

data obtained from the survey respondents. 

Once the product information was obtained, we categorized each product into one of 

the eleven AIM categories. This categorization was performed based on the product name 

as well as performance information. Manufacturers of multi-color coatings did not provide 

any product data for this AIM category. 

a. VOC Actual and VOC Regulatory Content 

Most companies supplied VOC content in pounds ofVOC per gallon of coating, which 

we then converted to grams ofVOC per liter of coating. This will enable comparison to the 

OTC AIM Model Rule limits, which are expressed in gil. Both VOC actual content and 

VOC regulatory content were requested. The majority of the companies provided VOC 

regulatory content. 

VOC actual content is the weight of all volatile materials less the weight of water and 

less the weight of exempt compounds per the entire volume of the coating (ARB, 1999d). 

VOC actual may also be referred to as the VOC of the material. VOC regulatory content, 

also known as VOC of the coating, is the VOC content limit or standard codified in 

architectural coating regulations. VOC regulatory content is the ratio of the weight of 

VOCs per a given volume of paint (e.g., gallon or liter) with water and exempt VOCs 

subtracted from both the numerator (weight) and denominator (volume). Formulas for 

both VOC actual and VOC regulatory are presented below. 

(Total Weight of Volatiles - Weight of Water - Weight of Exempt VOCs) VOCActual = -'------'='----'-------=--..!..-------'='---'------"---­

Total Weight of Coating 

(Total Weight of Volatiles - Weight of Water - Weight of Exempt VOCs) 

VOCRegulatory = (Total Volume of Coating - Volume of Water - Volume of Exempt VOCs) 

Expressing VOC content on a regulatory basis provides an equivalent basis for 

comparing the polluting portion of solvent-borne and water-borne coatings. In addition, 

VOC content limits codified in AIM regulations are commonly expressed as VOC 

regulatory. As such, to compare the VOC content of the survey product data with the 

limits required by the model rule, the VOC content should be on a VOC regulatory basis. 

Eighteen of the 31 AIM coating manufacturers contacted provided Pechan with the 

data requested. The product information for each company was entered into a data base to 

enable further analysis. None of the companies contacted were able to provide sales data 

for the OTR States. 

56 
B. FINDINGS 

1. Are Products Available that Meet the Limits? 

A listing of the National Rule and the OTC Model Rule VOC limits by AIM category is 

provided in Table V-3. Based on the initial survey data collected, individual products are 

available that meet OTC AIM Model Rule limits. Ideally, one would use data on the 

volume of coatings sold, in conjunction with VOC content data, to estimate potential 

emission reductions for each AIM category. Because we did not receive sales data, a more 

qualitative analysis was performed. 

Table V-4 provides a summary of the number of compliant and non-compliant products 

by AIM category. We compared the product's VOC regulatory content with the VOC limits 

of the National Rule and the OTC AIM Model Rule. When averaged across all categories, 

the percentage of products compliant with the OTC AIM Model Rule is 39 percent. 

Table V-5 presents a summary of the average VOC content, expressed on a regulatory 

basis, as well as the range of VOC content among products included in each AIM category. 

Note that there are some coating categories that include no-VOC products, as indicated by 

ranges starting with zero. 

2. How do OTC AIM Survey Results Compare to California Results? 

Table V-6 presents the percent compliant products by category in the OTR according to 

the OTC survey, for both the National AIM Rule and the OTC AIM Model Rule. These 

compliance percentages are compared to product data for California according to ARB's 

1998 survey. Compliance is determined by comparing reported VOC regulatory content per 

product to category-specific VOC emission limits required by each rule. It should be noted 

that some products may comply with the National AIM Rule through alternative 

compliance options. 

The percentage of compliant products varies per category, but the results show that 

compliant products are present in the OTC, to an extent comparable to that in California. 

In some cases the product data in the OTR States show a greater degree of compliance 

than the 1998 California product data (e.g., non-flat, industrial maintenance). Possibly, 

this is a result of new compliant product formulations being recently introduced. For some 

categories the percent of compliant products is greater in California. This may be a result 

of AIM coating rules already in place in California (i.e., SCAQMD Rule 1113) prior to 

proposal of ARB's revised SCM. 

57 

Table V-1 


List of AIM Survey Respondents 


Company Name Responded to Survey? 

ACE Hardware Corporation No 

AMERON Performance Coatings and Finishes Group Yes 

Amteco, Inc No 

Behr Process Corporation Yes 

Benjamin Moore & Co. Yes 

Bruning Paints No 

Cabot Stains Yes 

California Products Corporation Yes 

Carboline Company Yes 

Deft, Inc Yes 

Duron Paint & Wallcoverings Yes 

Fine Paints of Europe Yes 

Gaco Western, Inc. Yes 

ICI Paints NA Yes 

INSL-X Products Corporation No 

International Paints, Inc. No 

Lord Corporation No 

MABruder and Sons, Inc. Yes 

Masterchem Industries, Inc Yes 

Multicolor Specialties, Inc. No 

PPG Industries Yes 

Rust-Oleum Yes 

Sherwin-Williams Co. Yes 

Spraylet Corporation No 

Textured Coatings of America Yes 

The Flood Company No 

The Valspar Corporation No 

TNEMEC CO. Inc. Yes 

TruServ Manufacturing No 

United Gilsonite Laboratories No 

W. Zinsser & Co. No 

Yen kin-Majestic Paint Corporation No 

58 

01 

~ 

Table V-2 


Example of Data Requested 


Company 

Name Product Name Coating Name 

Coating 

Category 

Regulatory 

VOC Limit 

(R) 

Units Weight/gal 

% 

Volume 

Solids 

% 

Weight 

Solids 

Performance 

Information 

Sherwin­

~illiams Co. 

f6.-100 Exterior Latex Flat Coatings 1 149 gIl 10.9 31 48 Fade resistant, chalk resistant, blister 

resistant 

Sherwin­

~illiams Co. 

LowTemp 35 Exterior 

Latex Satin Finish 

Non-flat Coatings (except high 

gloss) 

2 102 gIl 10.3 35 47 Recommended for use on primed 

metal down to a surface and air 

emperature of 35 degrees Fahrenheit 

California 

Products 

Corporation 

~ilbur &Williams 

Lacrylic 7110 Clear 

Solvent Finish 

Lacquers (including sanding 

"ealers) 

3 680 gIl 7 12.1 17.7 non-yellowing, water, alkali, weak 

acids, and detergents 

resistant, abrasion resistant, prevents 

oxidation and discoloration 

Sherwin­

~illiams Co. 

Epo-Plex Multi-Mil 

Water Based Epoxy 

Industrial Maintenance Coatings 4 240 gIl 10.6 41 55 Moisture resistant, abrasion, chemical 

and impact resistant 

Rust-Oleum 6710 Polyurethane 

Clear Sealer 

Sealers 6 574 gIl 8 34 40 improves finishes resistance to 

hydraulic fluids, solvents, 

and chemical staining ... 

I 

i 

Sherwin­

~illiams Co. 

A-100 Exterior Oil 

Wood Primer 

Primers and Undercoaters 6 325 gIl 11.6 58 76 Resistance to peeling and blistering, 

resistance to fading and chalking 

outstanding durability 

ICI Paints 

NA 

ULTRA-HIDE Latex 

Low Lustre Interior 

Wall &Trim Enamel 

Quick-Dry Enamels 7 163 gIl 10.9 40 54 Quick dry, block resistant, washable, 

non-yellowing, low odor, low VOC, 

adhesion and moisture resistant 

Benjamin 

Moore &Co. 

Fresh Start@XID 

Penetrating Alkyd 

Primer 100 

Quick-Dry Primers, Sealers and 

Undercoaters 

8 350 gIl 13.0 66 Fast drying, mildew resistant 

Sherwin­

~illiamsCo. 

Woodscapes Ext. 

Polyurethane SemiTransparent Stain 

Stains 9 473 gIl 8.5 8 11 Mildew resistant 

California 

Products 

Corporation 

Wilbur &Williams 

RUBBERCOAT 

Chlorinated Rubber 

Swimming Pool Paint 

Swimming Pool Repair and 

Maintenance Coatings 

10 599 gIl 11.2 38 68 Durable, continuous film minimizes 

~eepagelosses 

[Textured 

Coatings of 

lAme rica 

Tex-Cote 

RainStopper 120 

-­ -­ - --­

~ood Waterproofing Sealers 11 600 gIl 6.79 10.23 11.83 ~ilane treatment to repel water and 

~alt for masonry, concrete 

and limestone ------­
Table V-3 


Summary of the National Rule and Selected aTC Model Rule 


vac Limits by AIM Category 


Coating Name 

National Rule 

VOC Limit 

(gil) 

OTC Model Rule 

VOC Limit 

(gil) 

Flat Coatings 250 100 

Non-flat Coatings (except high gloss) 380 150 

Lacquers (including sanding sealers) 680 550 

Industrial Maintenance Coatings 450 2501 

Multi-Color Coatings 580 250 

Sealers 400 200 

Primers and Undercoaters 350 200 

Quick-Dry Enamels 450 250 

Quick-Dry Primers, Sealers and Undercoaters 450 200 

Stains 550 250 

Swimming Pool Repair and Maintenance Coatings 2 

- 340 

Wood Waterproofing Sealers 600 250 

NOTES: 10TC model rule has an implementation option of 340 gIl for specialty industrial maintenance coatings. 

2The National AIM Rule does not specify a VOC content limit for this category. 

60 

Table V-4 


Summary of Number of Compliant and Non-Compliant Products by AIM Category 


Coating Name 

# of Products 

Compliant with 

National Rule 

# of Products 

Non-Compliant 

with National 

Rule1 

# of Products 

Compliant with 

Model Rule 

# of Products 

Non-Compliant 

with Model Rule 

Total # of 

Products 

Flat Coatings 108 12 45 75 120 

Non-Flat Coatings (except high gloss) 196 14 88 122 210 

Lacquers (including sanding sealers) 12 0 10 2 12 

Industrial Maintenance Coatings (250 gIl) 270 19 131 158 289 

Industrial Maintenance Coatings (340 gIl) Not applicable Not applicable 200 89 289 

Multi-Color Coatings 0 0 0 0 0 

Sealers 21 8 14 15 29 

Primers and Undercoaters 180 52 87 145 232 

Quick-Dry Enamels 22 3 12 13 25 

Quick-Dry Primers, Sealers, 

Undercoaters 

57 5 14 48 62 

Stains 76 3 22 57 79 

Swimming Pool Repair and Maintenance 

Coatings 

0 0 0 1 1 

Wood Waterproofing Sealers 20 0 1 19 20 

% Totals 89% 11% 39%2 61%2 1,079 

NOTES: 	 1Compliance as defined by meeting emission limit; some products comply with National AIM Rule through alternative 

compliance options. 

2Total compliance percentages calculated by comparing all industrial maintenance coatings to 250 gIl limit. 

61 

Table V-5 


VOC Content by AIM Category 


Coating Name 

Average of 

VOC Content 

(gIl) 

Range of 

VOC Content 

(g/l)1 

Flat Coatings 144 0-440 

Non-Flat Coatings (except high gloss) 208 0-448 

Lacquers (including sanding sealers) 522 285 - 680 

Industrial Maintenance Coatings 263 0-635 

Multi-Color Coatings 0 0 

Sealers 265 0-680 

Primers and Undercoaters 265 0-820 

Quick-Dry Enamels 333 151 - 541 

Quick-Dry Primers, Sealers, Undercoaters 321 0-508 

Stains 359 102 - 690 

Swimming Pool Repair and Maintenance Coatings 599 599 

Wood Waterproofing Sealers 377 0-600 

NOTE: 1For categories with a range starting with 0, this reflects the availability of no-VOe products within a category. 

62 

Table V-6 


Percent Compliant AIM Products for OTC Compared to 1998 ARB Survey Data 


Coating Name 

Flat Coatings 

Non-Flat Coatings (except high gloss) 

Lacquers (including sanding sealers) 

Industrial Maintenance Coatings (250 gIl) 

Industrial Maintenance Coatings (340 gIl) 

Multi-Color Coatings 

Sealers3 

Primers and Undercoaters, Sealers4 

Quick-Dry Enamels 

Quick-Dry Primers, Sealers, Undercoaters 

Stains 

Swimming Pool Repair and Maintenance 

National 

OTC States 

% 

Compliant 

90% 

93% 

100% 

93% 

Not applicable 

N/A2 

72% 

78% 

88% 

92% 

96% 

Not applicable 

AIM Rule1 

California 

% 

Compliant 

96% 

97% 

86% 

83% 

Not applicable 

100% 

64% 

80% 

87% 

62% 

87% 

100% 

OTC AIM 

OTC States 

% 

Compliant 

38% 

42% 

83% 

45% 

69% 

N/N 

48% 

38% 

48% 

23% 

28% 

0% 

Model Rule 

California 

% 

Compliant 

44% 

40% 

33% 

37% 

41% 

50% 

40% 

50% 

1% 

14% 

31% 

0% 

Wood Waterproofing Sealers 100% 80% 5% 80% 

m 

c.o 

NOTES: 'Compliance as defined by meeting emission limit; some products comply with National AIM Rule through alternative compliance options. 

2N/A =not available. 

3California's compliance percentages do not account for all sealers included in CARB's survey, since some sealers were reported under the primers, undercoaters, and sealers 

category. 

'For CARB's 1998 survey, manufacturers included sealers in the primers, undercoaters, and sealers category, so product information for sealers is included in the CARB's 

compliance percentages. 
64 

CHAPTER VI 

DIESEL FUEL SAMPLING PLAN 

During the OTC States' model rule evaluation process, the primary regional motor 

vehicle control measure that was considered was to require raising the average cetane 

number of motor vehicle diesel fuel to 50 during the ozone season. While the OTC States 

decided not to proceed with a model rule to increase cetane in diesel fuels, there was 

interest in knowing more about the potential compliance and enforcement issues 

associated with a regional diesel fuel strategy. This chapter provides some background 

information about diesel fuel regulatory issues, the diesel fuel distribution system in the 

OTC States, and makes recommendations about a diesel fuel sampling plan for the region. 

