24060 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 51, 52, 70, and 71 

[EPA–HQ–OAR–2006–0089; FRL–8301–4] 

RIN–2060–AN77 

Prevention of Significant Deterioration, 

Nonattainment New Source Review, 

and Title V: Treatment of Certain 

Ethanol Production Facilities Under 

the ‘‘Major Emitting Facility’’ Definition 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: This final rule finalizes 

proposed changes made to the 

definition of ‘‘major emitting facility’’ in 

the Prevention of Significant 

Deterioration (PSD), Nonattainment 

New Source Review (NSR) and Title V 

regulations. Two of the regulatory 

changes proposed addressed the major 

source threshold for PSD sources. The 

remaining proposed regulatory changes 

finalized in this action address when 

fugitive emissions are counted for 

purposes of determining whether a 

source is a major source under the PSD, 

nonattainment NSR or Title V programs. 

The proposal solicited comment on 

whether wet and dry corn milling 

facilities that produce ethanol for fuel 

should continue to be considered a part 

of the chemical process plants source 

category, and whether other types of 

facilities that produce ethanol fuel 

should be considered for exclusion from 

the definition of chemical process 

plants. Based on comments received 

and evaluated, we have included 

additional changes to this final rule that 

exclude other facilities that produce 

ethanol by natural fermentation and are 

classified in North American Industry 

Classification System (NAICS) code 

325193 or 312140 from the definition of 

‘‘chemical process plants.’’ 

DATES: This final rule is effective on July 

2, 2007. 

ADDRESSES: Docket. The EPA has 

established a docket for this action 

under Docket ID No. [EPA–HQ–OAR– 

2006–0089]. All documents in the 

docket are listed on the http:// 

www.regulations.gov Web site. Although 

listed in the index, some information is 

not publicly available, e.g., Confidential 

Business Information or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically through http:// 

www.regulations.gov or in hard copy at 

the Air and Radiation Docket and 

Information Center, EPA/DC, EPA West 

Building, Room 3334, 1301 Constitution 

Ave., NW., Washington, DC. The Air 

and Radiation Docket and Information 

Center telephone number is (202) 566– 

1742. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal 

holidays. The Public Reading Room is 

located in the EPA Headquarters 

Library, Room Number 3334 in the EPA 

West Building, located at 1301 

Constitution Ave., NW., Washington, 

DC. The telephone number for the 

Public Reading Room is (202) 566–1744. 

Visitors are required to show 

photographic identification, pass 

through a metal detector, and sign the 

EPA visitor log. All visitor materials 

will be processed through an X-ray 

machine as well. Visitors will be 

provided a badge that must be visible at 

all times. 

FOR FURTHER INFORMATION CONTACT: Ms. 

Joanna Swanson, Air Quality Policy 

Division, (C339–03), Environmental 

Protection Agency, Research Triangle 

Park, NC 27711, telephone number: 

(919) 541–5282; fax number: (919) 541– 

5509, e-mail address: 

swanson.joanna@epa.gov. 

SUPPLEMENTARY INFORMATION: The title 

of this final rule has been changed from 

the proposed rule title to better reflect 

the final rule. The proposed rule was 

entitled ‘‘Prevention of Significant 

Deterioration, Nonattainment New 

Source Review, and Title V: Treatment 

of Corn Milling Facilities Under the 

‘‘Major Emitting Facility’’ Definition.’’ 

The information presented in this 

preamble is organized as follows: 

I. General Information 

A. Does this action apply to me? 

B. Where can I obtain additional 

information? 

II. Background 

III. Summary of the Final Rule 

IV. Policy Rationale for Action 

V. Significant Comments Received on the 

Proposal 

A. What comments did we receive on our 

proposed changes to the ‘‘major emitting 

facility’’ definition? 

B. Why are ethanol production facilities 

regulated differently under different 

programs and standards? 

C. Do we need to make an express section 

302(j) finding? 

D. What are the enforcement implications 

of these final amendments? 

E. Are there any environmental and health 

concerns associated with this final rule? 

F. Will there be a Federal ethanol-specific 

VOC emissions test protocol? 

G. Are there backsliding issues related to 

this rulemaking? 

VI. Effective Date of This Rule and 

Requirements for State or Tribal 

Implementation Plans and Title V 

VII. Statutory and Executive Order Reviews 

A. Executive Order 12866—Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Analysis 

D. Unfunded Mandates Reform Act 

E. Executive Order 13132—Federalism 

F. Executive Order 13175—Consultation 

and Coordination with Indian Tribal 

Governments 

G. Executive Order 13045—Protection of 

Children from Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211—Actions 

Concerning Regulations that 

Significantly Affect Energy Supply, 

Distribution or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898—Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-income 

Populations 

K. Congressional Review Act 

VIII. Judicial Review 

I. General Information 

A. Does this action apply to me? 

Entities affected by this final rule are 

facilities that produce ethanol by a 

natural fermentation process that are 

classified under NAICS codes 325193 

and 312140; and State/local/Tribal 

governments. Categories and entities 

potentially affected by this action are 

expected to include: 

Industry group SIC a NAICS b

Wet Corn Milling ....... 2046 311221 

Industrial Organic 

Chemicals (Ethyl 

Alcohol) ................. 2869 325193 

Sugar Cane Mills ...... 2061 311311 

Sugar Beet Manufacturing ..................... 2063 311313 

Distilleries ................. 2085 312140 

State/local/Tribal government ................. 9511 924110 

a Standard Industrial Classification. 

b North American Industry Classification 

System. 

B. Where can I obtain additional 

information? 

In addition to being available in the 

docket, an electronic copy of this 

preamble and final amendments will 

also be available on the World Wide 

Web. Following signature by the EPA 

Administrator, a copy of this notice will 

be posted on the EPA’s NSR Web site, 

under Regulations & Standards, at 

http://www.epa.gov/nsr. 

II. Background 

These regulatory changes affect the 

applicability provisions of two separate 

permitting programs: the major NSR 


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program and the title V programs. The 

NSR program legislated by Congress in 

parts C and D of Title I of the Clean Air 

Act (CAA) is a preconstruction review 

and permitting program applicable to 

major stationary sources (major sources) 

that construct or undertake major 

modifications. In areas not meeting 

health-based national ambient air 

quality standards (NAAQS) and in 

ozone transport regions (OTR), the 

program is implemented under the 

requirements of part D of title I of the 

CAA for ‘‘nonattainment’’ NSR. We call 

this program the major nonattainment 

NSR program. In areas meeting NAAQS 

(‘‘attainment’’ areas) or for which there 

is insufficient information to determine 

whether they meet the NAAQS 

(‘‘unclassifiable’’ areas), the NSR 

requirements for the PSD of air quality 

under part C of title I of the CAA apply. 

We call this program the Prevention of 

Significant Deterioration (PSD) program. 

Collectively, we refer to both programs 

as the major NSR program. The NSR 

regulations are contained in 40 CFR 

51.165, 51.166, 52.21, 52.24, and 

appendix S of part 51. 

Title V of the CAA required EPA to 

promulgate regulations governing the 

establishment of operating permit 

programs. The current regulations are 

codified at 40 CFR parts 70 and 71. 

The CAA, as implemented by our 

regulations, defines the applicability of 

these different programs based, in part, 

on whether a stationary source is 

‘‘major.’’ For purposes of implementing 

the PSD program, Congress defined the 

term ‘‘major emitting facility’’ in section 

169(l) of the CAA. This definition 

contains a specific list of source 

categories for which an individual 

source will be considered a major 

source if it has the potential to emit 100 

tons per year (tpy) of any pollutant for 

which the local area is in attainment 

with the NAAQS. This is referred to as 

the 100 tpy threshold. For any source 

not otherwise listed, a 250 tpy threshold 

applies. For purposes of implementing 

the nonattainment major NSR program, 

we do not apply different applicability 

thresholds based on the type of source 

category. All sources are subject to a 100 

tpy threshold or less depending on the 

severity of the nonattainment problem. 

All major sources, as the term is 

defined for title V purposes, are 

required to obtain title V operating 

permits. Sources required to obtain title 

V permits include those sources subject 

to PSD and nonattainment NSR. 

Therefore, title V relies in part on the 

definition of ‘‘major emitting facility’’ 

for the PSD program. 

In addition to the determining which 

applicability threshold applies to a 

given source, the determination of 

whether a source is ‘‘major’’ is also 

partly dependent on whether the 

stationary source must count both 

fugitive and stack emissions in 

determining whether it exceeds the 

threshold. Section 302(j) provides that 

(j) Except as otherwise expressly provided, 

the terms ‘‘major stationary source’’ and 

‘‘major emitting facility’’ mean any stationary 

facility or source of air pollutants which 

directly emits, or has the potential to emit, 

one hundred tons per year or more of any air 

pollutant (including any major emitting 

facility or source of fugitive emission of any 

pollutant, as determined by rule by the 

Administrator). 

In 1980, we established a list of 

source categories that must consider 

fugitive emissions in source 

applicability determinations. We used 

the section 169(1) list of categories in 

developing our 302(j) list of categories. 

This final rule involves changes to the 

‘‘major stationary source’’ and ‘‘major 

source’’ definitions in the NSR and title 

V programs as this definition relates 

specifically to the manufacturing of 

ethanol through natural fermentation 

processes. These changes affect both the 

applicability threshold and whether this 

industry must count fugitive emissions 

in determining its major source status. 

On March 9, 2006 (71 FR 12240), we 

proposed to reinterpret the component 

term ‘‘chemical process plants’’ within 

the statutory definition of ‘‘major 

emitting facility’’ in section 169(1) of 

the CAA to exclude wet and dry corn 

milling facilities which produce ethanol 

fuel (Option 1). We requested comment 

on another option in which we would 

continue to include wet and dry corn 

milling facilities that produce ethanol 

fuel within the definition of ‘‘chemical 

process plants.’’ (Option 2). We also 

proposed similarly to reinterpret the 

regulatory term ‘‘chemical process 

plants’’ on the list of source categories 

for which fugitive emissions must be 

included in determining whether the 

source is a ‘‘major stationary source.’’ 

To implement these proposed 

changes, we proposed to revise the 

definition of ‘‘major stationary source’’ 

under 40 CFR parts 51 and 52, and the 

definition of ‘‘major source’’ under 40 

CFR parts 70 and 71. (See 71 FR 12240, 

March 9, 2006). Finally, we also 

requested information on other types of 

ethanol production facilities and 

comment on whether other types of 

facilities including those that produce 

potable ethanol or ethanol fuel should 

be considered for exclusion from the 

‘‘chemical process plants’’ definitions. 

III. Summary of the Final Rule 

This rule finalizes Option 1 and 

reinterpret the component term 

‘‘chemical process plants’’ within the 

statutory definition of ‘‘major emitting 

facility’’ and regulatory definitions of 

‘‘major stationary source’’ and ‘‘major 

source’’ to exclude wet and dry corn 

milling facilities that produce ethanol 

for fuel or ethanol for food. Moreover, 

based on comments we received, we are 

extending the exclusion to all facilities 

that produce ethanol through a natural 

fermentation process that involves the 

use of such things as corn, sugar beets, 

sugar cane or cellulosic biomass as a 

feedstock regardless of whether the 

ethanol is produced for human 

consumption, fuel or for an industrial 

purpose. This includes denatured 

alcohol, nonpotable ethanol, nonpotable 

grain alcohol, potable ethyl alcohol and 

grain alcohol beverages. We are also 

reinterpreting the term ‘‘chemical 

process plants’’ on the list of source 

categories that must count fugitives 

emissions in determining whether a 

source is a major source to be consistent 

with the way we now interpret that term 

for purposes of determining the major 

source threshold. 

As proposed, we are changing the 

PSD and nonattainment NSR regulations 

that we are amending with this action 

to include amendments to 40 CFR 

51.165, 51.166, 52.21, and appendix S. 

We are also amending the 40 CFR parts 

70 and 71 title V regulations. We are not 

making changes to 52.24 as proposed 

because we revised that section. 

Paragraph (f) now cross-references the 

provisions of 40 CFR 51.165 for 

definitions of terms under 40 CFR 52.24, 

and paragraph (h) no longer lists source 

categories. 

These final rule amendments define 

‘‘chemical process plants’’ under the 

regulatory definition of ‘‘major emitting 

facility’’ to exclude ethanol 

manufacturing facilities that produce 

ethanol by natural fermentation 

processes. In addition, we have changed 

our approach to defining the sources 

within the exclusion as explained 

below. As explained in the preamble to 

the proposed rule (71 FR at 12243), in 

1981, when we originally interpreted 

the ‘‘chemical process plants’’ term by 

guidance, we did so in reference to SIC 

28. Since the time we defined the 

chemical process plant based solely on 

reference to SIC 28, the Federal 

Government replaced the SIC code 

manual with the NAICS. Under the 

NAICS, as compared to the SIC system, 

there are over 350 more industries 

classified. Federal Government agencies 

have adopted the NAICS to collect 


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statistics from industry establishments 

more relevant to this economy. The 

NAICS gives special attention to 

emerging industries (such as ethanol 

production) and similar production 

processes are grouped together. The SIC 

system, which was last revised in 1987 

does not include many of the industries 

included in the NAICS. 

Ethanol fuel and industrial ethanol 

fall within NAICS 325193 (Ethyl 

Alcohol Manufacturing) which includes 

denatured alcohol, nonpotable ethanol, 

and nonpotable grain alcohol. The 

NAICS 312140 (Distilleries) includes 

potable ethyl alcohol and grain alcohol 

beverages. Even though NAICS 325193 

(ethyl alcohol manufacturing) has been 

classified under NAICS’ Chemical 

Manufacturing subsector, unlike under 

the SIC classification of 2869 (Industrial 

Organic Chemicals, Not Elsewhere 

Classified), ethyl alcohol manufacturing 

is within its own narrowly defined 

category. 

The Agency has considered whether, 

and in what way, we might transition 

from use of the SIC to the NAICS for 

purposes of determining the scope of a 

stationary source in general and for 

other purposes such as source category 

determinations. We have not reached 

any universal conclusions. Notably, 

however, some commenters expressed 

concern that by refining the ‘‘chemical 

process plants’’ definition such that we 

no longer rely solely on SIC code 28, we 

would be embroiling the Agency in the 

‘‘fine grain’’ analysis we sought to avoid 

under our initial guidance, negating the 

objectivity of the current approach. In 

view of this comment, we think it useful 

to consider the NAICS codes as a 

potential tool to address the 

commenters’ concerns. At proposal, we 

did not use SIC codes to define the 

facilities that are subject to these 

changes. We have decided to use NAICS 

codes to define these facilities in the 

final rule because the narrow 

classification of the NAICS codes for 

ethyl alcohol manufacturing (NAICS 

code 325193) and distilleries (NAICS 

code 312140) under the NAICS is useful 

and eliminates the problem of having to 

do a ‘‘fine grain’’ analysis. 