A. BACKGROUND 

Diesel fuels are made mainly from straight-run refinery components - hydrocarbons 

derived directly from the distillation of crude oil. Two main hydrocarbon fractions are used 

to make diesel fuels - the middle distillates, or gas oils, and the residual oils. To these are 

added small quantities of components from other refining processes, such as catcracking 

and hydro treating. High-speed diesel engines used in road vehicles run on distillate fuel 

from gas oil, while low-speed diesel engines used in ships and electric generators use heavy 

residual fuel oil. Diesel fuels are usually blends because the pattern of fuel demand does 

not match the output of a simple distillation refinery, and more complex refining patterns 

have to be used. Also, there is competition between products because fractions yielding 

diesel fuels are also used to make domestic and industrial heating oils and aviation fuel. 

Diesel fuel properties are highly dependent on the type of crude oil from which the diesel 

fuel is refined (Faiz, 1996). 

The relationship among fuel characteristics, engine performance, and exhaust 

emissions is complex, and there is often a trade-off between measures to control one 

pollutant, and its effect on others. Diesel engines generally tolerate a wide range in fuel 

characteristics and quality. Thus, fuel properties tend to have a minor influence on 

emissions compared with the influence of engine design and operating conditions. 

Nevertheless, the quality and composition of diesel fuel can have important effects on 

pollutant emissions. Studies of the effects of fuel on diesel emissions indicate that the fuel 

variables having the most important effects on emissions are sulfur content, cetane 

number, and the fraction of aromatic hydrocarbons contained in the fuel. Cetane number 

and aromatic hydrocarbon content are themselves closely related - fuels with high cetane 

tend to have low aromatic hydrocarbon content, and vice versa. Other fuel properties such 

as density, back-end volatility and viscosity, also affect emissions, but usually to a much 

lesser extent. In addition, use of fuel additives may have a significant impact on emissions. 

65 

B. OTC STATES DIESEL FUEL DISTRIBUTION 

There are a number of links in the highway diesel fuel distribution chain, which runs 

from the fuel source (i.e., refinery or importer) to the final dispensing location. Figure VI-I 

displays the potential connections in the distribution system, and presents estimates of the 

national number of facilities at each point in the chain (OTe-specific information was not 

available). Although most highway diesel fuel is transported from refineries to storage 

tanks at bulk terminals via the pipeline system, some fuel is transported directly from the 

refinery rack to the final location via tank truck. In some cases, highway diesel fuel is 

transported to a terminal or to a pipeline connection by barge or marine tanker. This 

method is used for imports from foreign countries, for example. In cases where pipeline 

service is limited, fuel is also shipped to the terminal by rail car. 

Figure VI-1 


Highway Diesel Fuel Distribution Chain 


t \ 

I 

t I I, 

I Barge ~m r ~~

~50,000 

Tank-Wagons 

Truck Stops Fleets (commercial, 


Stations federal/statellocal 


127 On-Highway 

Diesel Refineries 

~5,000 

/ 

~50,000 

Diesel Service 

~1350 Bulk 

Terminals 

>100,000 

Centrally-fueled 

12,000Transport 

Truck~ 

~7,000 Fuel 

Oil Dealers 

~10,000 

Bulk Plants 

»100,000 governments) Farm Tanks 

From the bulk terminal storage tanks, fuel can either be trucked directly to the final 

dispensing location or transferred by tank truck to bulk plants for later transfer to the 

final destination. Tank trucks are the largest capacity vehicles carrying diesel fuel to final 

destinations; tanks wagons are smaller capacity vehicles that are used to deliver fuel to 

smaller retailers, fleet operators, and other customers. Tanks wagons typically have a 

number of tank compartments to deliver several different fuels on a single delivery route. 

66 
In the OTC States, a significant amount of highway diesel fuel originates from nonOTC region sources. Figure VI-2 displays the Petroleum Administration for Defense 

Districts (PADD) for which the Department of Energy collects diesel fuel production data. 

All the refineries located in PADD I, which covers the Atlantic coast region that includes 

the OTC States, produce only 18 percent ofPADD I highway diesel demand (EPA, 2000b). 

Figure VI-2 


Petroleum Administration for Defense Districts (PADD) 


Modeling conducted for EPA's recent highway diesel fuel regulations suggests that 

three PADD I refineries will produce about 135,000 barrels per day of the newly required 

low-sulfur (15 parts per million [ppm]) diesel. Because highway diesel demand in PADD I 

is approximately 820,000 barrels per day, EPA forecasts about 82 percent of total highway 

diesel fuel will be imported from P ADD III, via the Colonial and Plantation pipelines, and 

through foreign imports (EPA, 2000b). 

There are two key diesel distribution factors in the OTC region that have implications 

for the design of a diesel sampling plan. First, much of the OTC's highway diesel fuel is 

supplied from non-OTC region refineries. Second, the fuel distribution system that 

handles highway diesel fuel is also used to distribute other products, some of which contain 

a high sulfur content. Sulfur contamination of highway diesel fuel from mixing of such 

products can occur at each link in the distribution system, and is cumulative. Of all of the 

links in the distribution system, the pipeline system has the greatest potential for mixing 

of highway diesel with high sulfur products. The most significant opportunity for mixing 

during pipeline shipment results from the common practice of sequentially shipping 

different products through the same line with no physical separation between the products. 

67 

There are also significant concerns related to limiting sulfur contamination in the other 

links in the distribution chain. These concerns include the potential for contamination of 

low-sulfur highway diesel fuel when it is put into a stationary storage tank, transfer line, 

vehicle tank compartment, or delivery line that previously held high-sulfur products. Due 

to existing contamination concerns, most marine vessel tank compartments used to 

transport highway diesel fuel are already dedicated for this specific fuel, and there is an 

increasing trend toward such dedication (EPA, 2000b). Sulfur contamination can also 

result from leaking valves or from the addition of fuel additives that have a high sulfur 

content. 

The extent to which such product mixing is acceptable, depends on the maximum 

allowable sulfur content of the highway diesel fuel, the sulfur level of the fuel as it leaves 

the refinery, and the sulfur content of the highest sulfur product that shares the 

distribution system with the highway diesel fuel. The highest sulfur product presenting a 

concern for highway diesel fuel is off-highway diesel fuel, which has a maximum sulfur 

content of 5,000 ppm and averages approximately 3,000 ppm sulfur. EPA's current sulfur 

cap for highway diesel fuel is 500 ppm with actual sulfur levels averaging approximately 

340 ppm. This currently represents a 1 to 10 ratio of the maximum allowable sulfur 

content of highway diesel fuel to the highest sulfur content of other products in the 

distribution chain. This ratio provides an indication of the demonstrated ability of the 

current distribution system to limit sulfur contamination in highway diesel fuel. 

EPA estimates that, in practice, its new sulfur regulations will result in highway diesel 

fuel leaving the refinery with an average sulfur concentration of approximately 7 ppm 

(EPA,2000b). This translates into at least a 11500 ratio of the maximum allowable sulfur 

contamination in highway diesel fuel to the highest sulfur level in a product that highway 

diesel fuel might come into contact with in the distribution chain. This ratio is 50 times 

the current ratio, and indicates that sulfur contamination will be a much greater issue 

with the new EPA regulations. The OTe will need to consider this sulfur contamination 

issue before setting more stringent standards if it is interested in doing so. If future sulfur 

standards are implemented for non-highway diesel fuel, or ifthe new EPA regulations 

result in the development of a separate highway diesel distribution system, then it will be 

easier to ensure compliance with a more stringent sulfur cap throughout the distribution 

chain. However, EPA's regulatory impact analysis assumes that the existing distribution 

system will be able to accommodate the new diesel fuel, and that a separate highway diesel 

system will not be developed as a result ofthe new standards (EPA, 2000b). 

The current highway diesel distribution chain has two major implications for a future 

OTe region sampling plan: (1) highway diesel fuel sampling cannot be conducted at the 

refinery level because many refineries supplying the OTe States are not located in the 

region; and (2) for any more stringent sulfur standards that the OTe may choose to 

implement, service stations and other final dispensing locations represent the only link in 

the chain where sampling can ensure that the fuel burned in highway diesel engines is 

achieving these standards. 

To address test variability concerns, EPA included a downstream tolerance of 2 ppm to 

the 15 ppm sulfur standard. Downstream of the refinery tank in which it was blended, all 

diesel fuel testing at 17 ppm or less will be considered to be in compliance with the EPA 

standard. The purpose of including this tolerance factor is to reflect measurement 

68 

variability. The standards do not, however, provide a measurement tolerance for 

refineries. The EPA does not anticipate that distributors will necessarily test for fuel 

sulfur content after each opportunity for contamination, but rather will rely on procedures 

set up to minimize the contamination, and obtaining fuel sufficiently below the standard to 

accommodate the increase in sulfur content from the contamination (EPA, 2000b). 

c. DIESEL FUEL REGULATIONS 

Diesel fuels in the OTC region are currently regulated by National standards. These 

national EPA standards, which have been in effect since October 1, 1993, apply only to fuel 

used in highway diesel engines. The regulations preclude anyone from producing, 

supplying, dispensing, transporting, or introducing into commerce highway diesel fuel that 

contains more than 500 ppm sulfur. The existing standards also protect against a rise in 

the fuel's aromatics content by setting a minimum cetane index of 40, or, alternatively, a 

maximum aromatics level of 35 volume percent. As a result of these diesel fuel standards, 

EPA estimates that the current average sulfur level in P ADD I highway diesel fuel is 

approximately 340 ppm (EPA, 2000b). Diesel fuel sold for use in non-highway applications 

has average sulfur levels of approximately 3,300 ppm. 

The Federal Government also currently imposes an excise tax of approximately 24 

cents per gallon on diesel fuel that is used on highways. Diesel fuel for off-highway use, 

such as home heating or construction, is not taxed. Certain entities, such as State and 

local governments, are exempt from paying tax on diesel fuel they use on highways. In 

order to improve upon past enforcement of diesel fuel tax collection, the Omnibus Budget 

Reconciliation Act of 1993 moved the tax collection point from the wholesale level to the 

point of removal from bulk terminal storage. In addition, EPA and the Internal Revenue 

Service agreed to require that all tax-exempt diesel fuel (both low- and high-sulfur) 

removed from a terminal after September 1994 be dyed red. Under this taxing system, the 

party that has contracted with the terminal operator to store fuel in a terminal is liable for 

the diesel fuel tax when the fuel is removed from the terminal. Ifthis fuel is subsequently 

sold for a tax-free use, the Internal Revenue Service is to refund the tax. 

EPA recently promulgated regulations controlling emissions from heavy-duty highway 

vehicles (66 FR 5001, 2001). These regulations are expected to reduce particulate matter 

and NOx emissions from heavy-duty engines by 90 and 95 percent below current standard 

levels, respectively. The new standards are based on the use of high-efficiency catalytic 

exhaust emission control devices or comparably effective advanced technologies. Because 

these devices are damaged by sulfur, the EPA regulations require reductions in the level of 

sulfur in highway diesel fuel beginning in mid-2006. 

With some exceptions, the EPA regulations mandate that refiners and importers of 

highway diesel fuel reduce the sulfur content of this fuel to 15 ppm by June 1, 2006. The 

regulations incorporate the following exceptions: (1) refiners/importers can produce a 

maximum of 20 percent of their highway diesel fuel at the current 500 ppm standard 

between June 1, 2006 and May 31,2010, with the remainder meeting the 15 ppm 

specification; and (2) companies that meet the definition of "small refiner" can continue to 

produce 500 ppm highway diesel fuel until May 31, 2010, provided that the small refiner 

certifies that ample supplies of 15 ppm highway diesel fuel will be available in its P ADD 

69 

from other suppliers. By May 31, 2010, all highway diesel fuel must meet the 15 ppm 

sulfur mandate, and all exceptions to the general rule will expire. 

In addition, a refiner or importer may generate sulfur credits for the early introduction 

of 15 ppm highway diesel fuel or for producinglimporting more than 80 percent of its 

production at the 15 ppm standard. These sulfur credits may be bought and sold by 

refiners and importers. As a result, a refiner that does not meet the 80 percent production 

mandate may purchase another refiner's credits to come into compliance with the mandate. 

All credits must be used by May 31, 2010. 

As part of the new diesel fuel sulfur program, EPA identified both the sampling 

methods and the test methods that will be used in determining compliance at all points in 

the distribution system. The new highway diesel sulfur regulations adopt the sampling 

methods that are used for EPA's Tier 2/Gasoline Sulfur rule (65 FR 6797, 2000). These 

sampling methods are ASTM D 4057-95 (manual sampling) and D 4177-95 (automatic 

sampling from pipelines/in-line blending). The designated compliance test method is called 

"Test Method for Total Sulfur in Liquid Aromatic Hydrocarbons and Their Derivatives by 

Oxidative Combustion and Electrochemical Detection," or ASTM D 6428-99. This test 

method would be the one that EPA would utilize in its own laboratory in order to 

determine whether a given sample taken at any point in the distribution system is in 

compliance with the appropriate diesel sulfur standard. EPA also allows the use of 

alternative test methods as long as they are correlated to EPA's designated test method. 

Although the final regulations provide that the primary determinant of compliance with 

the standards will be the approved regulatory test methods, other information may also be 

used under the rule. Such other information could include test results using nondesignated test methods. Under the rule, evidence from the non-regulatory test method 

could be used to establish the diesel fuel's sulfur level that would have resulted if the 

regulatory test method had been conducted. Similarly, absent sulfur test results using the 

regulation method, commercial documents asserting the sulfur level of diesel fuel or 

additive could be used as some evidence of the product's sulfur level if it had been tested 

using the regulatory method. EPA is requiring that refiners and importers provide 

information on commercial product transfer documents that identifies diesel fuel 

distributed for use in motor vehicles and that states that the fuel complies with the 15 ppm 

sulfur standard. 

If a violation of the rule is detected through random testing or other means, all parties 

in the distribution chain for that location are presumed liable for the violation. If a 

violation is detected at a retail outlet, for example, the diesel marketer, transporter, 

supplier, and refiner are all deemed liable. The rule identifies several types of evidence 

that can serve to defend against liability: 

• 	 The violation was not caused by the person or the person's employee or agent; 

• 	 Product transfer documents account for the fuel and/or additive found to be in 

violation and indicate that the violating product was in compliance with the 

applicable requirements when it was under the person's control; and 

• 	 A quality assurance sampling and testing program was conducted. 

70 
A quality assurance sampling and testing program entails periodic sampling and testing to 

ensure that the highway diesel fuel or additive the person sold, dispensed, supplied, stored, 

or transported, meets the applicable sulfur standards. Although a quality assurance 

sampling and testing program is not required by the final rule, such a program will 

strengthen the defense to an alleged violation of the regulation. 

D. FUEL REGULATIONS IN OTHER STATES 

1. Georgia Gasoline 

Georgia has a 2-phased program for counties in and around the Atlanta ozone 

nonattainment area that requires lower sulfur gasoline than is required by Federal 

regulations. Gasoline sold in a 25 county area is regulated by phase 1 requirements that 

began in 1999. The volume-weighted average sulfur content of gasoline is limited to 150 

ppm during the ozone season. There are 25 Georgia counties subject to this gasoline 

regulation in 1999. 

Phase 2 requirements set to achieve additional reductions in gasoline-powered vehicle 

exhaust will go into effect on April 1, 2003. To achieve this, the volume-weighted average 

sulfur content of gasoline will be limited to 30 ppm by weight and a 150 ppm gallon cap. 

This fuel will be required year-round and is consistent with the recent EPA proposal for a 

national sulfur control program. The area subject to this Georgia gasoline regulation in 

2003 will include the 25 counties affected by the phase 1 requirements, plus 20 additional 

counties. 

2. Texas Low Emission Diesel 

Texas will require low-emission diesel fuel Statewide for on-road use. In addition, 

Texas's revisions to its low-emission diesel rules will require low-emission diesel fuel for 

both on-road and non-road use in the eight counties in the Houston-Galveston area ozone 

nonattainment area, the four counties of the Dallas-Ft. Worth ozone nonattainment area, 

the three counties of the Beaumont-Port Arthur ozone nonattainment area, and 95 

additional central and eastern Texas counties. 

To comply with the State low-emission diesel regulations, diesel fuel producers and 

importers must ensure that the diesel fuel delivered to the low-emission diesel fuel zone 

meets the specifications in the Texas rules. These rules require that, beginning May 1, 

2002, diesel fuel produced for delivery and ultimate sale to the consumer in the affected 

area shall not exceed 500 ppm sulfur, must contain less than 100 percent by volume of 

aromatic hydrocarbons, and must have a cetane number of 48 or greater. In addition, 

these rules will require that the sulfur content in the diesel fuel supplied to the Dallas-Ft. 

Worth, Beaumont-Port Arthur, and Houston-Galveston area ozone nonattainment areas 

and 95 central and eastern Texas counties be reduced to 15 ppm sulfur beginning June 1, 

2006. Also, these rules require diesel fuel producers and importers who provide fuel to the 

affected areas to register with the Texas Natural Resource Conservation Commission 

(TNRCC) and provide quarterly status reports. 

71 
The Texas rules will restrict the registration, reporting, and testing requirements of 

these programs to those persons who have direct control over changes in fuel content; i.e., 

those persons who produce or import fuel into the State. 

If a new Federal diesel fuel sulfur rule is adopted that covers the areas in Texas that 

are affected by this rule, and the Federal rule is at least as stringent as these rules, then 

the commission may consider compliance with the national rule equally effective and may 

repeal the State sulfur requirements for diesel fuel. 

Regarding compliance, Texas rules require all parties in the distribution chain to 

maintain copies or records of product transfer documents for a minimum of two years. 

Each party in the distribution chain is required to comply with the rules, and, as with any 

rule, is subject to enforcement action for a violation. The TNRCC will enforce the 

requirements after the compliance date and will take appropriate action for noncompliance 

situations. 

No statistical-based sampling is planned in Texas. The primary compliance 

mechanisms are quarterly reports that diesel fuel suppliers are required to provide to the 

TNRCC, and TNRCC Regional Office inspections. Regional office enforcement is expected 

to be via random sampling. 

3. Arizona - Cleaner Burning Gasoline 

The Arizona Cleaner Burning Gasoline (CBG) program was adopted by the Arizona 

State Legislature to respond to EPA's classification ofthe Phoenix Metropolitan area as a 

serious nonattainment area for both carbon monoxide and ozone. Implementation and 

enforcement of the Arizona CBG began in the Phoenix Metropolitan area on May 1, 1999. 

Arizona receives all of its gasoline supply from two basic sources: the West pipeline 

suppliers (primarily Southern California refiners) and the East pipeline suppliers 

(predominately Gulf Coast refiners). The West pipeline runs from Southern California to 

Yuma and then to Phoenix. The East pipeline runs from EI Paso, Texas to Tucson, and 

then to Phoenix. Of the approximately 1.5 billion gallons of Arizona CBG that are piped or 

transported to, and consumed within, the CBG Covered Area each year, roughly 70 percent 

comes from the West pipeline and 30 percent comes from the East pipeline. 

Arizona CBG can technically be anyone of the following types, or formulations, of 

gasoline: 

Federal Phase 2 Reformulated Gasoline, or Federal Phase 2 Reformulated Gasoline is 

a basic formulation that is produced in such a way (as regulated by the Federal EPA) as to 

limit the quantity or levels of those compounds and characteristics of gasoline that lead to 

poor emissions. All Federal Phase 2 Reformulated Gasoline must pass the Federal 

Complex Model for use within a controlled area. 

CARB (California Air Resources Board) Phase 2 is a formulation that is currently 

being used throughout California. It is formulated in such a way as to further limit 

various parameters of a gasoline blend which leads to a greater emissions reduction from 

motor vehicles. CARB Phase 2 gasoline is viewed as superior to other types of 

72 
reformulated gasolines, including Federal Phase 2, and is considered the "cleanest 

burning" gasoline formulation available to date. 

Predictive Model Formulations, or PM gasoline, are very similar to CARB Phase 2 

gasoline, but differ in that the refiner is given leeway to deviate from the limits imposed on 

each compound or characteristic of CARB Phase 2, while the resultant emissions reduction 

meets the required emission expectations of the California Predictive Model. 

The Arizona CBG program comprehensively tracks every shipment of gasoline, by 

batch, to and sold within the CBG Covered Area from the refinery gate and to the retail 

outlets within the CBG Covered Area. 

It is the job of the Arizona Department of Weights and Measures, in consultation with 

the Arizona Department of Environmental Quality, to enforce the Arizona CBG rule (ACC, 

Title 20, Chapter 2, Article 7). This is accomplished by: (1) tracking the production and 

distribution of CBG into and throughout the CBG Covered Area; (2) monitoring fuel quality 

compliance at the retail end; (3) reviewing RFG Survey Association "surveys" year round; 

and (4) performing quality assurance "audits" throughout the CBG distribution system 

from refineries to oxygenate blending facilities. 

4. California Diesel Fuel Regulations 

ARB adopted diesel fuel regulations in 1988. These regulations are estimated to 

reduce sulfur dioxide emissions by 82 percent, particulate matter (PM) emissions by 25 

percent, and NOx emissions by 7 percent (ARB, 2001). California diesel fuel also reduces 

emissions of several toxic pollutants, including polynuclear aromatic hydrocarbons. These 

regulations took effect in 1993, the same year as the current Federal diesel fuel 

regulations. The Federal diesel rule, however, only reduces PM emissions by 5 percent and 

does not reduce NOx emissions. 

a. Diesel Fuel Standards 

There are two principal components of California's highway diesel fuel standards: (1) 

the fuel's maximum sulfur content is set at 0.05 percent (this is the same level as the 

current Federal standards); and (2) the fuel's aromatic hydrocarbon content is capped at 10 

percent, which is about one-third the level ofpre-1993 diesel fuel (ARB, 1997). A 

proportion of the total diesel fuel volume produced by "small refiners" is exempt from the 

aromatic hydrocarbon content limit. 

Unlike the refineries in the OTC States, California's refineries normally produce 

sufficient amounts of diesel fuel to meet in-State d~mand. However, diesel fuel can be 

imported into the State as long as it meets ARB's requirements. If a refinery is unable to 

produce sufficient diesel due to circumstances beyond its control, it can request a 

temporary variance from ARB to produce or import diesel that does not meet ARB's 

standards. 

The aromatic hydrocarbon standards can be met through diesel fuel that exceeds the 

10 percent aromatic limit if the fuel formulation meets requirements specified by ARB. 

These requirements specify that the producer/importer certify each alternative fuel 

73 

formulation with ARB. This certification requires that exhaust emissions testing using the 

fuel formulation results in NOx emissions, PM emissions, and the soluble organic fraction 

of PM emissions that are equivalent or less than those resulting from emissions tests using 

ARB's reference fuel. In addition, the producer/importer must specify the following limits 

that the alternative fuel must meet: 

• an alternative aromatic hydrocarbon limit; 

• a polycyclic aromatic hydrocarbon limit; 

• a nitrogen content limit; and 

• a minimum cetane number. 

The producer/importer must also identify all of the fuel additives and their concentrations 

in the alternative fuel. Actual concentrations must not be less than those specified for the 

alternative fuel formulation (except for an additive demonstrated by the applicant to have 

the sole effect of increasing the cetane number). 

b. Testing and Recordkeeping Requirements 

ARB's regulations require that producers/importers sample and test each highway 

diesel final blend produced/shipment imported for aromatic hydrocarbon content using 

ASTM D-5186-96. Producers/importers are required to maintain records on these samples 

for a period of two years from the date of the sampling. When producers selVsupply nonhighway diesel fuel with an aromatic hydrocarbon content exceeding the ARB's standard, 

they must maintain records for two years that demonstrate that the fuel was not highway 

diesel fuel. Producers/importers are required to provide these records to ARB within 20 

days of a written request. Producerslimporters that fail to provide these records, are 

presumed to have sold diesel fuel blends that violate the regulations. 

c. Compliance/Enforcement 

The diesel fuel regulations state that ARB may perform any sampling and testing 

needed to determine compliance with the standards, and that they can require that special 

samples be drawn and tested at any time. ARB has specified the use of ASTM Test 

Method D 2622-94 to identify compliance with the diesel fuel sulfur content limits. ARB 

has specified the use of ASTM D 5186-96 to identify compliance with the diesel fuel 

aromatic hydrocarbon limits. 

Discussions with ARB compliance division staffindicate that ARB does not utilize a 

statistical-based method for compliance testing (Lum, 2001). Instead, ARB develops a 

random testing schedule at the beginning for each calendar year. This schedule places 

more emphasis on the Southern California area because of the severity of the air pollution 

problem in this region. ARB indicates that they also respond to reports of "suspicious 

activity" and target facilities that have had a poor compliance record in the past. ARB 

compliance personnel also indicate that statistical sampling is not used for reformulated 

gasoline standard compliance testing. 

74 
E. CONCLUSIONS 

The RFG Survey Association is a not for profit trade association. Its members include 

refiners, importers, and blenders of reformulated, or cleaner burning, gasolines. The 

association's mission is to efficiently and effectively design and implement compliance 

survey programs for government or industry. This association currently performs the 

compliance programs for the Federal Reformulated Gasoline program and Arizona's CBG 

program, among others. It is recommended that the OTC States use this organization to 

develop a compliance program/sampling program for any regional diesel fuel program that 

it wants to implement. The RFG Survey Association can design a sampling plan, but it 

would need to know whether the regional program affects on-road, or non-road diesel (or 

both) and what diesel characteristics are being regulated (sulfur, cetane, aromatics, etc.). 

A diesel fuel sampling plan would be expected to differ from a gasoline sampling plan 

in that there are fewer retail stations that sell diesel. On the other hand, diesel can be 

stored in tanks at commercial facilities, farms, and residences because the fuel is much less 

volatile than gasoline. However, the 1999 Federal regulations affecting fuel storage tanks 

will make it much less likely with time that small fuel users will have their own tanks 

(because of liability issues). It is expected that any sampling plan designed by the RFG 

Survey Association would be based on the primary sampling being at the point of 

consumption (retail sites). 

75 

76 

CHAPTER VII 

CAVEATS AND UNCERTAINTIES ASSOCIATED 


WITH THE ANALYSIS 


The VOC model rule analysis uses per capita VOC emission factors to estimate current 

and future year emissions from model rule affected source categories in the OTC States. 

This method was chosen in order to produce straightforward emission estimates and to 

have calculation methods that are consistent throughout the study region. These estimates 

may differ from those that have been made by the individual States and published in SIPs. 

EPA guidance allows States some discretion in the VOC emission estimation factors, per 

employee emission factors, and State or local surveys. State inventories that used per 

employee emission factors, or surveys to estimate VOC emissions, may not match those 

presented in this report. 

The NOx model rule analysis presented in this report is the product of an extensive 

data exchange and review process during the project period among the OTC States and 

Pechan. This data exchange, and the resulting 1996 NOx emissions data base, has greatly 

improved our ability to identify the NOx sources, and associated emissions, that are likely 

to be affected by the NOx model rules. Some uncertainties in NOx emission benefit 

estimates still exist; for example, consistent assumptions were used where design 

capacities were not available for specific sources. NOx control efficiency estimates 

associated with source category-control strategy combinations are represented as point 

estimates. 

77 

78 

REFERENCES 


ARB, 1997: California Air Resources Board, "The California Diesel Fuel Regulations, Title 

13, California Code of Regulations, Sections 2281 and 2282," June 4, 1997. 