Accordingly, in response to 

commenters, our final rule references 

the NAICS codes 325193 and 312140 to 

exclude facilities using a natural 

fermentation process to produce ethanol 

from the definition of ‘‘chemical process 

plants.’’ We believe that by defining the 

‘‘chemical process plants’’ in this way, 

we retain the objectivity and ease of 

implementation inherent in our original 

guidance. 

The remaining regulatory changes 

address when fugitive emissions are 

counted for purposes of determining 

whether a source is a major source 

under the PSD, nonattainment NSR, or 

title V programs. Our final rule treats 

the term ‘‘chemical process plants’’ in 

those regulations in the same manner as 

we treat it for purposes of determining 

the major source threshold. 

IV. Policy Rationale for Action 

In our proposed rule, we expressed 

several reasons to support our proposal 

to change the definition of ‘‘chemical 

process plants.’’ First, we cited concerns 

related to the disparate treatment of 

ethanol fuel production verses 

production of ethanol intended for 

human consumption by applying two 

different major source thresholds. 

Because the two manufacturing 

processes are substantially similar, we 

believed that the process should be 

treated identically for purposes of the 

PSD and title V regulations regardless of 

the intended product. We also cited 

concerns that continuing to regulate the 

ethanol fuel industry, under the 100 tpy 

major source threshold, regardless of the 

production method could stymie the 

growth of the industry, and hamper our 

nation’s efforts toward energy 

independence. Some commenters 

agreed with our general approach. Other 

commenters asserted that a mere 

similarity in processes did not justify 

our proposed redefinition of the 

‘‘chemical process plant’’ category. 

Other commenters questioned whether 

permitting agencies treated the two 

types of ethanol production differently 

for regulatory purposes. 

After reviewing the comments, we reexamined whether our policy concerns 

remain valid, and affirm our conclusion 

that a change in the ‘‘chemical process 

plant’’ category definition is warranted. 

Although we received conflicting 

information as to how permitting 

authorities regulate ethanol intended for 

human consumption, especially at 

plants that also produce ethanol for fuel, 

we maintain the fundamental premise 

for our proposal, that ethanol, regardless 

of intended use, is produced through 

substantially similar processes, and that 

similar processes should be regulated in 

a similar way. Although there may be 

jurisdictional differences in the way 

these industries are regulated, we 

believe this further supports the need to 

clarify the definition of ‘‘chemical 

process plants’’ relative to the ethanol 

production industry as a whole and 

does not negate the fundamental basis 

on which we proposed the rule. 

We continue to believe that 

supporting our nation’s efforts toward 

energy independence is an important 

national goal, and that this 

consideration is appropriate in deciding 

how to balance our nations economic 

growth with environmental protection. 

The Energy Policy Act of 2005 (Pub. L. 

109–58) established a renewable fuel 

standard (RFS) that requires an 

increasing use of renewable fuels in our 

nation. It is clear that continued growth 

of the ethanol industry will play a vital 

role in achieving our nation’s energy 

and environmental objectives. 

While we are uncertain what impact 

this regulatory action may have on 

furthering our progress toward the goal 

of energy independence, we believe that 

including ethanol fuel in the ‘‘chemical 

process plants’’ presented potential 

obstacles for growth in the industry. 

These obstacles primarily include the 

time it takes to obtain a preconstruction 

permit, and, in some cases, the potential 

costs that may be incurred as a result of 

having to apply additional emissions 

controls. As we discuss, in section V, 

we conclude that this rule is not likely 

to result in significant net 

environmental harm. Nonetheless, even 

if our consideration of potential 

environmental consequences 

understates potential negative 

environmental consequences, we 

believe that the potential for other 

environmental benefits and the desire to 

support our nation’s energy policy 

objectives outweigh any potential 

negative environmental consequences 

that could potentially result from this 

rule. 

We maintain, as we did in the 

proposal preamble, that we have the 

discretion to define ‘‘chemical process 

plants’’ to exclude wet and dry corn 

milling facilities. As stated above, we 

based our proposed rule on the premise 

that ethanol production should be 

treated similarly regardless of whether it 

is produced using either the wet or dry 

corn milling process, and regardless of 

whether the end product is used as fuel 

or for human consumption because the 

process steps involved are essentially 

the same. As we noted in the proposal, 

the only difference is the final step 

where a small amount of denaturant 

(such as gasoline) is added to render the 

ethanol unfit for human consumption. 

This rationale also supports expansion 

of the exclusion to all facilities that 

produce ethanol through a natural 

fermentation process. We received 

numerous comments supporting this 

finding. Although some commenters 

pointed to differences in the production 

process, we are not persuaded that the 

differences justify disparate regulatory 

treatment. We also received comments 

justifying the expansion of our 

regulatory exclusion to other feedstock 

and end product uses. We discuss our 


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1 Chemical reaction. (2007). In Encyclopedia 

Britannica. Retrieved April 5, 2007, from 

Encyclopedia Britannica. Online: http// 

www.britannica.com/eb/article9110109; Chemical 

industry. (2007). In Encyclopedia Britannica. 

Retrieved April 5, 2007, from Encyclopedia 

Britannica. Online: http//www.britannica.com/eb/ 

article9108378. 

2 North American Industry Classification System. 

United States, 2002. Expanded Edition with Added 

‘‘Bridges.’’ Executive Office of the President. Office 

of Management and Budget. Pgs. 235–236, and pg. 

313. 

3 See e.g. Memo. Edwin B. Erickson, Regional 

Administrator, to George Clemon Freeman, Counsel 

for Reserve Coal Proportion Company, July 06, 

Continued 

responses to these comments in more 

detail in section V of this preamble. We 

did, however, receive a few comments 

stating that our regulatory approach is 

fundamentally flawed, because 

regardless of the similarity of process, 

ethanol fuel and perhaps ethanol 

production in general should be 

regulated under the 100 tpy threshold. 

Some commenters assert that we are 

not entitled to deference because such 

facilities fall within the plain meaning 

of the term ‘‘chemical processing plant.’’ 

Others assert that section 169(1) shows 

Congress’ intent to focus on a facility’s 

finished product and economic sector in 

which an industry competes. 

We do not believe that the term 

‘‘chemical process plant’’ is subject to a 

‘‘plain meaning interpretation.’’ There is 

not a universally accepted definition of 

chemical process, and accepted 

definitions differ depending on whether 

you view the term from a purely 

scientific sense or from an engineering 

sense, or for economic purposes. The 

scope of the chemical industry is in part 

shaped by custom rather than by logic 

and excludes industries that 

nevertheless engage in chemical 

processes, e.g., petroleum refineries are 

a separate category on the section 169(l) 

list.1 One definition offered by the 

commenter is so broad it would 

encompass nearly every manufacturing 

activity regardless of source category, 

and would render other categories on 

the source category list redundant. The 

specific chemical process relevant here, 

natural fermentation, is common to 

many industries. For example, natural 

fermentation is used by non-ethanol 

producing food manufacturers which 

Congress chose not to subject to the 100 

tpy. We find no ‘‘plain meaning’’ 

definition of ‘‘chemical process plant’’ 

that can be applied in light of these 

facts. Accordingly, we do not believe 

that whether or not an industry engages 

in a ‘‘chemical process’’ and specifically 

whether it engages in ‘‘natural 

fermentation’’ can be used as the 

decisive factor in determining whether 

Congress intended the industry to be 

included within the ‘‘chemical process 

plants’’ category. 

We also disagree that section 169 

clearly shows Congress’s intent on what 

factors we must consider in making 

source category determinations. As 

discussed below, we have used a variety 

of considerations in making source 

category determinations. We generally 

have not conducted economic analysis 

in making these decisions, nor have we 

based our decision solely on the end 

product produced or strictly followed 

an SIC approach for all categories. 

V. Significant Comments Received on 

the Proposal 

Significant comments received on, 

and our responses to, the proposed 

amendments to the ‘‘major emitting 

facility’’ definition are presented in the 

following paragraphs. 

A. What comments did we receive on 

our proposed changes to the ‘‘major 

emitting facility’’ definition? 

The Federal Register proposal 

preamble notes that most ethanol is 

produced in the U.S. from sugar or 

starch-based feedstock using two basic 

processes: The dry mill process and the 

wet mill process. The preamble stated 

that wet milling operations are 

specifically addressed under SIC Code 

2046 (‘‘Wet Corn Milling’’) under Major 

Group 20 (‘‘Food and Kindred 

Products’’). Wet corn milling units 

engaged in producing food products are 

subject to the 250 tpy threshold under 

PSD. The proposal provided that (1) 

Both wet and dry corn milling processes 

can produce ethyl alcohol for human 

consumption, (2) the processes are 

identical to those which produce ethyl 

alcohol for fuel (with some exceptions), 

and (3) industry stakeholders believe 

that the thresholds should be the same. 

Based on these reasons, we proposed to 

redefine ‘‘chemical process plants’’ 

under the definition of ‘‘major emitting 

facility’’ found in section 169(l) of the 

CAA to exclude wet and dry corn 

milling facilities that produce ethanol 

for fuel (Option 1). 

Several commenters on the proposal 

argued that there was insufficient 

explanation as to why we proposed the 

change for only one type of facility (i.e., 

corn milling facilities). Some of these 

commenters provided that we should 

extend the proposed exclusion to 

cellulosic biomass, sugar beets, and/or 

sugar cane facilities that produce 

ethanol fuel. A few commenters 

supported equal treatment of corn 

milling facilities regardless of the 

ethanol end product (i.e., for human 

consumption, ethanol fuel, industrial 

ethanol). The Corn Refiners Association 

(CRA) suggested that we expand the 

exclusion to all fermentation processes 

that result in products other than 

ethanol (in addition to ethanol) that 

replace petroleum feedstocks or are 

used to make food products (e.g., citric 

acid made from corn, propylene glycol 

made from corn), however, expanding to 

products other than ethanol is not 

within the scope of this rulemaking as 

it was not discussed at proposal. 

This final rule finalizes the exclusion 

for wet and dry corn milling ethanol 

production facilities and expands that 

exclusion to include ethanol production 

facilities that produce ethanol by 

natural fermentation included in NAICS 

codes 325193 and 312140 (includes 

denatured alcohol, nonpotable ethanol, 

nonpotable grain alcohol, potable ethyl 

alcohol, and grain alcohol beverages).2

The following subparagraphs present 

greater detail on the comments received 

on the proposed ‘‘major emitting 

facility’’ definition and whether the 

‘‘chemical process plants’’ exclusion for 

corn milling ethanol fuel production 

facilities should be expanded to 

facilities that produce ethanol fuel from 

cellulosic biomass, sugar beets, and 

sugar cane; and facilities that produce 

industrial ethanol from corn, cellulosic 

biomass, sugar beets, and sugar cane. 

1. Proposed Treatment of Corn Milling 

Facilities Under the ‘‘Major Emitting 

Facility’’ Definition 

Comments: One commenter asserted 

that the EPA, when applying section 

169(1), needs to discern whether a 

facility’s primary activity is a type listed 

as a 100 tpy ‘‘major’’ source in section 

169(1)—in this case, whether a facility’s 

primary activity is a chemical 

production process. Another indicated 

that our established policy requires that 

EPA look at the primary product 

produced and that we have not 

explained our change in policy. 

Response: While this rule represents a 

change in our definition of ‘‘chemical 

process plants’’, it does not represent a 

change in our general approach to 

determining the scope of source 

categories. In our proposed rule, we 

pointed to our August 7, 1980 

rulemaking wherein we indicated that 

we would use the 2-digit ‘‘Major Group’’ 

listings as defined by the SIC manual of 

1972 (as amended in 1977) for purposes 

of determining the scope of the source. 

In subsequent guidance, we clarified 

that we did not necessarily intend to 

follow the 1980 preamble approach for 

defining the scope of the source when 

determining the applicable major source 

threshold once the source is defined.3


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1996; and Memo. Request for PSD Applicability 

Determination, Golden Aluminum Company, San 

Antonio, TX, from William B. Hathaway, Director 

Air, Toxics and Pesticides Division to Steve Spraw, 

Deputy Executive Director, Texas Air Control 

Board, July 28, 1989. 

4 See Memo. Treatment of Aluminum Die Casting 

Operations for the Purposes of New Source Review 

Applicability, from Thomas C. Curran, Director 

Information Transfer and Program Integration 

Division, to Director, Office of Ecosystem 

Protection, Region I, et.al., December 4, 1998, and 

Memo. Applicability of Prevention of Significant 

Deterioration (PSD) and New Source Performance 

Standards (NSPS) to the Cleveland Electric 

Incorporated, Plant in Willioughby, Ohio, May 26, 

1992. 

5 See Memo. Treatment of Aluminum Die Casting 

Operations for the Purposes of New Source Review 

Applicability, from Thomas C. Curran, Director 

Information Transfer and Program Integration 

Division, to Director, Office of Ecosystem 

Protection, Region I, et. al., December 4, 1998. 

6 See Memo. Classification of the Bardstown Fuel 

Alcohol Company under PSD, from Edward E. 

Reich, Director Division of Stationary Source 

Enforcement, to Thomas W. Devine, Director Air 

and Hazardous Materials Division, Region IV, 

August 21, 1981. 

Importantly, contrary to some 

commenters’ assertions, EPA explicitly 

rejected the use of the ‘‘primary activity 

test’’ as the decisive means of defining 

source categories listed under section 

169(1). Id. As the proposal preamble 

explains, the SIC manual was not 

designed for regulatory application, but 

was developed primarily for the 

collection of economic statistics and for 

the consistent comparison of economic 

data between various sectors of the U.S. 

economy. The use of SIC codes by the 

EPA is not required by the CAA, nor 

was it referenced in any legislative 

history related to section 169(1) of the 

CAA. While it may be appropriate for 

economic statistical purposes to place 

certain types of sources in the same or 

in different categories, EPA never 

intended the SIC code to be the decisive 

factor for determining whether a given 

stationary source should be regulated as 

a listed source category. 

As one commenter properly pointed 

out, we use the SIC code manual only 

as the starting point for determining 

which pollutant-emitting activities 

should be considered as part of the same 

source category, but rely on case-by-case 

assessments to determine whether a 

particular stationary source belongs in a 

given source category. (Docket No. EPA– 

OAR–HQ–2006–0089–0086).4

Using this case-by-case approach, we 

applied different rationales for 

determining if a particular stationary 

source falls in a given source category. 

For example, we relied on the existing 

NSPS definition of municipal waste 

combustor in determining whether a 

source falls within a listed category. Id. 

We have also generally stated that we 

believe that Congress intended that we 

consider the source’s pollutant-emitting 

activity in determining whether a source 

is within a listed source category rather 

than the source’s finished product. In 

some cases, the listed source category 

does not directly correspond to a 

specific SIC code, and we considered 

the type of feedstock, the process steps, 

and end products produced to 

determine whether a given stationary 

source was part of the source category.5

For the chemical process plant 

category, EPA took a much more 

straightforward approach. Instead of 

specifically considering the pollutant 

emitting activity, the feedstocks, process 

steps, end products, or application of 

existing NSPS definition to making 

case-by-case determinations, EPA chose 

to specifically define the category based 

on SIC 28. We based this decision on a 

desire to promote consistency with 

source scope determinations, and for 

ease of implementation and objectivity.6

Notably, however, in that same 

memorandum we stated that we have 

the ability to amend the definition of 

chemical process plant to add to or 

delete from the scope of the source 

category, especially in light of the 

inconsistent treatment of the alcohol 

fuel and beverage alcohol processes, but 

declined to do so at that time. With this 

action, we are acting in light of that 

continuing discretion and the facts 

before us now. 

Comment: Several commenters assert 

that EPA places too much reliance on 

Congress’ use of the report submitted by 

Research Corporation of New England 

(‘‘Research Corp. report’’) and the fact 

that ethanol production was not 

specifically addressed in the report. 

Commenters assert that Congress’ 

silence can not be taken as an intent to 

exclude ethanol from the ‘‘chemical 

process plants’’ definition. One 

commenter believes, that the mere fact 

that chemical processes occur and that 

toxic chemicals are added is enough to 

conclude that Congress would intend to 

regulate the industry as a chemical 

process plant. A commenter also stated 

that Congress used broad terms like 

‘‘chemical processing plants’’ precisely 

to capture new ways of making products 

and to avoid having to change the 

statute in the future to capture these 

activities. 

Response: As noted in the proposal 

preamble and repeated here, section 111 

of the CAA requires the Administrator 

of EPA to establish Federal standards of 

performance for new stationary sources 

which may significantly contribute to 

air pollution and was intended by 

Congress to complement the other air 

quality management approaches 

authorized by the 1970 CAA. After 

enactment of section 111, EPA hired 

Research Corporation of New England 

(Research Corp.) to study stationary 

sources of air pollution in order to 

establish priorities for developing and 

promulgating NSPS. 

Because of limited resources, EPA 

could not feasibly set NSPS 

requirements for all categories of 

stationary sources simultaneously. 

Therefore, the goal of the Research Corp. 

study was to identify sources for which 

NSPS controls would have the greatest 

impact on reducing the quantity of 

atmospheric emissions. Research Corp. 

examined approximately 190 different 

types of stationary sources that 

potentially could be determined to be 

major emitting facilities, and provided 

information on the types of air 

pollutants that those sources emitted. 

The Research Corp. study was used by 

EPA in setting priorities for the order in 

which it would promulgate NSPS 

requirements for categories of stationary 

sources. 

The Research Corp. study was also 

relied on by Congress in identifying the 

28 categories of stationary sources 

specifically listed in the definition of 

the term ‘‘major emitting facility’’ in 

section 169(1) of the CAA. 122 Cong. 

Rec. 24,520–23 (1976). As explained by 

Senator McClure in the Congressional 

Record, the EPA Administrator 

examined the data from the draft 

Research Corp. study and determined 

that 19 of the stationary source 

categories examined should initially be 

classified as major emitting facilities. 

Senator McClure further explained that 

the Senate Committee added nine more 

categories of stationary sources to the 19 

selected by EPA for a total of 28 source 

categories. 122 Cong. Rec. at 24,521.2 

As discussed in the proposal 

preamble, in discussing the specific 

sources identified in section 169(1), 

Senator McClure stated: 

Mr. President, I ask unanimous consent 

that an extract from that report of the 

Research Corp. of New England, listing the 

190 types of sources, from which the EPA 

took 19, and the committee took 28, be 

printed in the Record at this point as an 

illustration of what the committee examined 

and the kinds of sources the committee 

intended to include and exclude, recognizing 

that it is neither exclusive nor invariable. 

There is administrative discretion to add to 

the list, to change the list. But the committee 

spoke very clearly on its intent on that 

question. 

122 Cong. Rec. at 24,521 (1976). 

As a result of Senator McClure’s 

action, the table from the draft Research 

Corp. report containing the list of 190 


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7 Memorandum from Mary Lalley, Eastern 

Research Group, Inc., to Bob Rosensteel. Ethanol 

Production Industry. U.S. EPA, July 2, 2002. See 

Docket No. EPA–HQ–OAR–2006–0089–0009. 

8 Memorandum from Mary Lalley, Eastern 

Research Group, Inc., to Bob Rosensteel. Ethanol 

Production Industry. U.S. EPA, July 2, 2002. See 

Docket No. EPA–HQ–OAR–2006–0089–0009. 

types of sources was printed in the 

Congressional Record. The 

approximately 190 source categories 

identified in Research Corporation’s 

report were further classified into ten 

general groups for purposes of the 

study—stationary combustion sources, 

chemical processing industries, food 

and agricultural industries, mineral 

products industries, metallurgical 

industries, and miscellaneous sources 

(evaporation losses, petroleum industry, 

wood products industry, and assembly 

plants). For the chemical process industry 

grouping, the Research Corp. study 

considered 24 different source 

categories and their associated 

pollutants. Notably, within the chemical 

process industry listings in the 1977 

final report and in the 1976 draft report 

(as incorporated into the Congressional 

Record) there is no listing which refers 

to ethanol production, ethanol fuel 

production, or corn milling operations. Given this history, we agree with 

commenters that Congress’ silence on 

the matter can not be taken as an intent 

to exclude ethanol, nor however, do we 

believe that the silence can be taken as 

an intent to include ethanol within the 

chemical process plant definition. It is 

precisely because Congress did not 

express an intent, and because the 

Congressional record shows that 

Congress recognized that the list was 

neither ‘‘exclusive or inclusive’’ that we 

believe we have discretion to determine 

whether or not the ethanol industry 

belongs in the chemical process plants 

source category. We are not persuaded that the mere 

fact that chemical reactions occur or 

that toxic chemical are added would 

have compelled Congress to include the 

industry within the category. These 

factors are too broad and too common in 

a multitude of industries to be effective 

criteria for categorizing sources. Comment: We received many 

comments supporting our position that 

basic steps of both processes are similar 

for both wet and dry corn milling. One 

commenter explained that a plant may 

produce beverage, industrial, and 

ethanol fuel at the same plant using the 

same equipment. Conversely, one commenter provided 

that the production of ethanol for fuel 

involves processes that are different in 

character than production of ethanol for 

human consumption, involving more 

steps and additional distillation that is 

necessary, among other things, to 

produce 100% ethanol (200 proof) 

needed for use as a fuel. This 

commenter pointed out that the closer 

the distillation process gets to 

producing 100% ethanol, the more 

energy/fuel is consumed, the more steps 

required, and the more pollutants 

emitted from the chemical processing 

plant. 

One commenter explained that while 

the two processes are theoretically the 

same, ethanol fuel is produced on a 

much larger scale, and competes with 

other fuel markets. They provided that 

alcohol for human consumption does 

not contain as much alcohol as ethanol 

fuel after the distillation process (40– 

50% compared to 90–100% ethanol), 

and is subject to different regulations 

(e.g., health, food safety). The 

commenters also asserted that the use of 

a molecular sieve in ethanol fuel 

production distinguishes this 

production from human alcohol 

consumption. 

Finally, one commenter asked EPA to 

explain in greater detail its conclusion 

that the two processes are the same. 

One commenter stated that ethanol 

fuel production facilities are more like 

refineries than an alcohol for 

consumption facility. They argued that 

ethanol fuel production facilities should 

be regulated similarly to a chemical 

process plant as that is what they are 

producing. 

Response: In the U.S., ethanol (ethyl 

alcohol) is currently being produced 

either synthetically or through the 

fermentation of sugars derived from 

agricultural feedstocks. For ethanol 

produced synthetically, either ethylene 

or hydrogen (H2) and carbon monoxide 

(CO) are used as the feedstock. As of 

2002, only two facilities in the U.S. 

were producing synthetic ethanol.7 The 

majority of ethanol produced in the U.S. 

is produced from sugar or starch-based 

feedstock (e.g., corn, millet, beverage 

waste) using two basic processes: the 

dry mill process and the wet mill 

process. The key difference between 

these two processes is the initial 

treatment of the grain. In the wet mill 

process, the grain is soaked and then 

ground to remove germ, fiber, and 

gluten from the starch prior to cooking. 

In the dry mill process, the grain or 

feedstock is not separated into its 

constituent parts prior to cooking. Both 

wet and dry milling operations produce 

ethanol as well as other coproducts. 

‘‘Co-products from the dry mill process, 

separated from the ethanol in the 

distillation step, include distiller’s dried 

grain (DDG) and solubles (S), which are 

often combined and referred to as 

DDGS. DDGS is used as an animal feed. 

In the wet mill process, co-products are 

separated from the ethanol production 

process in the initial grinding or milling 

step. Coproducts from the wet milling 

process include fiber and gluten, which 

are used for animal feed and corn oil.’’ 

8

Most new ethanol production 

capacity comes from dry mill processing 

facilities. Wet milling operations, on the 

other hand, can produce ethanol, 

including ethanol for fuel, but are 

typically primarily engaged in 

producing starch, syrup, oil, sugar, and 

by-products, such as gluten feed and 

meal. For ethanol which will be used as 

fuel, toxic solvents (typically gasoline) 

are added to the ethanol to render it 

unfit for human consumption 

(denatured). This additional step is 

required to develop ethanol fuel 

regardless of whether the dry or wet 

mill process was employed to develop 

the initially potable ethanol. 

We recognize that though the corn 

milling ethanol production processes for 

ethanol fuel and ethanol for human 

consumption are theoretically the same, 

ethanol fuel is produced on a much 

larger scale, and competes with other 

fuel markets. We also acknowledge that 

alcohol for human consumption does 

not typically contain as much alcohol as 

ethanol fuel (or some other denatured 

ethanol products (e.g., denatured 

ethanol products made for industrial 

use) after the distillation process (40– 

95% for distilled spirits), and is subject 

to different regulations (e.g., health, 

food safety). This does not negate the 

fact that the natural fermentation and 

distillation processes (though the 

number of distillation steps and length 

of fermentation may vary) up until the 

time the denaturant is added for ethanol 

fuel (or other denatured ethanol 

products) are similar. We are not 

persuaded that these differences are 

significant or that they warrant different 

treatment under PSD. Given that the 

basic goal of PSD are to ensure that 

economic growth will occur in harmony 

with the preservation of existing clean 

air resources, that other regulations in 

place ensure equivalent or near 

equivalent BACT level of control will 

continue, and that a State’s minor NSR 

program will apply when major NSR/ 

PSD does not apply, we believe that the 

basic goal of PSD will be maintained. 

2. Expansion to Other Ethanol 

Production Processes 

Comments: Supports Expansion to 

Other Feedstock. Two commenters 

requested that the proposed preferred 


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option (Option 1) be expanded to 

include facilities that produce ethanol 

fuel from molasses. 

One commenter noted that there are 

facilities other than corn milling which 

are capable of producing ethanol, 

notably molasses processing plants, and 

they should also be excluded from the 

definition of ‘‘major source’’ under the 

PSD, NSR, and title V programs. They 

provided that processes for both the 

production of ethanol from sugarcane 

molasses and from corn are similar, and 

because the processes are similar, the air 

emissions from the production of either 

product would also be similar. 

One commenter stated that EPA’s 

proposed rulemaking specifically 

requested public comments with respect 

to how future technological 

developments in the ethanol industry 

may be affected by the proposed 

rulemaking. They explained that while 

the current ethanol industry is 

dominated by the wet and dry corn 

milling process, the future of the 

ethanol industry could involve 

additional grain feedstocks such as 

wheat, barely, or rice as well as 

cellulosic feedstock’s such as wood 

waste, switchgrass, and municipal solid 

waste. This commenter provided that 

they believed since EPA’s proposal is 

rather narrowly focused on wet and dry 

corn milling newer ethanol production 

technologies currently under 

development could fall into the same 

regulatory quandary EPA is trying to 

correct through their proposal. They 

recommended that EPA’s final 

rulemaking be expanded to also cover 

the other ethanol production 

technologies that may be developed in 

the future. They suggested that the EPA 

modify the currently proposed rule 

language to adopt language more 

consistent with the various NSPS rules 

(such as the synthetic organic chemical 

manufacturing industry (SOCMI) 

wastewater NSPS Subpart YYY 

standard) and exclude any process that 

uses ‘‘natural fermentation’’ to produce 

ethanol from the definition of a 

‘‘chemical processing plant’’ under 

section 169. 

One commenter stated that they 

believed that it is appropriate to treat all 

other types of facilities which produce 

ethanol from cellulosic biomass feed 

stocks similarly to how corn milling 

facilities are being proposed to be 

treated under Option 1. 

One State commenter provided that 

other environmental rules have made 

distinctions with regard to applicability 

between ethanol by fermentation/ 

biological processes and synthetic 

ethanol production: 

1. NSPS subparts NNN and RRR— 

excludes ethanol by fermentation. The 

commenter stated that EPA has 

previously determined that ethanolmanufacturing facilities may be exempt 

from NSPS subparts RRR and NNN on 

a case-by-case basis. The commenter 

explained that in this instance, the 

ethanol facilities in question use a 

biological process to ferment the 

converted starches in corn into ethanol. 

These NSPS subparts did not envision 

unit operations for biological processes. 

2. Categorical waste water effluent 

limits for Organic Chemicals, Plastics 

and Synthetic Fibers, part 414— 

excludes ethanol by fermentation. The 

provisions of this part do not apply to 

any process wastewater discharges from 

the manufacture of organic chemical 

compounds solely by extraction from 

plant and animal raw materials or by 

fermentation processes. 

The commenter argued that EPA’s 

proposal of Option 1 would be 

consistent with the above programs and 

that the exclusion should not be limited 

to ‘‘corn’’ wet and dry milling to make 

ethanol fuel. They supported their 

position by stating that several plants 

currently use milo along with corn to 

make ethanol fuel, and that the future of 

ethanol appears to be in the use of 

biomass, i.e., cellulosic material. They 

explained that the only difference 

would be that the feedstock is a biomass 

material other than corn; and that 

fermentation and distillation processes 

would be essentially unchanged. They 

asserted that if the rule is not expanded 

to exclude cellulosic material, there 

could be a negative impact on the 

growth of cellulosic ethanol. This 

commenter argued that this could have 

an unintended complication as the 

energy balance favors ethanol from 

cellulosic feed stock over ethanol by 

corn. 

One commenter stated that it should 

not matter what biomass or 

carbohydrate feedstock is used in the 

ethanol production process as the 

natural fermentation and distillation 

steps would be the same as they are for 

corn milling ethanol production. 

One commenter provided that 

chemical feed stocks made from 

renewable sources should all be 

excluded as many of the products 

subject to the definition of chemical 

process plant were originally 

synthetically produced when SIC codes 

were established (e.g. citric acid and 

propylene glycol made from corn). 

Opposes Expansion to Other Feedstock 

One commenter opposed any 

suggestion to exclude ‘‘other types of 

facilities which produce ethanol fuel, 

such as those using cellulosic biomass 

feedstocks, e.g., solid waste, agricultural 

wastes, wood, and grasses * * * from the 

chemical process plants definition due 

to having production processes similar 

to those found at wet and dry milling 

facilities in cases where potable ethanol 

or ethanol fuel is being produced,’’ or 

for any other reason. They provided that 

while they believed that the use of 

ethanol (especially cellulosic ethanol) as 

a transportation fuel has significant 

potential environmental benefits, the 

high cost of natural gas had recently 

caused a shift from the use of natural 

gas to coal for process heat which they 

believed would lead to an erosion of the 

carbon benefits of displacing petroleumbased fuels. 