ARB, 1999a: California Air Resources Board, "Initial Statement of Reasons for Proposed 

Amendments to the California Consumer Products Regulation," Stationary Source 

Division, September 1999. 

ARB, 1999b: California Air Resources Board, "Public Meeting to Consider Approval of CA's 

Portable Gasoline-Container Emissions Inventory," Mailout MSC 99-25, Mobile Source 

Control Division, September 1999. 

ARB, 1999c: California Air Resources Board, "Initial Statement of Reason for Proposed 

Rule Making Public Hearing to Consider the Adoption of Portable Fuel Container 

Spillage Control Regulations." August 6, 1999. 

ARB, 1999d: California Air Resources Board, "1998 Architectural Coatings Survey, Final 

Report," September 1999. 

ARB, 2000a: California Air Resources Board, "Staff Report for the Proposed Suggested 

Control Measure for Architectural Coatings, Volume II, Technical Support Document, 

Section VIII, Economic Impacts," June 2000. 

ARB, 2000b: California Air Resources Board, "Proposed Determination of Reasonably 

Available Control Technology and Best Available Retrofit Control Technology for 

Stationary Spark-Ignited Internal Combustion Engines," SSD, July 2000. 

ARB, 2001: California Air Resources Board, "California Diesel Fuel, Fact Sheet," 

downloaded from http://www.arb.ca.gov/fuels/dieselldieselfs.pdf. October 6, 2000. 

BEA, 1995: Bureau of Economic Analysis, "Regional State Projections of Economic Activity 

and Population to 2045," U.S. Department of Commerce, Washington, DC, July 1995. 

BLS, 1999: Bureau of Labor Statistics, Economic and Employment Projections, 1998-2008. 

U.S. Department of Labor, November 30, 1999. 

Census, 1990: U.S. Census Bureau, 1990 Census of Population and Housing, Summary 

Tape File 1 (STF -1), April 1, 1990. 

Census, 2000: U.S. Census Bureau, Documentation to Accompany July 1, 1999 Population 

Estimates for Counties, http://www.census.gov/population/www/estimates/ 

co_99_8.html, March 9, 2000. 

79 
REFERENCES (continued) 


Connecticut, 2000: Regulations of Connecticut State Agencies, Section 22a-174-22, "Control 

of Nitrogen Oxides Emissions," July 2000. 

Delaware, 1993: Delaware State Regulation 12, "Control of Nitrogen Oxides Emissions," 

November 1993. 

EC,2000: European Commission, "Reference Document on Best Available Techniques in 

the Cement and Lime Manufacturing Industries," Integrated Pollution Prevention and 

Control (IPPC), World Trade Center, Sevilla, Spain, March 2000. 

EC/R,2000a: EC/R Inc., "NOx Control Technologies for the Cement Industry," Chapel Hill, 

NC, prepared for the U.S. Environmental Protection Agency, Office of Air Quality 

Planning and Standards, Research Triangle Park, NC, September 19, 2000. 

EC/R, 2000b: EC/R Inc., "Stationary Reciprocating Internal Combustion Engines, Updated 

Information on NOx Emissions and Control Techniques," prepared for the U.S. 

Environmental Protection Agency, Office of Air Quality Planning and Standards, 

Research Triangle Park, NC, August 29, 2000. 

EPA, 1991: U.s. Environmental Protection Agency, "Procedures for the Development of 

Emission Inventories for Carbon Monoxide and Precursors of Ozone," Office of Air 

Quality Planning and Standards, EPA 450/4-91-016, May 1991. 

EPA, 1994: U.S. Environmental Protection Agency, "Alternative Control Techniques 

Document - NOx Emissions from Cement Manufacturing," Office of Air Quality 

Planning and Standards, (EPA-4531R-94-004), March 1994. 

EPA, 1995: U.S. Environmental Protection Agency, "Summary of State NOx RACT Rules: 

Final Report," Research Triangle Park, NC, September 1995. 

EPA, 1999a: U.S. Environmental Protection Agency, "Development of Emission Budget 

Inventories for Regional Transport NOx SIP Call," Office of Air Quality Planning and 

Standards, May 1999. 

EPA, 1999b: U.S. Environmental Protection Agency, "Development of Emission Budget 

Inventories for Regional Transport NOx SIP Call, Technical Amendment Version," 

Office of Air Quality Planning and Standards, A-96-56:X-B-11, December 1999. 

EPA,2000a: U.S. Environmental Protection Agency, "NONROAD Model, Beta Version," 

Office of Transportation and Air Quality, Ann Arbor, MI, June 2000. 

80 
REFERENCES (continued) 


EPA,2000b: u.s. Environmental Protection Agency, "Regulatory Impact Analysis: HeavyDuty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control 

Requirements," Office of Transportation and Air Quality, Assessment and Standards 

Division, EPA 420-R-00-026, December 2000. 

EPA, 2001: U.S. Environmental Protection Agency, "Economic Growth Analysis System: 

Version 4.0 Reference Manual, Final Draft," Office of Air Quality Planning and 

Standards, Research Triangle Park, NC, January 26,2001. 

Faiz, 1996: A. Faiz, "Air Pollution from Motor Vehicles: Standards and Technologies for 

Controlling Emissions," The World Bank, Washington, DC, 1996. 

63FR48819, 1998: Federal Register, "National Volatile Organic Compound Emission 

Standards for Consumer Products," Final Rule, Vol. 63, No. 176, September 11, 1998. 

65 FR 6797, 2000: Federal Register, "Control of Air Pollution from New Motor Vehicles: 

Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements," 

February 10, 2000. 

66 FR 5001, 2001: Federal Register, "Control of Air Pollution from New Motor Vehicles: 

Heavy-Duty Engine and Vehicle Standards and Highway Diesel Fuel Sulfur Control 

Requirements," January 18, 2001. 

Industry Insights, 1993: Industry Insights, Inc., "Architectural and Industrial 

Maintenance Surface Coatings VOC Emission Inventory Survey," conducted for the 

National Paint and Coatings Association in cooperation with the AIM Reg-Neg 

Industry Caucus, May 1993. 

Leibel, 1999: T. Leibel, South Coast Air Quality Management District, personal 

communication with S. Roe, E.H. Pechan & Associates, Inc., October 15, 1999. 

Lum, 2001: D. Lum, California Air Resources Board, Compliance Division, personal 

communication with Andy Bollman, E.H. Pechan & Associates, Inc., March 13, 2001. 

Maryland, 2000: Code of Maryland 26, Section 11, Chapter 09.08, "Control of NOx 

Emissions for Major Stationary Sources," http:209.15.49.5/26/26.11.09.08.htm, 2000. 

NESCAUM,2000: Northeast States for Coordinated Air Use Management, "Status Report 

on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, Internal 

Combustion Engines, Technologies & Cost Effectiveness," December 2000. 

New Hampshire, 2000: New Hampshire Code of Administrative Rules, PART Env-A 1211, 

"Nitrogen Oxides (NOx)," 2000. 

81 
REFERENCES (continued) 


New Jersey, 1993: New Jersey Administrative Code, Title 7, Chapter 27, Subchapter 19, 

"Control and Prohibition of Air Pollution From Oxides of Nitrogen," December 1993. 

New York, 1998: New York State Implementation Plan for Ozone, "Meeting the Statewide 

Oxides of Nitrogen (NOx) Budget Requirements Contained in the NOx SIP Call," 

NYSDEC Air Resources, October 1998. 

OTAG, 1996: Ozone Transport Assessment Group, Assessment of Control Technologies for 

Reducing Nitrogen Oxide Emissions from Non-Utility Point Sources and Major Area 

Sources," OTAG Policy Paper, Control Technologies and Options Workgroup, February 

27, 1996. 

Pechan,2000: E.H. Pechan & Associates, Inc., "NOx Emissions Control Costs for Stationary 

Reciprocating Internal Combustion Engines in the NOx SIP Call States," prepared for 

the U.S. Environmental Protection Agency, Office of Air Quality Planning and 

Standards, Research Triangle Park, NC, August 11, 2000. 

Pennsylvania, 1998: Commonwealth of Pennsylvania, Pennsylvania Code, Title 25. 

Environmental Protection, Department of Environmental Protection, Chapters 121­

143, Air Resources, current through 28 Pa.B. 4776, September 19, 1998. 

SCAQMD, 1997: South Coast Air Quality Management District, "Final Staff Report for 

Proposed Amendments to Rule 1122 - Solvent Degreasers," June 6, 1997. 

SCAQMD, 1999: South Coast Air Quality Management District, Board Meeting: 

Amendment of Rule 1171 - Solvent Cleaning Operations, October 8, 1999. 

Seitz, 1994: John S. Seitz, "Credit for the 15 Percent Rate-of-Progress Plans for Reductions 

from the Architectural and Industrial Maintenance (AIM) Coating Rule and the 

Autobody Refinishing Rule," Office of Air Quality Planning and Standards, U.S. 

Environmental Protection Agency, Research Triangle Park, North Carolina, 

November 29, 1994. 

Seitz, 1995a: John S. Seitz, "Regulatory Schedule for Consumer and Commercial Products 

under Section 183(e) of the Clean Air Act," Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency, Research Triangle Park, NC, 

Memorandum to EPA Regional Offices, June 22, 1995. 

Seitz, 1995b: John S. Seitz, "Credit for the 15 Percent Rate-of-Progress Plans for 

Reductions from the Architectural and Industrial Maintenance (AIM) Coating Rule," 

Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, 

Research Triangle Park, NC, Memorandum to EPA Regional Offices, March 22, 1995. 

82 

REFERENCES (continued) 


STAPPAIALAPCO, 1994: State and Territorial Air Pollution Program 

Administrators/Association of Local Air Pollution Control Officials, "Controlling 

Nitrogen Oxides Under the Clean Air Act: A Menu of Options," July 1994. 

TNRCC, 2000: Texas Natural Resource Conservation Commission, "Chapter 114 - Control 

of Air Pollution from Motor Vehicles," Austin, Texas, December 2000. 

83 

84 

APPENDIX A 


METHODS FOR ESTIMATING 


PORTABLE FUEL CONTAINER EMISSIONS 


Appendix A 


Methods for Estimating Portable Fuel Container Emissions 


This appendix describes how the information in the California Air Resources Board's 

Mail-Out MSC 99-25 can be used to estimate portable fuel container emissions in the 

OTC States. Most of the text and equations in this appendix are taken directly from 

MSC 99-25. 

Introduction 

Gas-can emissions rates for various emissions modes (e.g., evaporation, permeation, 

etc.) occurring during typical usage are determined using diurnal evaporative and 

gravimetric test methods. The survey of population and usage are combined with the 

emissions test results to produce the inventory. This inventory will be used in 

estimating other inventories, such as those of past and future years, and for other 

purposes involving planning or air-quality modeling. The gas-can surveys and 

emissions test methods are discussed in the following sections. 

A. Residential-Gas Cans. 

1. Surveys. 

Residential-gas-can information can be solicited by mail from randomly selected OTC 

State households and directly from various agency staff. 

Gas-can emissions are a function of the can material (i.e., plastic or metal) and the 

storage conditions. Gas cans are stored in either an "open" or a "closed" condition. An 

open condition, or system, exists when a can is stored with an open breathing (vent) 

hole and/or an uncapped main-filler opening or nozzle. A closed system exists when 

the vent hole is closed and the main-filler opening or spout is capped. 

A sample result of an OTC State residential-gas-can-survey is presented in Table 1. 

Table 1: Residential-Gas-Can-Survey Results (sample) 

Percentage of Households with at Least One Gas Can 

Number-of-Gas-Cans per Household 

Percentage of Plastic-Gas Cans/Metal-Gas Cans 

Weighted Average Gas Can Capacity (gal.) 

Percentage of Gas Cans Stored With Fuel 

Weighted Average Stored Fuel Volume (% of Total Capacity) 

Percentage of Plastic-Gas Cans Stored Open/Closed 

46% 

1.8 

76%/24% 

2.34 

70% 

49% 

23%/53% 

- A-I ­
Percentage of Metal-Gas Cans Stored Open/Closed 11%/13% 


Percentage of All Gas Cans Stored Open/Closed 34%/66% 


2. Population. 

The residential-gas-can population is calculated as follows: 

POPR = (N)(A)(CountR) (Eq. 1) 

where: POPR = Statewide Residential-Gas-Can Population 

N = Number of Occupied-Housing Units in OTC 

State (say 11,127,621 on Jan. 1,2000) 

A = Percentage of Households with Gas Cans 

(46%) 

CountR = Average Number of Residential-Gas Cans per 

Household (Le., 1.8) 

Substituting the appropriate values into Equation 1 yields a statewide population of 

9,213,670 residential-gas cans for the 2000 calendar year. 

3. Population-Growth Rate. 

The 1990-2000 housing unit data from the OTC State Department of 

Finance can be used to estimate future gas-can growth rates until the 2010 calendar 

year. These projected growth rates will be normalized to the 1990 calendar year. 

The housing unit data can be used to extrapolate values of future annual housing 

units in OTC State until the 2010 calendar year. 

4. Emissions. 

Gas-can emissions are classified by five different emission processes: 

a) Permeation; 

b) Diurnal; 

c) Transport; 

d) Spillage; and, 

e) Vapor Displacement During Equipment Refueling. 

- A-2­
a) Permeation Emissions. 

Permeation emissions are produced after fuel has been stored long enough 

in a can for fuel molecules to infiltrate and saturate the can material. 