Response: In the proposal preamble, 

we solicited comment on whether other 

types of facilities that produce ethanol 

fuel, such as those using cellulosic 

feedstocks, e.g., solid waste, agricultural 

wastes, wood, and grasses, should also 

be considered for exclusion from the 

chemical process plants definition due 

to having similar processes to those 

found at wet and dry milling facilities 

in cases where potable ethanol or 

ethanol fuels is being produced. We 

requested information, including 

process flow diagrams, on the processes 

that would be used to develop ethanol 

using other feedstock. Process diagrams 

were provided that indicated that 

although the processes to produce 

sugars from these feedstocks differ, 

similar fermentation and distillation 

processes in the production of ethanol 

fuel from cellulosic material would be 

employed. Commenters also provided 

process diagrams illustrating similar 

processes in the production of ethanol 

from molasses (which is used as a 

feedstock in the production of rum). As 

with cellulosic feedstocks, the 

breakdown of these feedstocks to 

produce sugars may differ, but the 

ethanol fermentation and distillation 

processes were similar. In molasses 

(using both sugar beets and sugar cane 

feedstock) ethanol production, the 

molasses is diluted with water, acidified 

to precipitate minerals and then 

decanted to produce the mash. Yeast 

and nutrients are added to the mash and 

fermentation converts the sugars in the 

molasses to alcohol. There, fermented 

mash is then distilled to separate and 

concentrate the ethanol. The ethanol is 

dehydrated and, if being used to 

produce fuel alcohol, denatured. There 

are currently no U.S plant producing 

ethanol from sugar feedstocks (sugar 

beets, sugar cane) therefore there is little 

data available on their feasibility as an 

ethanol feedstock, however, Brazil and 


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9 BBI International. INNOVATIONS in Dry-Mill 

Ethanol Production. 

several other countries are producing 

ethanol from these feedstocks. 

In cellulosic ethanol production, acid 

is introduced to the feedstock at high 

temperatures to release hemicellulose 

sugars (depending on the type of 

cellulose used). If acids are toxic, they 

are removed prior to saccarification 

(break down of starches) and 

fermentation steps. Enzymatic 

hydrolysis to produce sugars from 

cellulose is another alternative being 

researched in pilot and demonstration 

commercial plants. The result is a 

‘‘beer’’ with 4 to 5 percent alcohol 

content by weight. The distillation step 

is employed to produce ethanol at about 

92 to 93 percent alcohol which must be 

processed by a vapor-molecular sieve (to 

further dehydrate the ethanol) to create 

fuel (the last step involving the adding 

of a denaturant). It is important to note 

that the use of a molecular sieve is not 

unique to cellulosic biomass ethanol 

production facilities as it is something 

that is used at many corn milling 

ethanol production facilities. Molecular 

sieves have become a popular means to 

dehydrate ethanol as they are low cost, 

environmentally friendly, and require 

less energy. Facilities that use molecular 

sieves replace azeotropic distillation 

systems that use cyclohexane or 

benzene (HAP), which were expensive, 

costly to operate, and energy intensive.9

There is currently no commercial 

cellulosic ethanol production plant 

operating in the U.S., however, there are 

several existing pilot plants, and several 

commercial plants are in the planning 

stages. 

Based on the process diagrams and 

information received from commenters 

that indicate that the fermentation and 

distillation processes are similar 

(included as part of the technical 

record), even though the pre-steps and 

after-steps may differ, we are expanding 

the exclusion of the definition of ‘‘major 

emitting facilities’’ to include ethanol 

production facilities that produce 

ethanol through natural fermentation 

processes included in NAICS codes 

325193 or 312140. 

We are not excluding other chemicals 

(e.g., citric acid and propylene glycol 

made from corn) made from renewable 

sources with this final rule. The scope 

of this rule is ethanol production and 

processes and there was no solicitation, 

or sufficient basis provided, to support 

expansion of exclusion to other 

chemicals. 

B. Why are ethanol production facilities 

regulated differently under different 

programs and standards? 

Several commenters provided input 

on the historic regulatory treatment of 

wet and dry corn milling facilities 

which produce ethanol fuel. Some of 

the commenters stated that EPA’s 

proposal to exclude wet and dry corn 

milling facilities from the definition of 

‘‘chemical process plants’’ was 

consistent with historic regulatory 

treatment, while others argued that it 

was inconsistent with historic 

regulatory treatment. Comments: The following comments 

were received on the historic and 

current regulatory treatment of wet and 

dry corn milling facilities that produce 

ethanol fuel. 

<bullet≤ One commenter requested 

clarification of rule applicability, with 

regards to ethanol production, of 

numerous NSPS and MACT standards. 

<bullet≤ Two industry commenters 

suggested that the rule include changes 

to the relevant NSPS under 40 CFR part 

60 since alcohol production facilities 

are potentially subject to several 

standards of performance for new 

stationary sources, including 40 CFR 

part 60, subparts Kb (volatile organic 

liquids storage vessels), VV (equipment 

leaks of volatile organic compounds 

(VOC) in the SOCMI), NNN (SOCMI 

distillation operations), and RRR (VOC 

emissions from SOCMI reactor 

processes. <bullet≤ Two State commenters 

provided examples where wet and dry 

corn milling facilities which produce 

ethanol fuel are treated as chemical 

process plants (40 CFR part 60, subparts 

VV, NNN, RRR (in Minnesota); 40 CFR 

part 63, subpart FFFF Miscellaneous 

Organic NESHAP (the MON Rule); AP– 

42 (Chapter 9.9.7 for Corn Wet Milling)). <bullet≤ Two environmental 

consultants, two industry commenters, 

and one State noted that EPA 

rulemakings and associated interpretive 

guidance have either established 

exemptions (or allow sources to seek 

exemptions on a case-by-case basis) for 

chemicals produced through 

fermentation (as with corn milling 

ethanol production) from various 

SOCMI industry regulations, including 

the NSPS subparts RRR (SOCMI process 

reactors) and YYY (SOCMI wastewater 

units). 

<bullet≤ One State commenter stated 

that categorical wastewater effluent 

limits for Organic Chemicals, Plastics, 

and Synthetic Fibers found in 40 CFR 

part 414 (promulgated under the Clean 

Water Act) excludes ethanol 

manufacturing by fermentation. <bullet≤ Two industry commenters 

were concerned that the 27th listed 

source category in the NSR and title V 

programs also regulates ethanol plants 

as a result of the NSPSs captured under 

this source category. 

<bullet≤ One environmental 

commenter stated that EPA has treated 

‘‘ethanol blending facilities’’—facilities 

that mix ethanol into gasoline—as 

refineries. 40 CFR 80.2(u). (‘‘Ethanol 

blending plant means any refinery at 

which gasoline is produced solely 

through the addition of ethanol to 

gasoline, and at which the quality or 

quantity of gasoline is not altered in any 

other manner.’’) (emphasis added). 

Additionally, the commenter argued 

that EPA has referenced the distinction 

between ‘‘chemical grade’’ ethanol that 

is used in transportation fuel and other 

kinds of ethanol. See 40 CFR 

79.55(e)(1)–(2). 

Response: The applicability of 

differing rules is standard-specific and 

determinations were made under 

individual rulemakings and will not be 

changed under this rulemaking. There is 

no directive for the applicability to be 

the same across CAA programs and 

standards and applicability 

determinations need to be determined 

on a case-by-case, or standard-bystandard, basis. 

For example, ethanol is listed as a 

SOCMI chemical for which 40 CFR part 

60, subpart YYY (SOCMI wastewater 

units) applies, however, the 

supplemental proposed rule (63 FR 

67988; September 12, 1994) excludes 

certain processes from the definition of 

chemical process unit (CPU) because 

they were not considered SOCMI 

processes, but are sometimes associated 

with SOCMI processes. Organic 

chemicals extracted from natural 

sources or totally produced from 

biological synthesis such as pinene and 

beverage alcohol were specifically 

excluded from the CPU definition. 

Under 40 CFR part 60, subpart YYY, the 

determination for excluding biological 

processes was based on the designation 

for the process unit, in contrast to the 

plant site. Under the 40 CFR part 63, 

subpart FFFF (the Miscellaneous 

Organic National Emission Standards 

for Hazardous Air Pollutants (NESHAP) 

(the MON)) standards, the applicable 

miscellaneous organic chemical process 

unit for which standards apply includes 

all equipment that collectively function 

to produce a product or material 

described in the standard (including 

denatured alcohol). The pollutant to be 

controlled (e.g., HAP, VOC, particulate 

matter (PM)), processes to be controlled, 

available control technologies, timing of 

standard development, and program and 

standard directives drive the 

applicability of individual standards. 


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As for the commenters’ concern that 

the 27th listed source category in the 

NSR and title V programs regulates 

ethanol plants as a result of the NSPSs 

captured under this source category, 

this concern would not be valid as all 

of the NSPSs listed by the commenters 

(40 CFR part 60, subparts Kb, VV, NNN, 

and RRR) were proposed and 

promulgated after August 7, 1980. The 

27th listed source category referenced 

by the commenters includes ‘‘[a]ny 

other stationary source category which, 

as of August 7, 1980, is being regulated 

under section 111 or 112 of the CAA.’’ 

C. Do we need to make an express 

section 302(j) finding? 

As noted in the proposal preamble, 

when we promulgated the list of source 

categories relative to the definition of 

‘‘major emitting facility’’ in the NSR 

regulations on August 7, 1980 (45 FR 

52676), we adopted this same list to 

identify source categories for which 

fugitive emissions were to be counted in 

determining whether a source was a 

major source. We promulgated the 28 

source categories as a result of the 

decision in Alabama Power v. Costle, 

626 F. 2d. 323 (D.C. Cir. 1979). In 

Alabama Power, the court held that 

‘‘fugitive emissions are to be included in 

determining whether a source or 

modification is major only if and when 

EPA issues an appropriate legislative 

rule.’’ The proposed rule Option 1 was 

to change the definition of chemical 

process plants with the definition of 

major stationary source and major 

source and would correspondingly also 

change our interpretation of that term 

relative to the 302(j) source category list. 

At proposal we stated that since we 

were not changing the list of source 

categories in the regulations, a section 

302(j) finding was unnecessary. Some 

commenters on the rule disagreed with 

EPA’s position, and stated that EPA 

needs to make an express section 302(j) 

finding in order to redefine when 

fugitive emissions are counted. 

Comments: Several commenters 

opposed EPA’s proposal to de-list cornbased ethanol fuel production from the 

list of facilities identified by EPA, 

pursuant to CAA section 302(j). One 

commenter stated that the EPA can not 

avoid making the necessary 

determinations to list a facility or source 

pursuant to section 302(j) by merely 

listing categories and later determining 

which sources and facilities to include 

in the category. The commenter asserts 

that, in 1980, the EPA determined that 

‘‘chemical process plants,’’ as defined in 

the SIC Manual, which specifically 

includes ethanol production plants, are 

a type of source category for which 

fugitive emissions should be counted. 

The commenter stated that EPA made 

this determination, based on its finding 

that these sources could degrade air 

quality significantly, and that the costs 

of listing this category were not 

unreasonable compared to the benefits. 

The commenter provided that the CAA 

does not allow EPA to identify generic 

categories that include unspecified 

sources. The commenter argued that 

EPA’s proposal violates the CAA and 

EPA’s own prior interpretation of the 

CAA. 

Another commenter stated that the 

EPA must specifically evaluate whether 

eliminating this requirement is 

appropriate based on criteria that relate 

to the intent of the PSD program and the 

air quality impact of such emissions. 

The commenter explained that the EPA 

has adopted criteria for the very purpose 

of determining whether to consider 

fugitive emissions—those criteria 

require EPA to examine (1) Whether 

sources in the category could degrade 

air quality; and (2) whether the cost of 

controlling fugitives are unreasonable 

compared to the expected benefits. The 

commenter argued that it would be 

arbitrary and irrational for EPA to 

affirmatively change its treatment of 

these sources without subjecting that 

decision to a meaningful substantive 

evaluation. The commenter asserts that 

because the initial classification 

imputed a need to address fugitive 

emissions from these plants, and 

because nothing in EPA’s proposal 

functions to counter that expectation, 

the commenter believes that it was not 

rational for EPA to exclude ethanol fuel 

plants from the fugitive emissions 

requirements without conducting an 

appropriate assessment. 

Response: As we stated in the 

proposal, we are not changing the list of 

categories that we developed by rule 

under section 302(j). We are merely 

reinterpreting what is included within 

the definition of one of those categories. 

When EPA added chemical processing 

plants to the section 302(j) list in 1980, 

it did so based on a very general finding 

that sources within the category could 

degrade air quality and did not make 

any specific determination as to the 

appropriateness of counting fugitive 

emissions from any particular source 

types that may fall within the category. 

Thus, we do not think that interpreting 

the category to exclude a narrow set of 

facilities triggers the section 302(j) 

rulemaking requirement that applies 

when categories are added to the list. 

Nonetheless, even if this action 

triggers the section 302(j) rulemaking 

requirement, we believe this rulemaking 

constitutes a sufficient section 302(j) 

rule that is consistent with the way we 

interpreted that requirement in 1980 

and re-affirmed in 1984. (45 FR 52676, 

52690 (Aug. 7, 1980) and 49 FR 43202 

(Oct. 28, 1984)). Specifically, we 

determined that our action to list a 

category under section 302(j) may be 

based on a policy decision after 

considering certain criteria, that we do 

not need extensive technical analysis to 

support our determination, and that the 

purpose of rulemaking is to afford the 

public an opportunity to comment on 

the Administrator’s decision. 

In 1979, when we initially proposed 

to use the section 169(1) source category 

list, our stated rationale for the proposal 

was only that we decided to focus first 

on the listed sources because of our 

experience in quantifying the ‘‘fugitive 

emissions’’ from these sources. (44 FR 

51924, 51931 (Sept. 5, 1979)). Similar to 

comments received on this proposed 

rule, we received comments then that 

our rulemaking then was inadequate, 

and that we should have conducted 

technical analysis to support our 

proposed rule. We rejected commenters 

assertions. We also stated that the 

purpose of the rulemaking was to afford 

the public the opportunity to comment 

on the Administrator’s decision, and to 

allow commenters to present factual or 

policy arguments that it would not be 

appropriate to include fugitive 

emissions in threshold calculations. Id. 

In our 1980 final rule, we stated that our 

decision to use the section 169(1) source 

category list was ‘‘a matter of policy.’’ 

We reiterated our position that we had 

greater experience in quantifying 

fugitive emissions from sources on the 

section 169(1) source category list; and, 

we observed that those sources have 

traditionally been considered the major 

polluters in the country. Despite the 

limited nature of the technical support 

for our proposal, we concluded that we 

conducted an adequate section 302(j) 

rulemaking since the affected sources 

were afforded an opportunity to 

comment on our policy decision. (45 FR 

at 52690–92). 