An average daily permeation-emission rate can be derived from test data obtained from 

several plastic-gas cans and metal-gas cans. Each gas can is sealed with a metal-filled 

epoxy and an overcoat of a non-permeable two-part epoxy resin. Additionally, any 

plastic caps and plugs are replaced with metal ones whenever possible. Also, all 

secondary vents are plugged with brass fittings and coated with sealant. Lastly, the 

gas cans are leak checked and reworked as necessary. The gas cans are filled with 

certification test fuel (Le., reformulated gasoline), and subjected to a diurnal-variable 

temperature profile in a sealed housing for evaporative determination unit (SHED). This 

temperature profile is the same as is currently required for on-highway motor-vehicleevaporative emissions testing (ozone episode days). Gravimetric measurements are 

made of the gas cans after each 24-hour test period. The average daily permeation 

rate from a plastic-gas can (closed system) is calculated as grams per gallon per day 

(g/gal-day). A permeation-emission rate for metal-gas cans is determined with similar 

test methods as g/gal-day. 

Statewide residential-gas-can-permeation emissions are computed as follows: 

HCPR = L [ (PoPR)(S)(EFp)(BR)(SizeR)(Level) ] (Eq.2) 

where: HCPR = Permeation Emissions in tons per day (tpd) 

POPR = Statewide Residential-Gas-Can Population 

EFp = Appropriate Permeation-Emission Factor (g/galday) 

S = Percentage of Gas Cans Stored with Fuel (70%) 

BR = Percentage of Cans Stored in Closed Condition 

with respect to Material (Plastic 53%; Metal 13%) 

SizeR = Weighted Average Capacity of Residential-Gas 

Cans (2.34 gal.) 

Level = Weighted Average Amount of Stored Fuel (49%) 

Substituting the appropriate values into Equation 2, summing the resultant products, 

and converting grams to tons (Le., 9.08(105

) grams per ton), produces a statewide total 

of residential-plastic-gas-can-permeation emissions. Similarly, a permeation-emissions 

total for residential-metal-gas-cans can be determined. 

- A-3 ­
b) Diurnal Emissions. 

Diurnal emissions result when stored fuel vapors escape to the outside of a 

gas can through any possible openings while the gas can is subjected to the daily cycle 

of increasing and decreasing ambient temperatures. Diurnal emissions are dependent 

on the closed- or open-storage condition of a gas can. Accordingly, emissions rates 

are determined for both conditions. 

Closed-System. Plastic-gas-can test data are gathered from, say, several 2-gallon-Bounce, and five-gallon, size gas cans. These gas cans are filled with certification-test 

fuel to one-half of the total capacity. One-half of the gas-can capacity approximates the 

weighted average of stored fuel volume of 49%. The cans are subjected to a diurnalvariable temperature profile in a shed. An average diurnal-emission rate is first 

calculated using each individual gas-can average daily-emission rate. The averagedaily plastic-gas-can permeation rate is then subtracted from that value to yield the 

resultant diurnal-emission rate for plastic, closed-system gas cans as g/gal-day. 

Similar diurnal-SHED tests of several metal-gas cans can be performed. 

Open-System. Plastic-gas-can test data are gathered from several five-gallon, and 2­

gallon-B-ounce, size gas cans. Each gas can is weighed, filled with test fuel to various 

fractions of their total capacities, and weighed again. The gas cans are then stored 

with open vent and breathing holes. Each gas can is weighed after each subsequent 

24-hour period for sixteen consecutive days. The average diurnal-emission rate over 

the test period can be measured as g/day. Note that this diurnal-emission rate is 

applicable for both plastic- and metal-gas cans that are stored in an open condition. 

Diurnal emissions from both open- and c1osed-system-residential-gas cans are 

calculated as follows: 

(Eq.3) 

where: HCDR = Diurnal Emissions (tpd) for Residential-Gas Cans 

with respect to Storage Condition (Open or 

Closed) and Material (Plastic or Metal) 

POPR = Statewide Residential-Gas-Can Population 

S = Percentage of Gas-Can Population Stored with 

Fuel (70%) 

EFD = Appropriate Diurnal-Emission Factor with respect 

to Storage Condition and Material (g/gal-day or 

g/day) 

BR = Percentage of Gas-Can Population with respect 

to Storage Condition and Material 

- A-4­
SizeR = Weighted Average Capacity of Residential-Gas 

Cans (2.34 gal.) 

Level = Weighted Average Amount of Stored Fuel (49%) 

Substituting the appropriate values into Equation 3, and performing the conversion to 

tons, yields a statewide total residential-gas-can-diurnal emission amount in tpd for the 

2000 calendar year. 

c) Transport-Spillage Emissions. 

Transport-spillage emissions arise when fuel escapes (e.g., spills, etc.) from 

gas cans that are in transit. The transport-em iss ion-spillage factor can be determined 

from data provided by the U. S. EPA's fuel transport spillage survey of hydrocarbon 

losses from lawn and garden equipment. Analysis of this data revealed that the 

emission rates for a gas can (Le., pump-to-pump losses) were 23.0 grams per gascan-refill-at-the-pump (g/refill) for a closed system, and 32.5 g/refill for an open 

system. Residential-transport-spillage emissions are determined as: 

(Eq.4) 

where: HCTR = Residential-Gas-Can-Transport-Spillage Emissions 

(tpd) 

POPR = Statewide Residential-Gas-Can Population 

S = Percentage of Gas Cans Stored with Fuel (70%) 

RefiliR = Average Number of Residential-Gas-Cans-PumpRefills per Day per Can ( refill/day from survey) 

EFT = Transport-Emission Factor with respect to 

Storage Condition (g/refill) 

BR = Percentage of Gas Cans with respect to Storage 

Condition and Material 

Substituting the appropriate values into Equation 4, and converting grams to tons, 

yields a statewide total residential-gas-can-transport-spillage emission value in tpd. 

B. Commercial-Gas Cans. 

1. Surveys. 

Commercial-gas can usage and storage information can be solicited by agency staff 

directly from various statewide businesses. Targeted businesses may include 

- A-5 ­
agricultural, automotive club and tow services, service stations, lawn and garden 

maintenance services, general contractors, and construction and rental yards. 

The results of a sample commercial-gas-can-survey may be as follows: 

Table 2: Commercial-Gas-Can-Survey Results (Sample) 

Percentage of Businesses with at Least One Gas Can 80% 

Gas Cans per Businesses 6.9 

Weighted Average Gas Can Capacity (gal.) 3.43 

Percentage of Plastic-Gas Cans/Metal-Gas Cans 72%/28% 

Percentage of Plastic-Gas Cans Stored Open/Closed 39%/33% 

Percentage of Metal-Gas Cans Stored Open/Closed 10%/18% 

Percentage of All Gas Cans Stored Open/Closed 49%/51% 

2. Population. 

The populations of commercial-gas cans held by businesses can be determined 

using the InfoUSA database. Specific businesses that are expected to utilize gas cans 

in their normal operations are identified within various industrial classifications 

(e.g., agricultural services, general building services, etc.). Summing up the individual 

populations of each business group gives an estimate of the total statewide population 

of businesses using gas cans. 

The commercial-gas-can population is calculated as follows: 

POPe = (Ne )( Countd (Eq.5) 

= Statewide Commercial-Gas-Can Population 

= Number of Occupied Businesses in OTC State 

= Average Number of Gas Cans per Business (6.9) 

where: 

3. Emissions. 

a) Permeation Emissions. 

Permeation-emission rates for commercial-gas cans are assumed to be the 

same as those for residential-gas cans 

Statewide commercial-gas-can-permeation emissions are computed as follows: 

- A-6­
(Eq.6) 

where: HCpc = Permeation Emissions (tpd) 

Popc = Statewide Commercial-Gas-Can Population 

EFp = Appropriate Permeation-Emission Factor (g/gal-day) 

S = Percentage of Gas Cans Stored with Fuel (70% 

for Residential Survey) 

Bc = Percentage of Applicable Gas Cans Stored in 

Closed Condition 

Sizec = Weighted Average Capacity of Commercial-Gas 

Cans (3.43 gal) 

Level = Weighted Average Amount of Stored Fuel (49% 

from Residential Survey) 

Substituting the appropriate values into Equation 6, summing the resultant products, 

and converting grams to tons, gives a commercial-gas-can statewide permeationemissions total in tpd for plastic-gas cans and for metal-gas cans. 

b) Diurnal Emissions. 

Diurnal-emissions rates for commercial-gas cans are expected to be the 

same as for residential-gas cans. 

The amount of diurnal emissions from both open- and closed-system commercial-gas 

cans is calculated as follows: 

(Eq.7) 

where: HCDC = Diurnal Emissions (tpd) for Commercial-Gas 

Cans with respect to Storage Condition (Open or 

Closed) and Material (Plastic or Metal) 

Popc = Statewide Commercial-Gas-Can Population 

EFD = Appropriate Diurnal-Emission Factor with respect 

to Storage Condition and Material (g/gal-day or 

g/day) 

S = Percentage of Gas Cans Stored with Fuel (70% 

from Residential Survey) 

Bc = Percentage of Gas Cans with respect to Storage 

Condition and Material 

- A-7 ­
Sizec = Weighted Average Capacity of Commercial-Gas 

Cans (3.43 gal.) 

Level = Weighted Average Amount of Stored Fuel (49% 

from Residential Survey) 

Substituting the appropriate values into Equation 7, and converting grams to tons, 

yields commercial-gas-can-diurnal-emission values. 

c) Transport-Spillage Emissions. 

Transport-Spillage emissions factors for commercial-gas cans are expected 

to be the same as those for residential-gas cans: 23.0 g/refill per can for a closed 

system, and 32.5 g/refill per can for an open system. The frequency of gas-can refills at 

the pump for lawn-and-garden equipment is expected to be different than for all of the 

other types of commercial equipment. This is due to the higher level of activity for 

commercial lawn-and-garden equipment; hence, this equipment is expected to be 

refueled more often than is other commercial equipment. Accordingly, the frequency of 

average commerciallawn-and-garden-equipment gas-can refills at the pump is derived 

from the U. S. EPA's fuel transport spillage survey of hydrocarbon losses from lawn and 

garden equipment data. 

The 2000-calendar-year frequency of non-Iawn-and-garden-equipment commercial-gascan refills at the pump is derived as follows: 

Refillc (Eq.8) = [ (L Fuel) l 

(Sizec)(POPNON)(S) 

where: Refillc = Average Number of Non-Lawn-and-Garden 

Equipment Commercial-Gas-Cans Pump 

Refills per Day per Can (refill/day) 

Fuel = Non-Lawn-and-Garden Equipment Fuel 

Consumption (gal/day) for 2000 

Sizec = Weighted Average Capacity of CommercialGas Cans (3.43 gal/can-refill) 

POPNON = Statewide Commercial-Gas-Can Population 

with respect to Non-Lawn-and-Garden 

Businesses 

S = Percentage of Gas Cans Stored with Fuel 

(70% from Residential Survey) 

The commercial-transport-spillage emissions are determine as: 

- A-8­
(Eq.9) 

where: HCTC = Commercial-Gas-Can-Transport-Spillage 

Emissions (tpd) 

Popc = Statewide Commercial-Gas-Can Population 

S = Percentage of Gas Cans Stored with Fuel (70% 

from Residential Survey) 

Bc = Percentage of Gas Cans with respect to Storage 

Condition and Material 

Refillc = Average Number of Gas-Cans Pump Refills per 

Day per Can 

EFTc = Transport-Spillage Emission Factor (g/refill) with 

respect to Storage Condition 

C. Spillage Emissions During Equipment Refueling. 

Spillage emissions are produced when fuel is dispensed from a gas can to an 

equipment/vehicle fuel tank, another gas can, etc., and fails to either be delivered into 

the intended reservoir or to remain inside the reservoir. Spillage data provided by the 

Outdoor Power Equipment Institute (OPEl) in conjunction with the U. S. EPA's NEVES 

report1 indicate that the spillage-emission rate for equipment refills from a gas can is 

17 grams per refill per equipment unit. This estimate assumes that every refill results in 

a replenishment of the fuel tank's entire capacity. The spillage-emission rate is applied 

to only equipment or vehicles that are typically fueled from a gas can (e.g., lawn care 

equipment, sometimes recreational equipment, etc.), and not typically from a pump. 

The amount of daily spillage emissions from all applicable residential- and commercialgas cans is calculated as follows: 

HC (Eq. 10) s = L {[(FUel)(SPill~ (con)} 

(Tank) J 

where: HCs = Daily Spillage Emission from All Gas Cans (tpd) 

Fuel = Applicable EquipmenWehicie Type Fuel 

Consumption (gal/day) 

Spill = Spillage-Emission Rate per Refill of Gas CanRefueled EquipmenWehicies (17 g/refill) 

1 "Nonroad Engine and Vehicle Emission Study - Report," U. S. Environmental Protection 

Agency, November 1991. 

- A-9 ­
Tank = 	Applicable EquipmenWehicle Fuel-Tank Capacity 

(gal/refill) 

Con = 	Frequency of Refuels (per day) with respect to 

EquipmenWehicie (none, always, or fraction of 

always) 

D. Refueling-Vapor Displacement. 

The refueling-displacement-vapor emissions result when fuel vapor is displaced 

from equipment and vehicle fuel tanks, gas cans, etc., by fuel dispensed from gas cans. 

The NEVES report of refueling emissions presented a formula to compute the refuelingvapor-displacement-emission factor. This formula is: 

DISP = 	 [-5.909 + (0.0884 )(TD) + (0.485)(RVP)] (Eq. 11) 

where: DISP = Daily Spillage-Emission Rate for All Gas Cans 

(g/gal) 

TD = Temperature CF) of the Dispensed Fuel 

(ambient temperature) 

RVP = Reid Vapor Pressure of Dispensed Fuel (psi) 

The amount of daily refueling vapor-displacement emissions from all applicable 

residential-and commercial-gas cans is calculated as follows: 

HCDlsp = l: {(DISP)(FUel)(COn)} 	 (Eq. 12) 

where: HCD1SP = Total Refueling-Vapor-Displacement Emissions 

from All Gas Cans (tpd) 

DISP = Refueling Vapor Displacement Emission Rate 

(4.52 g/gal) 

Fuel = Applicable EquipmenWehicie Type Fuel 

Consumptions (gal/day) 

Con 	 = Frequency of Refuels (per day) with respect to 

EquipmenWehicie (none, always, or fraction of 

always) 

As with the spillage-emission-factor calculation, the vapor-displacement-emission rate 

is applied only to equipment or vehicles that are typically fueled from a gas can, and not 

from a pump dispenser. 