In 1984, after re-examining our 

interpretation of the section 302(j) 

requirements, we affirmed that the 

rulemaking requirements of section 

302(j) were intended to afford the public 

an opportunity to comment on the 

Administrator’s decision to list a 

category, and that we were not required 

to undertake extensive technical 

analysis to support our determination. 

That 1984 preamble discussion 

addressed two criteria relevant to the 

Administrator’s decision to require 

sources to include fugitive emissions in 

threshold applicability determinations. 

We note that commenters 


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mischaracterized the manner in which 

the two criteria operate. The final rule 

stated that 

[a] determination by EPA that the sources 

in a category pose a threat of significant air 

quality degradation in effect establishes a 

presumption that the sources should be 

subject to PSD and nonattainment review * 

* *. Commenters then may seek to rebut this 

presumption by producing a record that 

unreasonable social or economic costs 

relative to the anticipated benefits would 

occur if PSD or nonattainment review were 

applied to a particular category of sources * 

* * 

(49 FR at 43203–08). 

Importantly, we discussed these 

criteria in light of our overall belief that 

listing a category involved the Agency’s 

exercise of policy discretion for which 

we carry a very low analytical burden in 

deciding to list a source category. Under 

this interpretation, section 302(j) 

functions as a useful ‘‘safety valve,’’ 

while at the same time minimizing the 

expenditure of Agency resources. 49 FR 

43202, 43208 (October 26, 1984). 

Notably, the 1984 final rule preamble 

did not address how or whether that 

requirement applies to EPA’s decision 

to interpret a category already on the list 

to exclude a narrow set of sources. 

Consistent with the ‘‘safety valve’’ 

purpose served by a section 302(j) 

rulemaking, we believe that it is not 

necessary to require a negative finding 

with respect to the same criteria before 

we interpret a category on the list to 

exclude certain types of sources. In sum, 

having made a policy decision based on 

a limited technical finding, we do not 

believe that our technical burden now 

in acting to refine a category on the list, 

should be greater than the technical 

analyzes we undertook in listing the 

categories in the first instance. 

Notably, as we stated, when EPA 

added ‘‘chemical processing plants’’ to 

the section 302(j) list in 1980, it did so 

based on a very general finding that 

sources within the category could were 

considered major polluters. We did not 

make any specific determination as to 

the appropriateness of counting fugitive 

emissions from any particular type of 

stationary sources within that category. 

At the time we conducted the section 

302(j) rulemaking, few ethanol facilities 

existed and inclusion of ethanol 

manufacturers was not specifically 

analyzed in our section 302(j) rule. 

When we examined the issue more 

closely in 1981, we made a policy 

decision without conducting technical 

analysis, to include ethanol fuel 

manufacturing within the chemical 

processing plant category. We based this 

decision on a desire to maintain 

consistency with use of SIC 28 and ease 

of implementation. Thus, before now, 

we considered this industry to be a 

source within the listed category. 

However, we find that the category 

should not include these sources or 

others who engage in natural 

fermentation process to produce 

ethanol. We believe that it is not 

necessary to require a negative finding 

with respect to the criteria that apply to 

list a category under section 302(j) 

before we interpret a category on the list 

to exclude certain types of sources. We 

believe that the economic and policy 

rational for the exclusion of certain 

ethanol production facilities from the 

chemical processing plant category for 

purposes of defining major emitting 

facility that we present elsewhere in the 

preamble to the proposed rule and in 

this preamble also provides ample 

support for a section 302(j) 

determination not to count fugitive 

emissions from such facilities. 

This decision is precisely the kind of 

‘‘flexibility to provide industry-byindustry consideration and appropriate 

tailoring of coverage’’ envisioned by the 

Alabama Power Court (Alabama Power 

Co. v. Costle, 636 F. 2d 323, 369 (D.C. 

Cir. 1979). Having been afforded the 

opportunity to comment on the 

Administrator’s decision, commenters 

failed to present compelling factual or 

policy arguments based on specific 

information which show that our policy 

decision is inappropriate. Accordingly, 

we have satisfied the section 302(j) 

rulemaking requirement. 

D. What are the enforcement 

implications of these final amendments? 

Comments: One commenter asserted 

that the new rule would represent a 

drastic about-face in Federal 

environmental policy, and could trigger 

revoking of consent decrees, refunds of 

fines, and removal of pollution control 

equipment. The commenter explained 

that in the last four years, Department 

of Justice (DOJ) and EPA attorneys have 

consistently argued, in at least nineteen 

separate Federal court complaints, that 

ethanol plants, including those with 

product lines of both fuel and beverage 

ethanol, are chemical manufacturing 

facilities under section 169(1) of the 

CAA, 42 U.S.C. 7479 (1). 

Specifically, this commenter 

indicated that the Federal government 

has argued in some of these complaints 

that ethanol production plants are 

facilities for synthetic organic chemical 

manufacturing and are affected facilities 

under part 60, subpart VV, 40 CFR 

60.480, and are subject to the leak 

detection and monitoring requirements 

on 40 CFR 60.482–1 through 60–489, 

which govern the synthetic organic 

chemical manufacturing industry. 

The commenter stated that the EPA 

formally charged that ethanol fuel 

facilities were chemical plants in 2002, 

when the EPA and the State of 

Minnesota filed complaints against all 

12 Minnesota ethanol plants. Those 

complaints stated that the plants were 

major emitting sources under section 

169 (1) of the CAA, 42 U.S.C. 7479 (1). 

Those cases were settled when these 

plants agreed to install thermal 

oxidizers and other additional pollution 

control equipment on their plants to 

bring their emissions per criteria 

pollutant to below 100 tpy. The 

companies were also fined from $18– 

42,000 a piece. A companion complaint 

was also filed, and settled, against Ace 

Ethanol in Wisconsin. 

The commenter expressed that the 

DOJ stated in a December, 2005 press 

release that 83% of the ethanol industry 

is under consent decrees. The decrees 

were all imposed to enforce the PSD 

provisions of the CAA under the legal 

theory that the ethanol plants were 

synthetic organic chemical 

manufacturing plants. All of these 

consent decrees required the plants to 

keep their emissions of each criteria 

pollutant below 100 tpy. Some decrees 

also required compliance with the leak 

detection and monitoring requirements 

found at 40 CFR 60.482–1 through 60– 

489, which govern the synthetic organic 

chemical manufacturing industry. 

In sum, the commenter stated that 

DOJ and EPA have consistently stated in 

court documents on nineteen separate 

occasions over the last 4 and one-half 

years that ethanol plants are chemical 

manufacturing plants. The commenter 

further stated that the DOJ and EPA 

have committed countless thousands of 

hours of staff and attorney time, 

laboring to advance this position. The 

commenter argued that the proposed 

preferred Option 1 could produce a 

situation where some or all of these 

companies, especially those who have 

been charged within the last several 

months (Cargill, MGP, Golden Triangle, 

AGP, and others) could claim that the 

consent decree terms, such as the 100 

tpy limit per pollutant, no longer 

applies to their plants. Any plant who 

has not had their consent decree 

discharged could immediately apply to 

have the decree dissolved since the 

decrees’ emissions limits no longer 

apply to ethanol plants. Additionally, 

the commenter asserts that these 

companies could ask the EPA to pay 

them back the millions in fines that they 

paid. The commenter is concerned that 

under Option 1, companies would be 

entitled to remove their thermal 


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24070 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

10 Ethanol Biorefinery Locations; U.S. Fuel 

Ethanol Industry Biorefineries and Production 

Capacity; updated March 13, 2007. 

11 ICM, Inc., Air Dispersion Modeling Study. 100 

TPY vs. 250 TPY. April 28, 2006. Attachment 3. 

(EPA–HQ–OAR–2006–0089–0086, Attachment 3). 

oxidizers when their current permits 

expire. 

One commenter representing State 

and local governments opposed the 

EPA’s preferred option (Option 1). They 

argued that if new facilities are allowed 

to construct without controls options, 

then EPA may face future lawsuits from 

existing facilities, insisting on a level 

playing field, for removal or relaxation 

of their control strategies. The 

commenter expressed that the EPA 

should uphold their previous decisions 

to enforce installation of pollution 

control technologies at all ethanol 

facilities. 

Response: This rule should have no 

effect on the existing consent decrees 

and the obligations of the sources to 

implement the consent decrees. The 

consent decrees are binding legal 

documents. The provisions of the 

consent decrees, by their terms, do not 

allow a source to alter its consent decree 

obligations as specified therein. Any 

civil penalties that had been due and 

owing to the United States have been 

paid into the United States Treasury. 

Even if the United States were so 

inclined, refunds of civil penalties from 

the United States Treasury would be 

unprecedented. 

The conditions for termination of the 

consent decrees are specified expressly 

in each consent decree. Such consent 

decrees can only be terminated after the 

source completes its consent decree 

obligation and demonstrates compliance 

with the consent decree terms to the 

satisfaction of the United States. One of 

those terms is that a source obtains a 

Federally-enforceable operating permit 

incorporating the terms of the consent 

decree. 

Our rationale for this final rule is 

explained in detail elsewhere in the 

preamble to the final rule. That we took 

actions to enforce the requirements in 

place before this rule does not 

undermine the basis for this rule. 

Existing facilities located in attainment 

areas would be required to maintain 

their existing permit limits and other 

permit requirements unless and until 

revised through a permitting procedure 

which, to be consistent with CAA 

section 110(a)(2)(C) and 40 CFR 51.160, 

must be shown not to cause or 

contribute to a violation of the NAAQS. 

We believe that raising the threshold 

from 100 tpy to 250 tpy in attainment 

areas will likely encourage facility 

expansions and construction of larger, 

more economically efficient plants, 

which in turn, will emit less emissions 

per gallon of ethanol produced. The 100 

tpy threhold on the other hand 

encourages the construction of more 

numerous, less economically efficient 

smaller facilities. In addition, as noted 

below, the environmental and health 

impacts of this rule are limited. 

E. Are there any environmental and 

health concerns associated with this 

final rule? 

Several comments were received 

concerning the potential negative 

impacts to the environment based on 

our proposed change. Some of the 

significant comments and concerns are 

provided in the following paragraphs. 

Comment: Several commenters 

expressed that increasing the PSD 

threshold for ethanol production 

facilities from 100 tpy to 250 tpy could 

lead to emissions increases that would 

not occur in absence of this rulemaking. 

Response: 

1. Introduction 

We acknowledge that there may be 

some emissions increases as a result of 

this rulemaking. Over the past 25 years, 

domestic ethanol fuel production has 

steadily increased due to changing 

environmental regulation, Federal and 

State tax incentives, and market 

demand, including an increasing 

number of State ethanol mandates, the 

phase out of MBTE, and elevated crude 

oil prices. In order to meet current and 

future demand, new facilities may be 

constructed or existing facilities may 

need to be expanded. However, we do 

not expect many new facilities to be 

constructed (other than those already 

planned) in the short-term (e.g., over the 

next 5 years). As noted later, we predict 

that the revision of the major source 

threshold applicable to the ethanol fuel 

industry will allow for the construction 

of larger, more economically efficient 

plants which, in turn, will emit less 

emissions per gallon of ethanol 

produced. Comments submitted on the 

proposal concurred with that 

prediction. (See Docket Nos. EPA–HQ– 

OAR–2006–0089–0086, 0039, 0040, 

0045, 0046, 0050, 0057, 0058, 0062, 

0063, 0065, 0066, 0067, 0068, 0069, 

0072, 0073, 0075, 0076, 0077, 0078, 

0079, 0085, 0090, 0091, 0092, 0093, 

0094, 0098, 0100, 0101, 0102, 0103, 

0104, 0105, 0107, 0108, 0110, 0111, 

0112, 0113, 0114, 0115, 0116). 

There are an estimated 114 facilities 

that currently exist in the U.S. that 

produce ethanol by natural fermentation 

as of March, 2007. Of these, an 

estimated 7 of the facilities are planning 

expansions. Eighty additional ethanol 

production facilities are currently under 

construction. Existing ethanol 

production capacity is estimated at 

5,600 million gallons year (mgy). New 

construction and expansions will add 

an estimated 6,400 mgy to existing 

capacity. The estimated total capacity 

(inclusive of expansions and new 

constructions) will be about 12,000 mgy 

(12 billion gallons year (bgy)) once 

expansions and new constructions are 

completed.10

Commenters expressed concern that 

this rule would result in emissions 

increases because (1) The rule increases 

the PSD major source threshold from 

100 tpy to 250 tpy for the subject 

ethanol production facilities (new or 

existing facilities) in attainment areas; 

and (2) that, for new sources, fugitive 

emissions will no longer be included in 

calculations to determine whether a 

source is a major PSD source in 

attainment areas or to determine 

nonattainment NSR applicability. 

Section 2 of this response section 

discusses our consideration of the 

potential for emissions increases due to 

the increased threshold, section 3 

discusses our consideration of the 

potential for emissions increases due to 

facilities no longer needing to count 

fugitives when determining whether 

they are a major source, and section 4 

presents our overall conclusions. 

2. Increase in Major Source Threshold 

Emissions data. One industry 

commenter provided estimates 

indicating that a controlled 110 mgy 

ethanol production facility could be 

assumed to emit 100 tpy and that a 

controlled 250 mgy ethanol production 

facility could be assumed to emit 250 

tpy.11 The commenter reported that 

emissions from both of these facilities 

are based on conservative potential to 

emit estimates, presenting worst-case 

operating scenario emissions and that 

actual plants generally emit less than 

their potential to emit estimates. As 

noted later, we believe future economies 

of scale will potentially drive the 

expansion and construction of facilities 

with capacities equal to or greater than 

250 mgy with actual emissions being 

less than 250 tpy. Thus, under this 

scenario, production of ethanol would 

result in less emissions per gallon 

produced than today. 

Volatile organic compounds (VOC) 

emissions occur from the cooling system 

baghouses, dryers, CO2 fermentation 

scrubbers, equipment leaks, transfer, 

and storage vessels. 

Estimates provided include estimates 

for emissions of nitrogen oxides that 

result from fuel combustion in the 

thermal oxidizers and dryers. The 


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12 ICM, Inc., Air Dispersion Modeling Study. 100 

TPY vs. 250 TPY. April 28, 2006. Attachment 3. 

(EPA–HQ–OAR–2006–0089–0086, Attachment 3). 

13 Memorandum to Docket EPA–HQ–OAR–2006– 

0089. Spreadsheet Presenting Ethanol Production 

Facility Locations and Ozone Nonattainment 

Designations. April 2007. 

potential to emit estimates assume that 

100% of the NOX emissions are emitted 

in the form of NO2 to depict a worstcase scenario. 

Carbon monoxide (CO) emissions are 

also attributed to fuel combustion at the 

thermal oxidizers and dryers. As such, 

CO emissions were also included in 

their potential to emit estimates. 

Emissions of particulate matter less 

than 10 microns (PM10) result from grain 

unloading and loading, grain handling 

and milling, natural gas combustion and 

process operations such as dryers and 

cooling towers, as well as from truck 

traffic and haul roads. As noted, 

particulate emissions are generated by 

grain receiving, milling and distillers 

dried grains and solubles (DDGS) 

loading. Most of these emissions are 

controlled by baghouses. 

Haul road emissions are generally 

dependent on the amount of vehicle 

miles traveled on the roads (more miles 

traveled equate to higher emissions). 

Grain fugitives are assumed to be 

controlled by a choked flow system, 

which reportedly is the typical control 

for fugitive particulate emissions. 

Carbon monoxide and VOC emissions 

are typically the largest source of 

emissions from these facilities and are 

the likely pollutants that would trigger 

major PSD/NSR review.12 Based on this, 

we have focused our analysis on 

increases in CO and/or VOC emissions 

that could potentially occur as a result 

of increased production and this 

rulemaking. We acknowledge that 

emissions increases in NOX and PM10

could also occur concurrent with CO 

and/or VOC emissions increases, but 

these pollutants are not as relevant to 

the major source determinations for 

ethanol plants. Additionally, we note 

that since ozone generation is 

dependent on the mixing of VOCs and 

oxidized nitrogen in the presence of 

sunlight, control of VOCs in NOXlimited environments may not be the 

best solution for reducing ground-level 

ozone emissions in those environments. 

Addressing other pollutants may result 

in greater environmental benefits. 

Attainment areas. There are an 

estimated 171 denatured ethanol 

production facilities located or are 

planned to be located in attainment 

areas. If we assume that a 110 mgy 

ethanol production facility can be 

controlled under a 100 tpy threshold 

(for VOC and CO) including fugitives, it 

then can be assumed that facilities that 

have capacities less than or equal to 110 

mgy are either controlled as synthetic 

minors or are uncontrolled facilities that 

have emissions that fall below the 100 

tpy emissions threshold (for VOC and 

CO). Additionally, given that a 250 mgy 

ethanol production facility can be 

controlled under a 250 tpy threshold 

(for VOC and CO), including fugitives, 

it then can be assumed that facilities 

that have capacities greater than 250 

mgy are currently regulated as major 

sources. 

Several commenters have provided 

that there are many ethanol production 

facilities that take on BACT controls in 

order to be permitted as ‘‘synthetic 

minor’’ sources or are subject to controls 

or PTE restrictions that may be similar 

to BACT controls because of other 

existing regulations (e.g., NSPSs, 

NESHAP, State regulations). (See Docket 

Nos. EPA–HQ–OAR–2006–0089–0086, 

0057, 0074). We do not have sufficient 

information to discern the number of 

facilities that are synthetic minor. 

However, those facilities which must 

comply with NSPS, NESHAP or State 

regulations will continue to be subject 

to those regulations as those 

requirements are unaffected by this rule 

change. In addition, we do know that 

there are approximately 6 facilities 

located in attainment areas that have 

low production capacities (less than 6 

mgy). The emissions from these 

facilities would likely fall below both a 

100 tpy and 250 tpy threshold and 

ethanol production is likely a secondary 

process at the facility (e.g., ESE Alcohol, 

Inc. in Leoti, KS has an ethanol 

production capacity of 1.5 mgy from 

seed corn; Land O’ Lakes of Melrose, 

MN has an ethanol production capacity 

of 2.6 mgy from cheese whey). For the 

purposes of this analysis, we assume 

that these small production capacity 

facilities will not be affected by this 

rulemaking. 

Based on this rulemaking, existing 

facilities located in attainment areas 

would be required to maintain their 

existing permit limits and other permit 

requirements unless and until revised 

through a permitting procedure which, 

to be consistent with CAA section 

110(a)(2)(C) and 40 CFR 51.160, must be 

shown not to cause or contribute to a 

violation of the NAAQS. In addition, 

any expansion would also have to 

comply with any applicable NSPS, 

NESHAP, or State regulation. 

Most of the existing ethanol 

production facilities in attainment areas 

have current production capacities less 

than 110 mgy and would, therefore, 

likely be either synthetic minor or 

actual minor source facilities, with a 

few facilities likely being permitted as 

major PSD sources. Given a worst-case 

scenario, the maximum these facilities 

could emit as a result of a change or 

modification and solely by the threshold 

being increased to 250 tpy is 249 tpy (up 

to the major source threshold). 

New facilities located in attainment 

areas would be subject to a 250 tpy 

major source applicability threshold 

when determining major source 

applicability. Therefore, these new 

facilities would be allowed to emit up 

to 249 tpy (and produce up to 250 mgy) 

VOC and/or CO as minor sources as a 

result of the major source threshold 

being increased from 100 tpy to 250 tpy. 

Although other factors may influence 

the construction of new ethanol 

production facilities in the future, we do 

not expect many additional facilities to 

be constructed over the next 5 years as 

a result of this rule. 

Over the past 25 years, domestic 

ethanol fuel production has steadily 

increased due to changing 

environmental regulation, Federal and 

State tax incentives, and market 

demand, including an increasing 

number of State ethanol mandates, the 

phase out of MBTE, and elevated crude 

oil prices. We assume, and commenters 

have supported that, under a 250 tpy 

threshold, there is incentive to construct 

more efficient facilities with larger 

capacities. (EPA–HQ–OAR–2006–0089– 

0086). Therefore, in the future, 

economies of scale will potentially drive 

the expansion and construction of 

facilities with capacities equal to or 

greater than 250 mgy with actual 

emissions being less than 250 tpy. Thus, 

under this scenario, production of 

ethanol would result in less emissions 

per gallon of ethanol produced today. 

Nonattainment areas. There are an 

estimated 23 ethanol production 

facilities located in or planned to be 

located in ozone nonattainment areas 

(12% of all facilities).13 In 

nonattainment areas, existing ethanol 

production facilities will continue to be 

subject to the 100 tpy threshold, 

therefore, there will not be emissions 

increases as a direct result of this 

rulemaking associated with increasing 

the major source threshold in 

attainment areas for these existing 

sources. 

3. Impact of Not Counting Fugitives in 

Emissions Applicability Calculations 

Emissions data. For fugitive 

emissions, we used the potential to emit 

emissions estimates provided by a 

commenter when considering the 

potential VOC and CO fugitive 


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14 ICM., Air Dispersion Model Study. 100 TPY vs. 

250 TPY. April 28, 2006, Attachment 3. (EPA–HQ– 

OAR–2006–0089–0086). 

15 ICM, Inc., Air Dispersion Modeling Study. 100 

TPY vs. 250 TPY. April 28, 2006. Attachment 3. 

(EPA–HQ–OAR–2006–0089–0086, Attachment 3). 

16 Ability to change treatment of fugitives in 

individual PSD permits may be limited by the terms 

of such permits. 

17 Memorandum to Docket EPA–HQ–2006–0089. 

Spreadsheet Presenting Ethanol Production Facility 

Locations and Ozone Nonattainment Designations. 

April 2007. 

18 Where a stationary source is adding a 

emissions unit or modifying an existing emissions 

unit, the State’s SIP-approved minor NSR program 

that permits physical modifications of existing 

minor sources would govern. 

emissions from the 110 mgy and 250 

mgy model plants.14 Based on these 

estimates, an estimated 16% of plant 

VOC and/or CO emissions from the 110 

mgy production plant are fugitives, and 

13% of plant VOC and CO emissions 

from the 250 mgy production plant are 

fugitives.15

Attainment areas. Existing facilities 

subject to a PSD permit will need to 

continue to include their fugitive 

emissions, as permitted, in attainment 

areas. This is because existing permit 

limits and other permit requirements 

remain in effect and enforceable unless 

and until revised through a permitting 

procedure which, at a minimum,16 to be 

consistent with CAA section 

110(a)(2)(C) and 40 CFR 51.160, must be 

shown not to cause or contribute to a 

violation of the NAAQS and to comply 

with all applicable requirements. When 

determining whether an emissions 

increase is significant, these sources 

would still be required to count their 

fugitives. 

New facilities located in attainment 

areas would be subject to a 250 tpy 

major source applicability threshold and 

would no longer need to count fugitives 

when determining major source 

applicability. Therefore, these new 

facilities would be allowed to emit up 

to an additional 33 tpy (and produce up 

to 250 mgy) VOC and/or CO (assuming 

VOC and/or CO fugitives account for 

13% of facility wide VOC and/or CO 

emissions) as minor sources as a result 

of this rulemaking. 

As we noted previously, we do not 

expect many new facilities to be 

constructed over the next 5 years. 

However, provided that there is 

construction of more facilities over the 

next 5 years, such a facility would be 

able to emit 33 tpy more VOC and/or CO 

emissions (assuming 13% of 250 tpy are 

fugitive emissions no longer required to 

be included in the major source 

applicability calculations) than it would 

have prior to this rulemaking. 

Nonattainment areas. As noted in the 

introduction, there are concerns that 

emissions may increase in 

nonattainment areas because fugitive 

emissions will no longer be required to 

be included in calculations to determine 

nonattainment NSR applicability. As 

noted previously, in nonattainment 

areas, both existing and new ethanol 

production facilities will continue to be 

subject to the 100 tpy threshold. 

Conservatively, approximately 23 of the 

194 facilities (approximately 12 percent) 

are located in ozone nonattainment 

areas.17

Of the estimated facilities located in 

ozone nonattainment areas, 4 of the 

facilities have reported capacities below 

6 mgy. These types of facilities produce 

ethanol from waste beverages, waste 

beer, and/or cheese whey and more than 

likely produce ethanol secondary to 

other processes at the facility (e.g., the 

Golden Cheese Company of California 

has a reported ethanol production 

capacity of 5 mgy). As with the small 

production capacity facilities mentioned 

previously that are located in attainment 

areas, we do not believe that these 

facilities will be affected by this 

rulemaking. 

Existing facilities subject to a 

nonattainment NSR permit will need to 

continue to include their fugitive 

emissions, as permitted, in 

nonattainment areas. This is because 

existing permit limits and other permit 

requirements remain in effect and 

enforceable unless and until revised 

through a permitting procedure which, 

to be consistent with CAA section 

110(a)(2)(C) and 40 CFR 51.160, must be 

shown not to cause or contribute to a 

violation of the NAAQS and to comply 

with all applicable requirements. When 

determining whether an emissions 

increase is significant, these sources 

would still be required to count their 

fugitives.18

We believe that very few ethanol 

production facility constructions in 

nonattainment areas will occur in the 

near future and that future facilities (as 

with existing facilities) will likely be 

located near an applicable feedstock 

(such as corn). Currently, and in the 

near foreseeable future, corn is the 

primary feedstock used in ethanol 

production in this country and the bulk 

of the corn grown in this country is 

located in attainment areas, and 

transportation costs may influence 

decision makers to locate such plants 

close to the feedstock. In the future, 

where cellulosic materials will be used 

as a feedstock for ethanol production on 

a commercial scale, agricultural and 

other waste may be used. We believe 

that this rulemaking, which increases 

the PSD major source threshold to 250 

tpy, will provide decision makers with 

additional incentives to locate these 

facilities in attainment areas. 

However, if a new facility did locate 

in a nonattainment area to meet future 

demand for ethanol, it is assumed that 

it would be a 110 mgy facility that 

would have the potential to emit an 

additional 16 tpy of VOC and/or CO 

fugitive emissions. 

It is important to note that most, if not 

all, ethanol fuel plants employ an active 

leak detection and repair (LDAR) 

program to minimize VOC emissions 

from tanks, valves, pumps and piping. 

(Docket No. EPA–HQ–OAR–2006–0089– 

0074). Fugitive particulate emissions 

from vehicular traffic are often 

controlled by a combination of paving 

and cleaning plant roads and other dust 

suppression methods. (Docket No. EPA– 

HQ–OAR–2006–0089–0074). Based on 

the assumption that there will be few, 

if any, facilities that will expand or be 

constructed in nonattainment areas in 

the future, and in light of the fugitive 

control measures that are employed at 

these facilities, we do not believe that 

this rulemaking will result in significant 

emissions increases in nonattainment 

areas. 

4. Our Overall Conclusion 

As stated previously, we believe that 

a larger, more economically efficient 

plant that is able to produce more 

ethanol fuel could result in significantly 

more fuel production without a 

corresponding increase in energy use or 

pollutant emissions, thereby resulting in 

a net reduction of environmental 

impacts as compared to the greater 

number of smaller, less efficient ethanol 

fuel production facilities that would be 

needed to achieve the same level of 

production. Given the likelihood of 

larger capacity facilities being better 

able to reduce emissions per gallon of 

ethanol produced than a greater number 

of smaller facilities, it is more logical to 

increase the capacity at a larger facility 

than locating additional smaller 

capacity facilities in an area. Similarly, 

it is more logical to allow the 

construction of larger capacity facilities 

in an area than locating numerous 

smaller capacity facilities in an area. 

In conclusion, the effect of this rule is 

limited given that other emissions 

requirements continue to apply and will 

be unaffected by this rulemaking. As we 

have noted in our discussion, VOC and/ 

or CO emissions (and other increases in 

emissions for NOX and PM10) will likely 

occur. However, other Federal 

regulations that apply will continue to 

apply to ethanol production facilities 

including numerous NSPS (e.g., 40 CFR 


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part 60, subparts Db, Dc (boilers and 

steam generating units); DD (grain 

handling and storage facilities); VV 

(leaks from VOC equipment); K, Ka, and 

Kb (storage vessels), and NESHAP (e.g., 

40 CFR part 63, subparts FFFF 

(miscellaneous organics. New Source 

Performance Standards require the 

application of the best demonstrated 

system of emission reductions for 

affected facilities to control criteria 

pollutants and NESHAP require the 

application of maximum achievable 

control technology to control HAP. We 

also note that nothing in this rule 

precludes a permitting authority from 

choosing to retain the 100 tpy major 

source threshold, as necessary, to meet 

its air quality needs. In short, we 

weighed and considered the 

environmental consequences of this rule 

relative to the expected benefits of 

ethanol use. The increased use of 

renewable fuels such as ethanol and 

biodiesel are expected to reduce 

dependence on foreign sources of 

petroleum, increase domestic sources of 

energy, and help transition to 

alternatives to petroleum in the 

transportation sector. 

Comment: A couple of commenters 

stated that there will be an increased 

use of coal over natural gas to fuel the 

ethanol production process due to the 

higher cost of natural gas and the 

increased threshold. One commenter 

stated that many of the new ethanol fuel 

plants (which tend to be significantly 

larger than ethanol for human 

consumption plants) are considering 

using coal as a source of energy for the 

chemical processing instead of natural 

gas as the industry has traditionally 

used. The commenter expressed that the 

use of coal for production of ethanol 

fuel will result in much greater 

emissions of conventional pollutants 

such as NOX, SO2, and PM, as well as 

increases in toxic pollutants, such as 

mercury that are not expressly regulated 

by the PSD program. They also argued 

that the use of coal will result in 

increases in CO2 emissions from ethanol 

plants which will threaten to undermine 

any global warming benefits of using 

ethanol instead of petroleum-derived 

fuels. 