- A-IO ­
Summary of Results. 

Table 3 can be used to estimate the total emissions: 

Table 3: Statewide Gas-Can Emissions for 2000 Calendar Year 

Emission Residential Commercial Total by 

Type Emissions Emissions Emission Type 

(tpd) (tpd) (tpd) 

Permeation 

Diurnal 

Transport-Spillage 

Spillage 

Refueling-Vapor Displ. 

Subtotal: 

Total: XX.X 

- A-U ­
- A-12 ­
APPENDIX B 


SOURCE CLASSIFICATION CODES AFFECTED BY THE 


NOx MODEL RULE 


Appendix B 


Source Classification Codes affected by the NOx model rule 


Source Type SCC SCC Description 

Cement Kilns 

30500606 

30500706 

30500622 

30500623 

Stationary Combustion Turbines 

20100101 

20100201 

20100801 

20100901 

20101001 

20101302 

20200101 

20200103 

20200201 

20200203 

20200701 

20200705 

20200901 

20201011 

20201013 

20201601 

t;d 20201701 ,

,.... 20300102 

20300202 

20300203 

20300701 

20300801 

20300901 

Industrial Boilers 

10200060 

10200101 

10200102 

10200104 

10200107 

10200117 

10200201 

10200202 

10200203 

10200204 

10200205 

10200206 

10200210 

10200212 

10200213 

10200217 

10200218 

10200221 

10200222 

10200223 

10200224 

10200225 

Industrial Processes; Mineral Products; Cement Manufacturing (Dry Process); Kilns 

Industrial Processes; Mineral Products; Cement Manufacturing (Wet Process); Kilns 

Industrial Processes; Mineral Products; Cement Manufacturing (Dry Process); Preheater Kiln 

Industrial Processes; Mineral Products; Cement Manufacturing (Dry Process); Preheater/Precalciner Kiln 

Internal Combustion Engines; Electric Generation; Distillate Oil (Diesel); Turbine 

Internal Combustion Engines; Electric Generation; Natural Gas; Turbine 

Internal Combustion Engines; Electric Generation; Landfill Gas; Turbine 

Internal Combustion Engines; Electric Generation; Kerosene/Naphtha (Jet Fuel); Turbine 

Internal Combustion Engines; Electric Generation; Geysers/Geothermal; Steam Turbine 

Internal Combustion Engines; Electric Generation; Liquid Waste; Waste Oil - Turbine 

Internal Combustion Engines; Industrial; Distillate Oil (Diesel); Turbine 

Internal Combustion Engines; Industrial; Distillate Oil (Diesel); Turbine: Cogeneration 

Internal Combustion Engines; Industrial; Natural Gas; Turbine 

Internal Combustion Engines; Industrial; Natural Gas; Turbine: Cogeneration 

Internal Combustion Engines; Industrial; Process Gas; Turbine 

Internal Combustion Engines; Industrial; Process Gas; Refinery Gas: Turbine 

Internal Combustion Engines; Industrial; Kerosene/Naphtha (Jet Fuel); Turbine 

Internal Combustion Engines; Industrial; Liquified Petroleum Gas (LPG); Turbine 

Internal Combustion Engines; Industrial; Liquified Petroleum Gas (LPG); Turbine: Cogeneration 

Internal Combustion Engines; Industrial; Methanol; Turbine 

Internal Combustion Engines; Industrial; Gasoline; Turbine 

Internal Combustion Engines; Commercial/Institutional; Distillate Oil (Diesel); Turbine 

Internal Combustion Engines; Commercial/Institutional; Natural Gas; Turbine 

Internal Combustion Engines; Commercial/Institutional; Natural Gas; Turbine: Cogeneration 

Internal Combustion Engines; Commercial/Institutional; Digester Gas; Turbine 

Internal Combustion Engines; Commerciailinstitutional; Landfill Gas; Turbine 

Internal Combustion Engines; Commercial/Institutional; Kerosene/Naphtha (Jet Fuel); Turbine: JP-4 

Ext Comb Boilers - Industrial;Not Classified ?: assumed as bituminous coal 

External Combustion Boilers; Industrial; Anthracite Coal; Pulverized Coal 

External Combustion Boilers Industrial Anthracite Coal> 100 mmBtu Stoker (Old NAPAP) 

External Combustion Boilers; Industrial; Anthracite Coal; Traveling Grate (Overfeed) Stoker 

External Combustion Boilers; Industrial; Anthracite Coal; Hand-fired 

External Combustion Boilers; Industrial; Anthracite Coal; Fluidized Bed Boiler Burning Anthracite-Culm Fuel 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Pulverized Coal: Wet Bottom 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Pulverized Coal: Dry Bottom 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Cyclone Furnace 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Spreader Stoker 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Overfeed Stoker 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Underfeed Stoker 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Overfeed Stoker" 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Pulverized Coal: Dry Bottom (Tangential) 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Wet Slurry 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Atmospheric Fluidized Bed Combustion: Bubbling Bed (Bituminous Coal) 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Atmospheric Fluidized Bed Combustion: Circulating Bed (Bitum. Coal) 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Pulverized Coal: Wet Bottom (Subbituminous Coal) 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Pulverized Coal: Dry Bottom (Subbituminous Coal) 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Cyclone Furnace (Subbituminous Coal) 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Spreader Stoker (Subbituminous Coal) 

External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Traveling Grate (Overfeed) Stoker (Sub bituminous Coal) 
Appendix B 


Source Classification Codes affected by the NOx model rule 


Source Type SCC SCC Description 

Industrial Boilers 

td, 

l\:) 

10200226 External Combustion Boilers; Industrial; Bituminous/Subbituminous Coal; Pulverized Coal: Dry Bottom Tangential (Subbituminous Coal) 

10200300 External Combustion Boilers; Industrial; Lignite; Pulverized Coal: Wet Bottom 

10200301 External Combustion Boilers; Industrial; Lignite; Pulverized Coal: Dry Bottom, Wall Fired 

10200302 External Combustion Boilers; Industrial; Lignite; Pulverized Coal: Dry Bottom, Tangential Fired 

10200303 External Combustion Boilers; Industrial; Lignite; Cyclone Furnace 

10200304 External Combustion Boilers; Industrial; Lignite; Traveling Grate (Overfeed) Stoker 

10200306 External Combustion Boilers; Industrial; Lignite; Spreader Stoker 

10200401 External Combustion Boilers; Industrial; Residual Oil; Grade 6 Oil 

10200402 External Combustion Boilers; Industrial; Residual Oil; 10-100 Million Btu/hr ** 

10200403 External Combustion Boilers; Industrial; Residual Oil; < 10 Million BtU/hr ** 

10200404 External Combustion Boilers; Industrial; Residual Oil; Grade 5 Oil 

10200406 External Combustion Boilers Industrial Residual Oil ?? 

10200501 External Combustion Boilers; Industrial; Distillate Oil; Grades 1 and 2 Oil 

10200502 External Combustion Boilers; Industrial; Distillate Oil; 10-100 Million Btu/hr ** 

10200503 External Combustion Boilers; Industrial; Distillate Oil; < 10 Million Btu/hr ** 

10200504 External Combustion Boilers; Industrial; Distillate Oil; Grade 4 Oil 

10200601 External Combustion Boilers; Industrial; Natural Gas; > 100 Million BtU/hr 

10200602 External Combustion Boilers; Industrial; Natural Gas; 10-100 Million Btu/hr 

10200603 External Combustion Boilers; Industrial; Natural Gas; < 10 Million Btu/hr 

10200699 Ext Comb Boilers - Industrial;Not Classified 

10200701 External Combustion Boilers; Industrial; Process Gas; Petroleum Refinery Gas 

10200702 External Combustion Boilers Industrial Process Gas ?? 

10200704 External Combustion Boilers; Industrial; Process Gas; Blast Furnace Gas 

10200707 External Combustion Boilers; Industrial; Process Gas; Coke Oven Gas 

10200799 External Combustion Boilers; Industrial; Process Gas; Other: Specify in Comments 

10200801 External Combustion Boilers Industrial Process Gas ?? 

10200802 External Combustion Boilers; Industrial; Coke; All Boiler Sizes 

10200901 External Combustion Boilers; Industrial; Wood/Bark Waste; Bark-fired Boiler (> 50,000 Lb Steam) 

10200902 External Combustion Boilers; Industrial; Wood/Bark Waste; Wood/Bark-fired Boiler (> 50,000 Lb Steam) 

10200903 External Combustion Boilers; Industrial; Wood/Bark Waste; Wood-fired Boiler (> 50,000 Lb Steam) 

10200904 External Combustion Boilers; Industrial; Wood/Bark Waste; Bark-fired Boiler « 50,000 Lb Steam) 

10200905 External Combustion Boilers; Industrial; Wood/Bark Waste; Wood/Bark-fired Boiler « 50,000 Lb Steam) 

10200906 External Combustion Boilers; Industrial; Wood/Bark Waste; Wood-fired Boiler « 50,000 Lb Steam) 

10200910 External Combustion Boilers; Industrial; Wood/Bark Waste; Fuel cell/Dutch oven boilers 

10200911 External Combustion Boilers; Industrial; Wood/Bark Waste; Stoker boilers 

10200912 External Combustion Boilers; Industrial; Wood/Bark Waste; Fluidized bed combustion boiler 

10201001 External Combustion Boilers; Industrial; Liquified Petroleum Gas (LPG); Butane 

10201002 External Combustion Boilers; Industrial; Liquified Petroleum Gas (LPG); Propane 

10201003 External Combustion Boilers; Industrial; Liquified Petroleum Gas (LPG); Butane/Propane Mixture: Specify Percent Butane in Comments 

10201101 External Combustion Boilers; Industrial; Bagasse; All Boiler Sizes 

10201201 External Combustion Boilers; Industrial; Solid Waste; Specify Waste Material in Comments 

10201202 External Combustion Boilers; Industrial; Solid Waste; Refuse Derived Fuel 

10201301 External Combustion Boilers; Industrial; Liquid Waste; Specify Waste Material in Comments 

10201302 External Combustion Boilers; Industrial; Liquid Waste; Waste Oil 

10201401 External Combustion Boilers; Industrial; CO Boiler; Natural Gas 

10201402 External Combustion Boilers; Industrial; CO Boiler; Process Gas 

10201403 External Combustion Boilers; Industrial; CO Boiler; Distillate Oil 

10201404 External Combustion Boilers; Industrial; CO Boiler; Residual Oil 

10201601 External Combustion Boilers; Industrial; Methanol; Industrial Boiler 

10201701 External Combustion Boilers; Industrial; Gasoline; Industrial Boiler 

10299997 Ext Comb Boilers - Industrial;Not Classified 
Appendix B 


Source Classification Codes affected by the NOx model rule 


Source Type 	 SCC SCC Description 

Commercial/Institutional Boiler 

10300101 

10300102 

10300103 

10300203 

10300205 

10300206 

10300207 

10300208 

10300209 

10300211 

10300214 

10300216 

10300217 

10300218 

10300221 

10300222 

10300223 

10300224 

10300225 

10300226 

10300300 

td, 	 10300305 

CoJ 	 10300306 

10300307 

10300309 

10300401 

10300402 

10300403 

10300404 

10300501 

10300502 

10300503 

10300504 

10300601 

10300602 

10300603 

10300701 

10300799 

10300811 

10300901 

10300902 

10300903 

10300910 

10300911 

10300912 

10301001 

10301002 

10301003 

10301201 

10301202 

10301301 

10301302 

External Combustion Boilers; Commercial/Institutional; Anthracite Coal; Pulverized Coal 

Extemal Combustion Boilers; Commercial/Institutional; Anthracite Coal; Traveling Grate (Overfeed) Stoker 

External Combustion Boilers; Commercial/Institutional; Anthracite Coal; Hand-fired 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Cyclone Furnace (Bituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Pulverized Coal: Wet Bottom (Bituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Pulverized Coal: Dry Bottom (Bituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Overfeed Stoker (Bituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Underfeed Stoker (Bituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Spreader Stoker (Bituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Overfeed Stoker" 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Hand-fired (Bituminous Coal) 

External Combustion Boilers; Commerciailinstitutional; Bituminous/Subbituminous Coal; Pulverized Coal: Dry Bottom (Tangential) (Bituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Atmospheric Fluidized Bed Combustion: Bubbling Bed (Bituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Atmospheric Fluidized Bed Combustion: Circulating Bed (Bitum. Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Pulverized Coal: Wet Bottom (Subbituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Pulverized Coal: Dry Bottom (Subbituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Cyclone Furnace (Subbituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Spreader Stoker (Subbituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Traveling Grate (Overfeed) Stoker (Subbituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Bituminous/Subbituminous Coal; Pulverized Coal: Dry Bottom Tangential (Subbituminous Coal) 

External Combustion Boilers; Commercial/Institutional; Lignite; Pulverized Coal: Wet Bottom 

External Combustion Boilers; Commercial/Institutional; Lignite; Pulverized Coal: Dry Bottom, Wall Fired 

External Combustion Boilers; Commercial/Institutional; Lignite; Pulverized Coal: Dry Bottom, Tangential Fired 

External Combustion Boilers; Commercial/Institutional; Lignite; Traveling Grate (Overfeed) Stoker 

External Combustion Boilers; Commercial/Institutional; Lignite; Spreader Stoker 

External Combustion Boilers; Commercial/Institutional; Residual Oil; Grade 6 Oil 

External Combustion Boilers; Commercial/Institutional; Residual Oil; 10-100 Million Btu/hr" 

External Combustion Boilers; Commercial/Institutional; Residual Oil; < 10 Million Btu/hr" 