Response: We disagree with the 

assertion that existing ethanol 

production facilities that currently use 

natural gas as a fuel supply will likely 

convert to coal as a result of raising the 

major source threshold to 250 tpy. One 

commenter reported, and we agree, that 

the capital costs of such a conversion 

would be costly and facilities would 

more likely opt for increasing their 

production capacity. (Docket No. EPA– 

HQ–OAR–2006–0089–0086). The 

Renewable Fuels Association reports 

that, to their knowledge, no gas-fired 

mill has made a conversion to coal 

[EPA–HQ–OAR–2006–0089–0086]. It is 

acknowledged, however, that new 

plants may decide to use coal in lieu of 

natural gas because of the increased 

major source emissions threshold and 

because of it being a cheaper fuel source 

and that this could result in increases in 

emissions of pollutants not expressly 

regulated by the PSD program. 

However, even if there is an increased 

use of coal, these facilities will be 

subject to the same PSD major source 

limit requirements as facilities that use 

natural gas, and will continue to be 

subject to other regulations (State and 

Federal). We also acknowledge that the 

use of coal could result in increases in 

CO2 emissions from ethanol plants. 

Comment: Several commenters 

provided specific examples of situations 

where implementation of our proposed 

Option could cause or contribute to the 

negative impact on an area. 

One State commenter expressed that 

the proposed Option 1 would result in 

a negative impact on growth due to the 

projected increment consumption. They 

said that although some States could 

deal with this locally by making their 

regulations stricter than the Federal 

regulations, others are restricted because 

they have rules that limit them from 

having laws in their States that are 

stricter than the Federal rules. 

A commenter representing State and 

local governments provided that even 

current minor sources—under the 

existing 100 tpy threshold, including 

fugitive emissions—are known to 

contribute significantly to potential 

violations of the NAAQS. They stated 

that permit data from STAPPA and 

ALAPCO members show that emissions 

from some ethanol fuel production 

facilities contribute to an area exceeding 

the 24-hour PM10 standard and, in some 

cases, are close to violating the 24-hour 

PM10 increment. 

Another commenter stated that EPA 

and North Dakota have not resolved the 

issue of sulfur dioxide PSD exceedances 

in Class I areas of North Dakota and 

Montana, and that if Option 1 is 

promulgated for ethanol plants, there is 

potential for an increase of more than 

double the allowable sulfur dioxide 

emissions from proposed and existing 

ethanol plants. 

Response: Generally, although we 

acknowledge that there may be negative 

impacts to particular regions or areas 

due to this rulemaking, we do not think 

there would be many instances where 

this is the case. Provided that there are 

local and regional instances with the 

potential for unacceptable negative 

impacts from this rule, a State or local 

government regulations/minor NSR 

program can be implemented to mitigate 

such impacts. In fact, a State is not 

required to adopt the rule’s change in 

threshold and can maintain the 100 tpy 

threshold or other lower threshold in 

order to best serve its air quality/ 

economic needs. If a State’s regulations 

provide that its major source PSD 

thresholds cannot be more stringent 

than those prescribed by the Federal 

programs, its State minor NSR program 

should be able to address specific local 

concerns such as some of those 

suggested by the commenters. 

We also acknowledge that there are 

local and Regional concerns that this 

rule is contrary to the purposes of the 

PSD program. It is true that one purpose 

of the PSD program is to ensure that 

new sources do not cause or contribute 

to an area that is in attainment 

becoming a nonattainment area. 

However, we believe that, in part, this 

directive will continue to be addressed 

by a State’s minor NSR permit program 

and various Federal, State and Local air 

quality requirements. Federal 

regulations that apply and will continue 

to apply to ethanol production facilities 

include numerous NSPS (e.g., 40 CFR 

part 60, subparts Db, Dc (boilers and 

steam generating units); DD (grain 

handling and storage facilities); VV 

(leaks from VOC equipment); K, Ka, and 

Kb (storage vessels), and NESHAP (e.g., 

40 CFR part 63, subparts FFFF 

(miscellaneous organics. New Source 

Performance Standards require the 

application of the best demonstrated 

system of emission reductions for 

affected facilities to control criteria 

pollutants and NESHAP require the 

application of maximum achievable 

control technology to control HAP. 

F. Will there be a Federal ethanolspecific VOC emissions test protocol? 

Comments: A couple of States argued 

that there is a need for a Federallyapproved VOC performance test 

specifically for ethanol production. 

Reasons given include that (1) VOC 

testing at ethanol plants would be 

straightforward, (2) facilities would be 

assured of equitable treatment between 

them, (3) States would be able to moreeasily and consistently determine 

compliance with Federal PSD rules, and 

(4) administering the Clean Air 

permitting programs for ethanol plants 

would be easier if there were a 

Federally-approved method to measure 

volatile organic compound emissions 

from ethanol plants. 

Response: The EPA believes that the 

existing Reference Methods found at 40 

CFR part 60 are applicable for 


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19 Where a stationary source is adding a 

emissions unit or modifying an existing emissions 

unit, the State’s SIP-approved minor NSR program 

that permits physical modifications of existing 

minor sources would govern. 

estimating the total mass emissions of 

VOCs, as defined in 40 CFR 51.100(s), 

from each process commonly used at 

wet and dry corn mills that produce 

ethanol. Over the past 5 years, VOC 

emissions from ethanol facilities under 

consent decrees with the United States 

have been successfully tested using a 

combination of EPA Reference Method 

25 or 25A, and Reference Method 18. 

In addition to the currently available 

Reference Methods, EPA works with 

industry groups to develop their own 

test methods as an alternative to using 

existing EPA Reference Methods, 

provided that the alternative methods 

produce accurate results. One example 

of an alternative method by an industry 

is the method developed by the Corn 

Refiners Association for measuring VOC 

emissions from the wet corn milling 

industry. This method was developed 

by the wet corn milling industry 

specifically to measure VOC mass 

emissions from processes within their 

facilities. It is a systematic approach for 

developing a specific list of target 

organic compounds and determining the 

appropriate sampling procedure to 

collect those target compounds during 

subsequent VOC emissions testing. This 

method is currently available on EPA’s 

Emission Measurement Center Web 

page (http://www.epa.gov/ttn/emc/ 

prelim/otm11.pdf). The EPA plans to 

begin a rulemaking in the near term 

regarding the above-noted new method. 

If promulgated, this method will be 

codified in 40 CFR part 51, appendix M, 

as a Federally-approved method for 

measuring VOC emissions from wet 

corn milling plants. 

G. Are there backsliding issues related 

to this rulemaking? 

Comments: Several commenters 

expressed concern that the States would 

not be able to adopt the proposed 

changes without violating the 

antibacksliding provisions under 

sections 193 of the CAA. The 

commenter alleges that the PSD program 

and ‘‘synthetic minor’’ limits are control 

requirements. Another commenter 

stated that states will have to comply 

with the anti-backsliding provisions of 

section 116 before adopting these 

changes. Finally, the same commenter 

noted that EPA’s justification for the 

final rule appears inconsistent because 

we did not discuss the impacts of the 

proposed rule on state efforts to attain 

and maintain compliance with the 

NAAQS, as States will be required to do 

to adopt the changes under State law. 

Response: Section 193 applies to 

nonattainment areas only. It provides 

that ‘‘no control requirement in effect, 

or required to be adopted by an order, 

settlement agreement, or plan in effect 

before the date of the enactment of the 

CAA of 1990 may be changed unless the 

change insures equivalent or greater 

emission reductions of such air 

pollutant.’’ We have previously stated 

our position that section 193 is 

ambiguous as to whether it applies to 

the NSR program, and that although we 

have chosen a conservative approach in 

our review of NSR SIP changes, our past 

option to review changes for 

consistency with section 193 is not 

conclusive of its scope. See 70 FR 

39420, 69 FR 31056, 31063. 

Recently, the U.S. Court of Appeals 

for the D.C. Circuit ruled on our 

interpretation of a similar, but not 

identical term ‘‘controls’’ as used in 

section 172(e), and found that ‘‘NSR is 

a control.’’ South Coast Air Quality 

Mgmt. Dist. v. EPA, 472 F.3d 882, 901 

(D.C. Cir. 2006). We respectfully 

disagree with the court’s finding on this 

issue and have filed a petition for 

rehearing of the decision. We also 

believe that the Court’s interpretation of 

the term ‘‘controls’’ in section 172(e) is 

not necessarily decisive of how we 

should interpret the similar but different 

term ‘‘control requirement’’ in section 

193, although we recognize we will 

need to take into account the D.C. 

Circuit’s decision following the outcome 

of our rehearing request. 

Nonetheless, this action does not in 

and of itself modify any requirements 

applicable to nonattainment areas. We 

believe the appropriate time to 

determine the applicability of and 

compliance with section 193 is when a 

control requirement in a nonattainment 

area is changed. For States that 

undertake a SIP revision, we will 

address the applicability of section 193 

in our future actions to approve the SIP 

revisions. To the extent States can 

implement this approach consistent 

with their existing SIPs, the SIP 

requirements are not changing, and 

section 193 does not apply. 

Similarly, we disagree with 

commenters that state that existing 

sources would simply be able to lift 

existing permit limits upon 

promulgation of this rule. These existing 

permit limits and other permit 

requirements remain in effect and 

enforceable unless and until revised 

through a permitting procedure which, 

to be consistent with CAA section 

110(a)(2)(C) and 40 CFR 51.160, must be 

shown not to cause or contribute to a 

violation of the NAAQS and to comply 

with all applicable requirements.19

As explained previously, section 116 

of the CAA allows States to enforce their 

own emissions limitation and standards 

if such requirements are not less 

stringent than the approved SIP and 

Federal regulations under sections 111 

and 112 of the CAA. However, nothing 

in section 116 prevents a State from 

revising its SIP to make its requirements 

less stringent, provided the new 

requirements are not less stringent than 

Federal regulations under sections 111 

and 112 and meet all other applicable 

requirements. Nothing in this rule 

authorizes States to adopt changes that 

are less stringent than what is required 

under sections 111 and 112, and 

therefore section 116 does not limit a 

State’s ability to revise its SIP to adopt 

these changes. 

Finally, in response to comments, we 

have analyzed the impact of this rule 

and discussed our findings in section 

IV.E. of this preamble. 

VI. Effective Date of This Rule and 

Requirements for State or Tribal 

Implementation Plans and Title V 

These changes will take effect in the 

Federal PSD and part 71 permit 

programs on July 2, 2007. This means 

that we will apply these rules in any 

area without a SIP-approved PSD 

program or title V program, for which 

we are the permitting authority, or for 

which we have delegated our authority 

to issues permits to a State, local, or 

tribal permitting authority. 

We are establishing these 

requirements as minimum program 

elements of the PSD, nonattainment 

NSR, and title V programs. 

Notwithstanding this requirement, it 

may not be necessary for a State, local 

or tribal authority to revise its SIP or 

title V programs to begin to implement 

these changes. Some State, local or 

tribal authorities may be able to adopt 

these changes through a change in 

interpretation of the term ‘‘chemical 

process plant’’ without the need to 

revise the SIP or the title V program. 

For any State, local or tribal agency 

that can implement the changes without 

revising its approved NSR or title V 

program, the changes will become 

effective when the permitting authority 

publicly announces that it has accepted 

these changes by interpretation. 

Although we find that no SIP or title V 

program revisions may be necessary in 

certain areas that are able to adopt these 

changes by interpretation, we encourage 

such State, local and tribal authorities in 

such areas to make such SIP or title V 


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program changes in the future to 

enhance the clarity of the existing rules. 

For areas that revise their SIPs or title 

V programs to adopt these changes, the 

changes are not effective in such area 

until we approve the SIP revision or 

title V program as meeting all applicable 

requirements. Revisions to title V 

programs to reflect the changes in this 

rule should be submitted to EPA for 

approval within 3 years. State, local, or 

tribal authorities may adopt or maintain 

NSR program elements that have the 

effect of making their regulations more 

stringent than these rules. 

VII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866—Regulatory 

Planning and Review 

Under Executive Order (EO) 12866 

(58 FR 51735, October 4, 1993), the 

Agency must determine whether the 

regulatory action is ‘‘significant’’ and 

therefore subject to Office of 

Management and Budget (OMB) review 

and the requirements of the Executive 

Order. Pursuant to the terms of 

Executive Order 12866, it has been 

determined that this rule is a 

‘‘significant regulatory action’’ because 

it raises policy issues arising from the 

President’s priorities. Also, this rule is 

not ‘‘economically significant.’’ 

Accordingly, the EPA submitted this 

action to OMB for review under 

Executive Order 12866 and any changes 

made in response to OMB’s 

recommendations have been 

documented in the docket for this 

action. 

B. Paperwork Reduction Act 

This action does not impose any new 

information collection burden as the 

burden imposed by this rule has already 

been taken into account in previouslyapproved information collection 

requirement actions under both the NSR 

and title V programs. The OMB has 

previously approved the information 

collection requirements contained in the 

existing 40 CFR parts 51 and 52 

regulations under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq., and has assigned OMB 

control number 2060–0003, EPA ICR 

number 1230.17. The OMB has also 

previously approved the information 

collection requirements contained in the 

existing 40 CFR parts 70 and 71 

regulations under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq., and has assigned OMB 

control number 2060–0243 (EPA ICR 

number 1587.06) to the part 70 rule and 

OMB control number 2060–0336 (ICR 

Number 1713.05) to the part 71 rule 

respectively. A copy of the OMBapproved Information Collection 

Requests (ICR’s), EPA ICR numbers 

1230.17, 1587.06, and 1713.05, may be 

obtained from Susan Auby, Collection 

Strategies Division; U.S. Environmental 

Protection Agency (2822T); 1200 

Pennsylvania Avenue, NW., 

Washington, DC 20460 or by calling 

(202) 566–1672. 

It is necessary that certain records and 

reports be collected by a State or local 

agency (or the EPA Administrator in 

non-delegated areas), for example, to: (1) 

Confirm the compliance status of 

stationary sources, including identifying 

any stationary sources subject/not 

subject to the rule, and (2) ensuring that 

the stationary source control 

requirements are being achieved. The 

information is then used by the EPA or 

State enforcement personnel to ensure 

that the subject sources are applying the 

appropriate control technology and that 

the control requirements are being 

properly operated and maintained on a 

continuous basis. Based on the reported 

information, the State, local, or tribal 

agency can decide which plants, 

records, or processes should be 

inspected. Such information collection 

requirements for sources and States are 

currently reflected in the approved 

ICR’s referenced above for the NSR and 

title V programs. 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, disclose, or 

provide information to or for a Federal 

agency. This includes the time needed 

to review instructions; develop, acquire, 

install, and utilize technology and 

systems for the purposes of collecting, 

validating, and verifying information; 

processing and maintaining 

information; disclosing and providing 

information; adjusting the existing ways 

to comply with any previously 

applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. 

C. Regulatory Flexibility Analysis 

The Regulatory Flexibility Analysis 

(RFA) generally requires an agency to 

prepare a regulatory flexibility analysis 

of any rule subject to notice and 

comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the Agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of this action on small entities, a small 

entity is defined as: (1) A small business 

that is a small industrial entity as 

defined in the U.S. Small Business 

Administration (SBA) size standards 

(see 13 CFR 121.201); (2) a small 

governmental jurisdiction that is a 

government of a city, county, town, 

school district, or special district with a 

population of less than 50,000; or (3) a 

small organization that is any not-forprofit enterprise that is independently 

owned and operated and is not 

dominant in its field. There are an 

estimated 114 ethanol production 

facilities in the U.S. and an estimated 70 

more under construction with several 

more being planned. Most of these 

facilities use corn as the primary 

feedstock. It is estimated that farmerowned cooperatives make up nearly half 

of the ethanol plants in the U.S. with an 

additional percentage of facilities under 

construction that are locally-controlled. 

(http://ethanol.org/production.html). 

After considering the economic impacts 

of these final amendments on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

Note that the EPA does not know the 

number of ethanol plants that are (or 

will be) considered small entities; 

however, we believe this final rule will 

not have a significant economic impact 

on any ethanol plants because its overall 

impact will be to lessen the 

requirements that apply to such plants. 

Additionally, the expansion to 

additional feedstocks in the production 

of ethanol reduces the potential 

economic disparity among ethanol 

plants regardless of the carbohydrate 

feedstock used. Additionally, it is 

important to note that there are 

currently no commercial scale (other 

than commercial demonstration plants 

under construction for cellulosic 

biomass ethanol production) facilities 

using sugar beet, sugar cane, or 

cellulosic biomass feedstocks in the U.S. 

D. Unfunded Mandates Reform Act 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on State, local, 

and tribal governments and the private 

sector. Under section 202 of the UMRA, 


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the EPA generally must prepare a 

written statement, including a costbenefit analysis, for proposed and final 

rules with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and tribal governments, in the aggregate, 

or to the private sector, of $100 million 

or more in any 1 year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of the UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective or least burdensome alternative 

that achieves the objectives of the rule. 

The provisions of section 205 do not 

apply when they are inconsistent with 

applicable law. Moreover, section 205 

allows EPA to adopt an alternative other 

than the least costly, most cost-effective 

or least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation as to why that 

alternative was not adopted. Before EPA 

establishes any regulatory requirements 

that may significantly or uniquely affect 

small governments, including tribal 

governments, it must have developed 

under section 203 of the UMRA a small 

government agency plan. 

The plan must provide for notifying 

potentially affected small governments, 

enabling officials of affected small 

governments to have meaningful and 

timely input in the development of EPA 

regulatory proposals with significant 

Federal intergovernmental mandates, 

and informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. This rule 

contains no Federal mandates (under 

the regulatory provisions of Title II of 

the UMRA) for State, local, or tribal 

governments or the private sector. 

The EPA has determined that this rule 

does not contain a Federal mandate that 

may result in expenditures of $100 

million or more for State, local, and 

tribal governments, in the aggregate, or 

the private sector in any one year. Thus, 

this rule is not subject to the 

requirements of sections 202 and 205 of 

the UMRA. 

E. Executive Order 13132—Federalism 

Executive Order 13132, entitled 

‘‘Federalism’’ (64 FR 43255, August 10, 

1999), requires EPA to develop an 

accountable process to ensure 

‘‘meaningful and timely input by State 

and local officials in the development of 

regulatory policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ 

Under section 6(b) of Executive Order 

13132, EPA may not issue a regulation 

that has federalism implications, that 

imposes substantial direct compliance 

costs, and that is not required by statute, 

unless the Federal government provides 

the funds necessary to pay the direct 

compliance costs incurred by State and 

local governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

regulation. Under section 6(c) of 

Executive Order 13132, EPA may not 

issue a regulation that has federalism 

implications and that preempts State 

law, unless the Agency consults with 

State and local officials early in the 

process of developing the proposed 

regulation. 

EPA has concluded that this final rule 

will not have federalism implications. It 

will not impose substantial direct 

compliance costs on State or local 

governments, nor will it preempt State 

law. Thus, the requirements of sections 

6(b) and 6(c) of the Executive Order do 

not apply to this rule. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, the 

EPA specifically solicited comment on 

the proposed rule from State and local 

officials. 

F. Executive Order 13175—Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

‘‘Consultation and Coordination with 

Indian Tribal Governments’’ (65 FR 

13175, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This final rule does not 

have tribal implications, as specified in 

Executive Order 13175, as there are no 

tribal authorities currently issuing PSD, 

major nonattainment NSR, title V 

permits, or synthetic minor limits to 

ethanol plant which process 

carbohydrate feedstocks. Thus, 

Executive Order 13175 does not apply 

to this rule. 

Although Executive Order 13175 does 

not apply to this final rule, EPA 

specifically solicited comment on the 

proposed rule from tribal officials. 

G. Executive Order 13045—Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045, entitled 

‘‘Protection of Children from 

Environmental Health Risks and Safety 

Risks’’ (62 FR 19885, April 23, 1997), 

applies to any rule that: (1) Is 

determined to be ‘‘economically 

significant’’ as defined under Executive 

Order 12866; and (2) concerns an 

environmental health or safety risk that 

EPA has reason to believe may have a 

disproportionate effect on children. If 

the regulatory action meets both criteria, 

the Agency must evaluate the 

environmental health or safety effects of 

the planned rule on children, and 

explain why the planned regulation is 

preferable to other potentially effective 

and reasonably feasible alternatives 

considered by the Agency. 

EPA interprets Executive Order 13045 

as applying only to those regulatory 

actions that concern health or safety 

risks, such that the analysis required 

under section 5–501 of the Executive 

Order has the potential to influence the 

regulation. This final rule is not subject 

to Executive Order 13045 because it is 

not ‘‘economically significant’’ as 

defined in Executive Order 12866 and 

because the Agency does not have 

reason to believe the environmental 

health or safety risks addressed by this 

action present a disproportionate risk to 

children. 

H. Executive Order 13211—Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

These final amendments do not 

constitute a ‘‘significant energy action’’ 

as defined in Executive Order 13211, 

‘‘Actions Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use’’ (66 FR 28355, May 

22, 2001), because they will not likely 

have a significant adverse effect on the 

supply, distribution, or use of energy. 

I. National Technology Transfer and 

Advancement Act 

As noted in the proposed rule, section 

12(d) of the National Technology 

Transfer and Advancement Act of 1995 

(NTTAA), Public Law 104–113, 12(d) 

(15 U.S.C. 272 note), directs EPA to use 

voluntary consensus standards in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. 

Voluntary consensus standards are 

technical standards (for example, 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. The NTTAA directs EPA to 

provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 


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Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 24077 

These final rule amendments do not 

involve technical standards. Therefore, 

EPA did not consider the use of any 

voluntary consensus standards. 

J. Executive Order 12898—Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629 

(Feb. 16, 1994)) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, any disproportionately 

high and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

The EPA has determined that this 

final rule will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations. 

The reason for EPA’s determination is 

because the final rule does not affect the 

level of protection provided to human 

health or the environment as it does not 

change a permitting authority’s 

obligation to maintain the NAAQS, even 

though changes are being made to the 

PSD, major nonattainment NSR, and 

title V programs. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the United 

States prior to publication of the rule in 

the Federal Register. A major rule 

cannot take effect until 60 days after it 

is published in the Federal Register. 

These final rule amendments do not 

constitute a ‘‘major rule’’ as defined by 

5 U.S.C. 804(2). Therefore, this rule will 

be effective July 2, 2007. 

VIII. Judicial Review 

Under section 307(b)(1) of the Act, 

judicial review of this final action is 

available by filing of a petition for 

review in the U.S. Court of Appeals for 

the District of Columbia Circuit by July 

2, 2007. Any such judicial review is 

limited to only those objections that are 

raised with reasonable specificity in 

timely comments. Under section 

307(b)(2) of the Act, the requirements of 

this final action may not be challenged 

later in civil or criminal proceedings 

brought by us to enforce these 

requirements. 

List of Subjects 

40 CFR Parts 51 and 52 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Nitrogen dioxide, Ozone, 

Particulate matter, Reporting and 

recordkeeping requirements, Sulfur 

oxides. 

40 CFR Parts 70 and 71 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Intergovernmental 

relations, Reporting and recordkeeping 

requirements. 

Dated: April 12, 2007. 

Stephen L. Johnson, 

Administrator. 

■ For reasons stated in the preamble, 

title 40, chapter I of the Code of Federal 

Regulations is amended as follows: 

PART 51—[AMENDED] 

■ 1. The authority citation for part 51 

continues to read as follows: 

Authority: 23 U.S.C. 101; 42 U.S.C. 7401– 

7671q. 

Subpart I—[Amended] 

■ 2. Section 51.165 is amended by 

revising paragraphs (a)(1)(iv)(C)(20) and 

(a)(4)(xx) to read as follows: 

§ 51.165 Permit requirements. 

(a) * * * 

(1) * * * 

(iv) * * * 

(C) * * * 

(20) Chemical process plants—The 

term chemical processing plant shall not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140; 

* * * * * 

(4) * * * 

(xx) Chemical process plants—The 

term chemical processing plant shall not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140; 

* * * * * 

■ 3. Section 51.166 is amended by 

revising paragraphs (b)(1)(i)(a), 

(b)(1)(iii)(t), and (i)(1)(ii)(t) to read as 

follows: 

§ 51.166 Prevention of significant 

deterioration of air quality. 

* * * * * 

(b) * * * 

(1)(i) * * * 

(a) Any of the following stationary 

sources of air pollutants which emits, or 

has the potential to emit, 100 tons per 

year or more of any regulated NSR 

pollutant: Fossil fuel-fired steam electric 

plants of more than 250 million British 

thermal units per hour heat input, coal 

cleaning plants (with thermal dryers), 

kraft pulp mills, portland cement plants, 

primary zinc smelters, iron and steel 

mill plants, primary aluminum ore 

reduction plants (with thermal dryers), 

primary copper smelters, municipal 

incinerators capable of charging more 

than 250 tons of refuse per day, 

hydrofluoric, sulfuric, and nitric acid 

plants, petroleum refineries, lime 

plants, phosphate rock processing 

plants, coke oven batteries, sulfur 

recovery plants, carbon black plants 

(furnace process), primary lead smelters, 

fuel conversion plants, sintering plants, 

secondary metal production plants, 

chemical process plants (which does not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140), fossil-fuel boilers (or 

combinations thereof) totaling more 

than 250 million British thermal units 

per hour heat input, petroleum storage 

and transfer units with a total storage 

capacity exceeding 300,000 barrels, 

taconite ore processing plants, glass 

fiber processing plants, and charcoal 

production plants; 

* * * * * 

(iii) * * * 

(t) Chemical process plants—The term 

chemical processing plant shall not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140; 

* * * * * 

(i) * * * 

(1) * * * 

(ii) * * * 

(t) Chemical process plants—The term 

chemical processing plant shall not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140; 

* * * * * 

Appendix S to Part 51—[Amended] 

■ 4. Appendix S to Part 51 is amended 

by revising paragraphs II.A.4.(iii)(t), and 

II.F.(20) to read as follows: 

Appendix S to Part 51—Emission Offset 

Interpretative Ruling 

* * * * * 


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24078 Federal Register / Vol. 72, No. 83 / Tuesday, May 1, 2007 / Rules and Regulations 

II. * * * 

A. * * * 

4. * * * 

(iii) * * * 

(t) Chemical process plants—The term 

chemical processing plant shall not include 

ethanol production facilities that produce 

ethanol by natural fermentation included in 

NAICS codes 325193 or 312140; 

* * * * * 

F. * * * 

(20) Chemical process plants—The term 

chemical processing plant shall not include 

ethanol production facilities that produce 

ethanol by natural fermentation included in 

NAICS codes 325193 or 312140; 

* * * * * 

PART 52—[AMENDED] 

■ 5. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401, et seq. 

Subpart A—[Amended] 

■ 6. Section 52.21 is amended by 

revising paragraphs (b)(1)(i)(a), 

(b)(1)(iii)(t) and (i)(1)(vii)(t) to read as 

follows: 

§ 52.21 Prevention of significant 

deterioration of air quality. 

* * * * * 

(b) * * * 

(1)(i) * * * 

(a) Any of the following stationary 

sources of air pollutants which emits, or 

has the potential to emit, 100 tons per 

year or more of any regulated NSR 

pollutant: Fossil fuel-fired steam electric 

plants of more than 250 million British 

thermal units per hour heat input, coal 

cleaning plants (with thermal dryers), 

kraft pulp mills, portland cement plants, 

primary zinc smelters, iron and steel 

mill plants, primary aluminum ore 

reduction plants (with thermal dryers), 

primary copper smelters, municipal 

incinerators capable of charging more 

than 250 tons of refuse per day, 

hydrofluoric, sulfuric, and nitric acid 

plants, petroleum refineries, lime 

plants, phosphate rock processing 

plants, coke oven batteries, sulfur 

recovery plants, carbon black plants 

(furnace process), primary lead smelters, 

fuel conversion plants, sintering plants, 

secondary metal production plants, 

chemical process plants (which does not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140), fossil-fuel boilers (or 

combinations thereof) totaling more 

than 250 million British thermal units 

per hour heat input, petroleum storage 

and transfer units with a total storage 

capacity exceeding 300,000 barrels, 

taconite ore processing plants, glass 

fiber processing plants, and charcoal 

production plants; 

* * * * * 

(iii) * * * 

(t) Chemical process plants—The term 

chemical processing plant shall not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140; 

* * * * * 

(i) * * * 

(1) * * * 

(vii) * * * 

(t) Chemical process plants—The term 

chemical processing plant shall not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140; 

* * * * * 

PART 70—[AMENDED] 

■ 7. The authority citation for part 70 

continues to read as follows: 

Authority: 42 U.S.C 7401, et seq. 

■ 8. Section 70.2 is amended by revising 

paragraph (2)(xx) of the definition of 

‘‘Major source’’ to read as follows: 

§ 70.2 Definitions. 

* * * * * 

Major source * * * 

(2) * * * 

(xx) Chemical process plants—The 

term chemical processing plant shall not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140; 

* * * * * 

PART 71—[AMENDED] 

■ 9. The authority citation for part 71 

continues to read as follows: 

Authority: 42 U.S.C 7401, et seq. 

Subpart A—[Amended] 

■ 10. Section 71.2 is amended by 

revising paragraph (2)(xx) of the 

definition of ‘‘Major source’’ to read as 

follows: 

§ 71.2 Definitions. 

* * * * * 

Major source * * * 

(2) * * * 

(xx) Chemical process plants—The 

term chemical processing plant shall not 

include ethanol production facilities 

that produce ethanol by natural 

fermentation included in NAICS codes 

325193 or 312140; 

* * * * * 

[FR Doc. E7–7365 Filed 4–30–07; 8:45 am] 

BILLING CODE 6560–50–P 


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