External Combustion Boilers; Commercial/Institutional; Residual Oil; Grade 5 Oil 

External Combustion Boilers; Commercial/Institutional; Distillate Oil; Grades 1 and 2 Oil 

External Combustion Boilers; Commercial/Institutional; Distillate Oil; 10-100 Million Btu/hr" 

External Combustion Boilers; Commercial/Institutional; Distillate Oil; < 10 Million Btu/hr" 

External Combustion Boilers; Commercial/Institutional; Distillate Oil; Grade 4 Oil 

External Combustion Boilers; Commercial/Institutional; Natural Gas; > 100 Million Btu/hr 

External Combustion Boilers; Commercial/Institutional; Natural Gas; 10-100 Million Btu/hr 

External Combustion Boilers; Commercial/Institutional; Natural Gas; < 10 Million Btu/hr 

External Combustion Boilers; Commerciailinstitutional; Process Gas; POTW Digester Gas-fired Boiler 

External Combustion Boilers; Commercial/Institutional; Process Gas; Other Not Classified 

Extemal Combustion Boilers; Commerciailinstitutional; Landfill Gas; Landfill Gas 

External Combustion Boilers; Commerciailinstitutional; Wood/Bark Waste; Bark-fired Boiler 

External Combustion Boilers; Commercial/Institutional; Wood/Bark Waste; Wood/Bark-fired Boiler 

External Combustion Boilers; Commercial/Institutional; Wood/Bark Waste; Wood-fired Boiler 

External Combustion Boilers; Commercial/Institutional; Wood/Bark Waste; Fuel cell/Dutch oven boilers 

External Combustion Boilers; Commercial/Institutional; Wood/Bark Waste; Stoker boilers 

External Combustion Boilers; Commercial/Institutional; Wood/Bark Waste; Fluidized bed combustion boilers 

External Combustion Boilers; Commercial/Institutional; Liquified Petroleum Gas (LPG); Butane 

External Combustion Boilers; Commercial/Institutional; Liquified Petroleum Gas (LPG); Propane 

External Combustion Boilers; Commercial/Institutional; Liquified Petroleum Gas (LPG); Butane/Propane Mixture: Specify Percent Butane in Comments 

External Combustion Boilers; Commercial/Institutional; Solid Waste; Specify Waste Material in Comments 

External Combustion Boilers; Commercial/Institutional; Solid Waste; Refuse Derived Fuel 

External Combustion Boilers; Commercial/Institutional; Liquid Waste; Specify Waste Material in Comments 

External Combustion Boilers; Commercial/Institutional; Liquid Waste; Waste Oil 
Appendix B 


Source Classification Codes affected by the NOx model rule 


Source Type 	 SCC SCC Description 

Stationary Internal Combustion Engines 

10301303 

20100102 

20100202 

20100702 

20100802 

20100902 

20200102 

20200104 

20200202 

20200204 

20200252 

20200253 

20200254 

20200255 

20200256 

20200301 

20200401 

20200402 

20200403 

20200501 

20200702 

Cd 	 20200706 

~ 20200902 

20201001 

20201002 

20201012 

20201014 

20201602 

20201702 

20300101 

20300201 

20300204 

20300301 

20300702 

20300802 

20301001 

20301002 

External Combustion Boilers; Commercial/Institutional; Liquid Waste; Sewage Grease Skimmings 

I nternal Combustion Engines; Electric Generation; Distillate Oil (Diesel); Reciprocating 

Internal Combustion Engines; Electric Generation; Natural Gas; Reciprocating 

I nternal Combustion Engines; Electric Generation; Process Gas; Reciprocating 

Internal Combustion Engines; Electric Generation; Landfill Gas; Reciprocating 

Internal Combustion Engines; Electric Generation; Kerosene/Naphtha (Jet Fuel); Reciprocating 

Internal Combustion Engines; Industrial; Distillate Oil (Diesel); Reciprocating 

Internal Combustion Engines; Industrial; Distillate Oil (Diesel); Reciprocating: Cogeneration 

Internal Combustion Engines; Industrial; Natural Gas; Reciprocating 

Internal Combustion Engines; Industrial; Natural Gas; Reciprocating: Cogeneration 

Internal Combustion Engines; Industrial; Natural Gas; 2-cycle Lean Burn 

Internal Combustion Engines; Industrial; Natural Gas; 4-cycle Rich Burn 

Internal Combustion Engines; Industrial; Natural Gas; 4-cycle Lean Burn 

Internal Combustion Engines; Industrial; Natural Gas; 2-cycle Clean Burn 

Internal Combustion Engines; Industrial; Natural Gas; 4-cycle Clean Burn 

Internal Combustion Engines; Industrial; Gasoline; Reciprocating 

Internal Combustion Engines; Industrial; Large Bore Engine; Diesel 

Internal Combustion Engines; Industrial; Large Bore Engine; Dual Fuel (Oil/Gas) 

Internal Combustion Engines; Industrial; Large Bore Engine; Cogeneration: Dual Fuel 

Internal Combustion Engines; Industrial; Residual/Crude Oil; Reciprocating 

Internal Combustion Engines; Industrial; Process Gas; Reciprocating Engine 

Internal Combustion Engines; Industrial; Process Gas; Refinery Gas: Reciprocating Engine 

Internal Combustion Engines; Industrial; Kerosene/Naphtha (Jet Fuel); Reciprocating 

Internal Combustion Engines; Industrial; Liquified Petroleum Gas (LPG); Propane: Reciprocating 

Internal Combustion Engines; Industrial; Liquified Petroleum Gas (LPG); Butane: Reciprocating 

Internal Combustion Engines; Industrial; Liquified Petroleum Gas (LPG); Reciprocating Engine 

Internal Combustion Engines; Industrial; Liquified Petroleum Gas (LPG); Reciprocating Engine: Cogeneration 

Internal Combustion Engines; Industrial; Methanol; Reciprocating Engine 

Internal Combustion Engines; Industrial; Gasoline; Reciprocating Engine 

Internal Combustion Engines; Commercial/Institutional; Distillate Oil (Diesel); Reciprocating 

Internal Combustion Engines; Commercial/Institutional; Natural Gas; Reciprocating 

Internal Combustion Engines; Commerciaillnstitutional; Natural Gas; Cogeneration 

Internal Combustion Engines; Commercial/Institutional; Gasoline; Reciprocating 

Internal Combustion Engines; Commercial/Institutional; Digester Gas; Reciprocating: POTW Digester Gas 

Internal Combustion Engines; Commercial/Institutional; Landfill Gas; Reciprocating 

Internal Combustion Engines; CommerciaVlnstitutional; Liquified Petroleum Gas (LPG); Propane: Reciprocating 

Internal Combustion Engines; Commercial/Institutional; Liquified Petroleum Gas (LPG); Butane: Reciprocating 
APPENDIX C 


NOx MODEL RULE CONTROL COST SUMMARIES 


This appendix presents information about the costs of available NOx control 

technologies that might be employed by NOx model rule affected sources in the OTC States. 

Separate tables are provided for industrial boilers, stationary gas turbines, reciprocating 

internal combustion engines, and cement kilns. These are the four source categories 

affected by the OTC NOx model rule. Each table presents information about the ozone 

season (five month) and annual cost effectiveness of various NOx control methods. NOx 

control data is differentiated by source size, fuel type, and the expected NOx control 

efficiency. 

C-1 

Table C-1 


NOx Control Methods for Industrial Boilers 


Baseline Base Controlled Control 

Boiler Size NOx NOx NOx NOx %NOx Cost Effectiveness 

NOx Control Method (MMBtu/hr) Fuel Type (lb/MMBtu) (t/day) (lb/MMBtu) (t/day) Reduction $/ton NOx Removed 

Ozone Season Annual 

Low NOx Burners 

10 gas 50% $9,030-$11,300 

50 gas 50% $2,560-$3,200 

150 gas 45-50% $800-$3,500 

350 gas 0.20 0.84 0.15 0.63 25% $454-$857 $189-$357 

350 

10 

gas 

distillate oil 

0.20 0.84 0.10 0.42 50% 

45% 

$3,783-$7,145 

$5,310-$6,640 

$1,576-$2,977 

50 distillate oil 45% $2,750-$3,440 

150 distillate oil 45% $600-$750 

10 residual oil 45% $2,910-$3,640 

50 residual oil 45% $990-$1,240 

0 

t-:l 

150 

680 

350 

residual oil 

residual oil 

coal 

0.43 

0.60 

3.51 

2.52 

0.39 

0.45 

3.18 

1.89 

45% 

10% 

25% 

$490-$610 

$38-$72 

$2,522-$4,763 

$16-$30 

$1,051-$1,985 

350 coal 0.60 2.52 0.38 1.6 36.6% $1,751-$3,308 $730-$1,378 

500 coal-pul. 50% $760-$2,900 

SNCR 

50 

150 

50 

gas 

gas 

distillate oil 

30-60% 

30-60% 

30-70% 

$4,720-$5,910 

$3,100-$6,800 

$5,040-$6,310 

150 distillate oil 30-70% $2,450-$3,060 

50 residual oil 30-70% $2,190-$2,740 

150 residual oil 30-70% $2,100-$2,630 

350 wood 0.45 1.89 0.29 1.22 35% $2,101-$3,303 $1,300-$1,814 

500 coal-put. 30-70% $870-$1,450 

500 coal-stok. 30-70% $940-$1,170 

Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 


December 2000. 


Data in italics taken from draft "Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 

Table C-1 (continued) 


NOx Control Methods for Industrial Boilers 


Baseline Base Controlled Control 

Boiler Size NOx NOx NOx NOx %NOx Cost Effectiveness 

NOx Control Method (MMBtu/hr) Fuel Type (lb/MMBtu) (t/day) (lb/MMBtu) (t/day) Reduction $/ton NOx Removed 

Ozone Season Annual 

SCR 

50 

150 

50 

150 

50 

150 

gas 

gas 

distillate oil 

distillate oil 

residual oil 

residual oil 

80-90% 

80-90% 

80-90% 

80-90% 

80-90% 

80-90% 

$4,830-$5,480 

$2,060-$5,600 

$5,200-$5,890 

$1,560-$1,780 

$2,070-$2,360 

$1,290-$1,480 

100 gas 0.15 0.18 0.03 0.04 80% $7,919-$14,479 $3,376-$6,110 

350 gas 0.15 0.63 0.03 0.13 80% $4,764-$8,519 $2,062-$3,626 

350 coal 0.45 1.89 0.09 0.38 80% $2,953-$5,046 $1,307-$2,179 

350 coal 0.45 1.89 0.09 0.38 80% $4,004-$7,030 $1,745-$3,006 

Q, 

w 

Conventional Gas Reburn 

500 

500 

coal-put. 

coal-stok. 

80-90% 

80-90% 

$1, 790-$6,800 

$1,980-$2,230 

500 coal 1.20 7.20 0.60 3.60 50% $1,215 

500 coal 1.20 7.20 0.60 3.60 50% $1,482 

640 coal 1.36 8.16 0.685 4.11 50% $1,246 

Fuel Lean Gas Reburn (FLGR) 

350 coal 0.45 1.89 0.293 1.23 35% $1,330-$2,000 $890-$1 ,170 

350 coal 0.45 1.89 0.293 1.23 35% $1,523-$2,220 $1,083-$1,362 

Amine Enhanced FLGR 

350 coal 0.45 1.89 0.18 0.76 60% $1,700-$2,455 $1,210-$1,520 

350 coal 0.45 1.89 0.18 0.76 60% $1,812-$2,604 $1,316-$1,631 

Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 


December, 2000. 


Data in italics taken from draft ''Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 

Table C-2 


NOx Control Methods for Turbines 


Baseline Controlled 

NOx NOx %NOx Cost Effectiveness 

NOx Control Method Turbine Size Fuel Type (ppm) (ppm) Reduction $/ton NOx Removed 

Ozone Season Annual 

In-Combustor Methods 

Dry Low NOx 

V 

>I'>-

Diluent Injection 

Water Injection 

7000 HP 

13,000 HP 

75MW 

5 MW(Cont.) 


25 MW (Cant.) 


100 MW (Cant.) 


25 MW (2000 P) 


100 MW (2000 P) 


21 MW 

21 MW 

5 MW(Cont.) 


25 MW (Cant.) 


100 MW (Cant.) 


25 MW (2000 P) 


100 MW (2000 P) 


5 MW(Cont.) 


25 MW (Cant.) 


100 MW (Cant.) 


25 MW (2000 P) 


100 MW (2000 P) 


gas 

gas 

gas 

gas 

gas 

gas 

gas 

gas 

gas 

distillate oil 

gas 

gas 

gas 

gas 

gas 

oil 

oil 

oil 

oil 

oil 

135 

167 

154 

125 

180 

50 63% 

50 70% 

15 90% 

60-90% 

60-90% 

60-90% 

60-90% 

60-90% 

50 60% 

50 72% 

70-90% 

70-90% 

70-90% 

70-90% 

70-90% 

70-90% 

70-90% 

70-90% 

70-90% 

70-90% 

$4,492-$9,483 

$3,145-$6,640 

$533-$1,126 

$530-$800 

$240-$370 

$130-$200 

$960-$1,470 

$530-$800 

$867-$1,217 

$829-$1,031 

$1,390-$1,780 

$690-$880 

$500-$640 

$1,670-$2,150 

$1,050-$2,150 

$1,000-$1,300 

$560-$710 

$440-$560 

$1,190-$1,520 

$800-$1,020 

$1,872-$3,951 

$1,311-$2,767 

$222-$469 

$638-$784 

$697-$781 

Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 


December, 2000. 


Data in italics taken from draft "Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 

Table C-2 (continued) 

NOx Control Methods for Turbines 

NOx Control Method Turbine Size Fuel Type 

Baseline 

NOx 

(ppm) 

Controlled 

NOx 

(ppm) 

%NOx 

Reduction 

Cost Effectiveness 

$Iton NOx Removed 

Ozone Season Annual 

In-Combustor Methods 

Diluent Injection (Continued) 

Steam Injection 

5 MW(Cont.) gas 70-90% $1,560-$2,000 

25 MW (Cant.) gas 70-90% $760-$970 

100 MW (Cant.) gas 70-90% $520-$670 

25 MW (2000 P) gas 70-90% $2,150-$2,760 

100 MW (2000 P) gas 70-90% $1,370-$1,760 

5 MW(Cont.) oil 70-90% $1,010-$1,300 

25 MW (Cant.) oil 70-90% $520-$670 

100 MW (Cant.) oil 70-90% $380-$480 

0 

01 

25 MW (2000 P) 

100 MW (2000 P) 

oil 

oil 

70-90% 

70-90% 

$1,520-$1,820 

$930-$1,190 

Exhaust Treatment 

SCR 

Simple Cycle Turbines 75MW gas 15 3 80% $12,227-$20,075 $5,171-$8,441 

75MW gas 42 7 83% $4,278-$6,969 $1,859-$2,980 

75MW gas 154 15 90% $1,176-$1,853 $566-$849 

7000 HP gas 42 5 88% $16,031-$27,020 $6,756-$11,335 

7000 HP gas 142 15 89% $4,763-$7,965 $2,061-$3,395 

Combined Cycle Turbines 75MW gas 15 3 80% $8,680-$13,376 $3,693-$5,650 

75MW gas 42 7 83% $3,062-$4,673 $1,353-$2,024 

75MW gas 154 15 90% $869-$1,275 $439-$608 

7000 HP gas 42 5 88% $10,023-$15,672 $4,253-$6,607 

7000HP gas 142 15 89% $3,013-$4,659 $1,332-$2,018 

Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 


December, 2000. 


Data in italics taken from draft ''Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 

Table C-2 (continued) 


NOx Control Methods for Turbines 


Baseline Controlled 

NOx NOx % NOx Cost Effectiveness 

NOx Control Method Turbine Size Fuel Type (ppm) (ppm) Reduction $/ton NOx Removed 

Ozone Season Annual 

Exhaust Treatment 

SCR (Continued) 

5 MW(Cont.) gas 90% $2,180-$2,450 

25 MW(Cont.) gas 90% $1,230-$1,390 

100 MW (Cont.) gas 90% $920-$1,030 

25 MW (2000 P) gas 90% $3,480-$3,920 

100 MW (2000 P) gas 90% $2,400-$2,700 

5 MW(Cont.) oil 90% $1,390-$1,560 

25 MW (Cont.) oil 90% $820-$920 

100 MW (Cont.) oil 90% $630-$710 

25 MW (2000 P) oil 90% $2,170-$2,440 

100 MW (2000 P) oil 90% $1,530-$1,720 o 

en 

Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 


December, 2000. 


Data in italics taken from draft "Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 
Table C-3 


NOx Control Methods for IC Engines 


Baseline Controlled 

NOx NOx %NOx Cost Effectiveness 

NOx Control Method Engine Type Engine Size Fuel Type (gm/hp-hr) (gm/hp-hr) Reduction $Iton NOx Removed 

Ozone Season Annual 

In-Cylinder Methods 

Ignition Timing Retard 

()

, 

-l 

SI Rich Burn 


SI Rich Burn 


SI Rich Burn 


SI Lean Burn 


SI LeanBurn 


SI LeanBurn 


CI Diesel (Cant.) 


CI Diesel (Cant.) 


CI Diesel (Cant.) 


CI Diesel (2000 P) 


CI Diesel (2000 P) 


CI Diesel (2000 P) 


CI Diesel (200 P) 


CI Diesel (200 P) 


CI Diesel (200 P) 


CI Dual Fuel 


CI Dual Fuel 


CI Dual Fuel 


250HP 

1000 HP 

1100 HP 

1100 HP 

4000HP 

250HP 

1000 HP 

4000HP 

250HP 

1000 HP 

4000HP 

250HP 

1000 HP 

4000HP 

250HP 

1000 HP 

4000HP 

250HP 

1000 HP 

4000HP 

gas 

gas 

gas 10 

gas 10 

gas 

gas 

gas 

gas 

diesel 

diesel 

diesel 

diesel 

diesel 

diesel 

diesel 

diesel 

diesel 

dual fuel 

dual fuel 

dual fuel 

9 

7.5 

0-40% 

0-40% 

10% 

25% 

0-40% 

0-20% 

0-20% 

0-20% 

20-30% 

20-30% 

20-30% 

20-30% 

20-30% 

20-30% 

20-30% 

20-30% 

20-30% 

20-30% 

20-30% 

20-30% 

$680-$1,130 

$370-$610 

$1,476-$1,640 

$589-$657 

$270-$450 

$980-$4,930 

$490-$1,470 

$340-$1,020 

$760-$1,140 

$420-$630 

$310-$470 

$1,900 

$830 

$515 

$13,400 

$4,600 

$2,010 

$950-$1,420 

$470-$700 

$320-$480 

$615-$685 

$274-$245 

Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 


December, 2000. 


Data in italics taken from draft ''Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 

Table C-3 (continued) 

NOx Control Methods for IC Engines 

Baseline Controlled 

NOx NOx %NOx Cost Effectiveness 

NOx Control Method Engine Type Engine Size Fuel Type (gm/hp-hr) (gm/hp-hr) Reduction $/ton NOx Removed 

Ozone Season Annual 

In-Cylinder Methods 

(Continued) 

High Energy Ignition/ A-F Ratio 2500 HP gas 15 7 53% $280-$385 $115-$160 

SI Rich Burn 250HP gas 10-40% $580-$870 

SI Rich Burn 1000 HP gas 10-40% $350-$520 

SI Rich Burn 4000HP gas 10-40% $270-$400 

SI Lean Burn 250HP gas 5-30% $980-$4,930 

SI LeanBurn 1000 HP gas 5-30% $490-$1,470 

SI LeanBurn 4000HP gas 5-30% $340-$1,020 

Low Emission Combustion Retrofit 

()

, 

00 

Low Speed Engine 

Medium Speed Engine 

3400 HP 

2500 HP 

gas 

gas 

13 

15 

3 

3 

77% 

80% 

$1,222-$2,296 

$585-$1 ,1 00 

$509-$957 

$245-$460 

Dual-Fuel Engine 2500 HP gas/oil 15 3 80% $1,794-$3,388 $747-$1,412 

SI Rich Burn 250HP gas 70-90% $4,500-$5,010 

SI Rich Burn 1000 HP gas 70-90% $1,850-$2,090 

SI Rich Burn 4000HP gas 70-90% $1,190-$1,340 

SI Lean Burn 250HP gas 80-93% $3,970-$4,460 

SI LeanBurn 1000 HP gas 80-93% $1,610-$1,820 

SI LeanBurn 4000HP gas 80-93% $1,030-$1,150 

Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 

December, 2000. 

Data in italics taken from draft ''Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 
Table C-3 (continued) 

NOx Control Methods for IC Engines 

Baseline Controlled 

NOx NOx %NOx Cost Effectiveness 

NOx Control Method Engine Type Engine Size Fuel Type (gm/hp-hr) (gm/hp-hr) Reduction $/ton NOx Removed 

Ozone Season Annual 

Exhaust Treatment 

SCR 

Gas Engine 1800 HP gas 10 90% $1,104-$8,245 $533-$3,508 

Gas Engine 3130 HP gas 10 90% $591-$3,884 $319-$1,691 

SI Lean Burn 250HP gas 90% $4,280-$4,810 

SI LeanBurn 1000 HP gas 90% $1,320-$1,490 

SI LeanBurn 4000HP gas 90% $580-$660 

Diesel Engine 1800 HP diesel oil 10 90% $922-$6,866 $453-$2,929 

Diesel Engine 3130 HP diesel oil 10 90% $614-$4,246 $324-$1,838 

CI Diesel (Cont.) 250HP diesel 80-90% $4,170-$4,690 

CI Diesel (Cont.) 1000 HP diesel 80-90% $1,460-$1,640 

V 

co 

CI Diesel (Cont.) 

CI Diesel (2000 P) 

4000HP 

250HP 

diesel 

diesel 

80-90% 

80-90% 

$780-$880 

$8,750 

CI Diesel (2000 P) 1000 HP diesel 80-90% $3,000 

CI Diesel (2000 P) 4000HP diesel 80-90% $1,560 

CI Diesel (200 P) 250HP diesel 80-90% $61',000 

CI Diesel (200 P) 1000 HP diesel 80-90% $20,000 

CI Diesel (200 P) 4000HP diesel 80-90% $10,000 

CI Dual Fuel 250HP dual fuel 80-90% $5,800-$6,530 

CI Dual Fuel 1000 HP dual fuel 80-90% $1,970-$2,210 

CI Dual Fuel 4000HP dual fuel 80-90% $1,010-$1,140 

Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 


December, 2000. 


Data in italics taken from draft "Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2/27/96). 

Table C-3 (continued) 


NOx Control Methods for IC Engines 


Baseline Controlled 

NOx NOx %NOx Cost Effectiveness 

NOx Control Method Engine Type Engine Size Fuel Type (gm/hp-hr) (gm/hp-hr) Reduction $/ton NOx Removed 

Ozone Season Annual 

Exhaust Treatment 

(Continued) 

Mobile-Source Derivative SCR 

Diesel Engine 1971 HP diesel oil 7.62 1.91 75% $769-$3,080 $528-$1,491 

Diesel Engine 1971 HP diesel oil 15 3.75 75% $577-$1,751 $455-$944 

NSCR 

SI Rich Burn 250HP gas 90-98% $290-$310 

SI Rich Burn 1000HP gas 90-98% $200-$220 

SI Rich Burn 4000HP gas 90-98% $180-$190 

o Data taken from "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 

:::; December, 2000. 

Data in italics taken from draft "Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 
Table C-4 


NOx Control Methods for Cement Kilns 


Baseline Controlled 

Kiln Kiln Size NOx NOx %NOx Cost Effectiveness 

NOx Control Method Type (tons/hour) (Ib/ton clinker) (Ib/ton clinker) Reduction $Iton NOx Removed 

Ozone Season Annual 

Low NOx Burners 

Long Wet 30 20-30% $1,130 

Long Wet 50 20-30% $880 

Long Dry 25 20-30% $1,270 

Long Dry 40 20-30% $970 

Preheater 40 20-30% $1,330 

Preheater 70 20-30% $970 

Precalciner 100 20-30% $1,010 

Precalciner 150 20-30% $830 

Mid-Kiln Tire Firing with LNB 

\1 

I-' 

I-' 

Long Wet 

Long Wet 

Long Dry 

30 

50 

25 

20-40% 

20-40% 

20-40% 

$550 

$450 

$610 

Long Dry 40 20-40% $470 

Indirect Firing & Mid-Kiln Tire Firing 

No tipping fee 96 5.0 2.55 49% $1,766-$4,385 $736-$1,827 

With $20 tipping fee 96 5.0 2.55 49% $1,231-$3,850 $513-$1,604 

With $75 tipping fee 96 5.0 2.55 49% ($242)-$2,377 ($101 )-$991 

Mid-Kiln Tire Firing Only 

No tipping fee 40 5.0 4.0 20% ($2,326)-($4,035) ($969 )-($1 ,681 ) 

With $20 tipping fee 40 5.0 4.0 20% ($5,164 )-($6,873) ($2,151 )-($2,864) 

With $75 tipping fee 40 5.0 4.0 20% ($12,966)-($14,675) ($5,403)-($6,115) 

Numbers in ( ) mean company is realizing a savings instead of a cost by using control method. 


Data taken from draft "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectriveness", NESCAUM, 


December, 2000. 


Data in italics taken from draft ''Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96). 
Table C-4 (continued) 


NOx Control Methods for Cement Kilns 


Baseline Controlled 

Kiln Kiln Size NOx NOx % NOx Cost Effectiveness 

NOx Control Method Type (tons/hour) (Ib/ton clinker) (Ib/ton clinker) Reduction $/ton NOx Removed 

Ozone Season Annual 

CemStar Process 

net clinker value =$15/ton 

net clinker value =$30/ton 

net clinker value =$50/ton 

SNCR 


pre-calciner kiln 


SNCR (Urea) 


Preheater 


Preheater 


Precalciner 


Precalciner 


0, SNCR (Ammonia) 

Preheater """'" t>:l

Preheater 

Precalciner 

Precalciner 

SCR 

Long Wet 


Long Wet 


Long Dry 


Long Dry 


Preheater 


Preheater 


Precalciner 


Precalciner 


40 200 Ib NOxlhr 160 Ib NOxlhr 20% 

40 200 Ib NOxlhr 160 Ib NOxlhr 20% 

40 200 Ib NOxlhr 160 Ib NOxlhr 20% 

<150 700 Ib NOxlhr 385 Ib NOxlhr 45% 

40 30-70% 

70 30-70% 

100 30-70% 

150 30-70% 

40 30-70% 

70 30-70% 

100 30-70% 

150 30-70% 

30 80-90% 

50 80-90% 

25 80-90% 

40 80-90% 

40 80-90% 

70 80-90% 

100 80-90% 

150 80-90% 

$664-$1 ,120 $365-$555 

($1,156)-($1,611 ) ($1,721)-($1,910) 

($4,190)-($4,646) ($4,755)-($4,945) 

$890-$1,215 $675-$810 

$930 

$790 

$880 

$800 

$1,100 

$910 

$980 

$880 

$3,600 

$3,140 

$3,630 

$3,170 

$4,120 

$3,490 

$4,870 

$4,400 

Numbers in ( ) mean company is realizing a savings instead of a cost by using control method. 


Data taken from draft "Status Report on NOx Controls for Gas Turbines, Cement Kilns, Industrial Boilers, and I.C. Engines - Technologies & Cost Effectiveness", NESCAUM, 


December, 2000. 


Data in italics taken from draft "Assessment of Control Technologies for Reducing Nitrogen Oxides from Non-Utility Point Sources and Major Area Sources", OTAG (2127/96).