Document ID: EPA-HQ-OAR-2006-0089-0128
Agency: epa
Document Type: Rule
Title: Prevention of Significant Deterioration, Nonattainment New Source Review, and Title V: Treatment of Certain Ethanol Production Facilities Under the ``Major Emitting Facility Definition
Posted Date: 2007-05-01T04:00Z

[Federal Register: May 1, 2007 (Volume 72, Number 83)]
[Rules and Regulations]               
[Page 24059-24078]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr01my07-11]                         

[[Page 24059]]

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Part IV

Environmental Protection Agency

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40 CFR Parts 51, 52, 70, and 71

Prevention of Significant Deterioration, Nonattainment New Source 
Review, and Title V: Treatment of Certain Ethanol Production Facilities 
Under the ``Major Emitting Facility'' Definition; Final Rule

[[Page 24060]]

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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.

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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

[[Page 24061]]

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

[[Page 24062]]

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 re-examined 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

[[Page 24063]]

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.
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    \1\ Chemical reaction. (2007). In Encyclopedia Britannica. 
Retrieved April 5, 2007, from Encyclopedia Britannica. Online: http/
/http://www.britannica.com/eb/article9110109; Chemical industry. (2007). In 

Encyclopedia Britannica. Retrieved April 5, 2007, from Encyclopedia 
Britannica. Online: http//http://www.britannica.com/eb/article9108378.

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    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\
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    \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.
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    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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    \3\ See e.g. Memo. Edwin B. Erickson, Regional Administrator, to 
George Clemon Freeman, Counsel for Reserve Coal Proportion Company, 
July 06, 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.

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[[Page 24064]]

    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\
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    \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.
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    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\
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    \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.
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    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 24065]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 24066]]

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 ethanol-
manufacturing 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 petroleum-based 
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

[[Page 24067]]

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.
---------------------------------------------------------------------------

    \9\ BBI International. INNOVATIONS in Dry-Mill Ethanol 
Production.
---------------------------------------------------------------------------

    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.
     One commenter requested clarification of rule 
applicability, with regards to ethanol production, of numerous NSPS and 
MACT standards.
     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.
     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)).
     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).
     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.
     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.
     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-by-standard, 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.

[[Page 24068]]

    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 
corn-based 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

[[Page 24069]]

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-by-industry 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

[[Page 24070]]

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\
---------------------------------------------------------------------------

    \10\ Ethanol Biorefinery Locations; U.S. Fuel Ethanol Industry 
Biorefineries and Production Capacity; updated March 13, 2007.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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

[[Page 24071]]

potential to emit estimates assume that 100% of the NOX 
emissions are emitted in the form of NO2 to depict a worst-
case 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 
NOX-limited 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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \13\ Memorandum to Docket EPA-HQ-OAR-2006-0089. Spreadsheet 
Presenting Ethanol Production Facility Locations and Ozone 
Nonattainment Designations. April 2007.
---------------------------------------------------------------------------

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

[[Page 24072]]

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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \16\ Ability to change treatment of fugitives in individual PSD 
permits may be limited by the terms of such permits.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \17\ Memorandum to Docket EPA-HQ-2006-0089. Spreadsheet 
Presenting Ethanol Production Facility Locations and Ozone 
Nonattainment Designations. April 2007.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 24073]]

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 ethanol-specific VOC emissions test 
protocol?

    Comments: A couple of States argued that there is a need for a 
Federally-approved 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 more-
easily 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

[[Page 24074]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 24075]]

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 previously-approved 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 OMB-approved 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-for-profit 
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 farmer-owned 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,

[[Page 24076]]

the EPA generally must prepare a written statement, including a cost-
benefit 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 cost-effective 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.

[[Page 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.

0
For reasons stated in the preamble, title 40, chapter I of the Code of 
Federal Regulations is amended as follows:

PART 51--[AMENDED]

0
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]

0
2. Section 51.165 is amended by revising paragraphs (a)(1)(iv)(C)(20) 
and (a)(4)(xx) to read as follows:

Sec.  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;
* * * * *

0
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:

Sec.  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]

0
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

* * * * *

[[Page 24078]]

    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]

0
5. The authority citation for part 52 continues to read as follows:

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

Subpart A--[Amended]

0
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:

Sec.  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]

0
7. The authority citation for part 70 continues to read as follows:

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

0
8. Section 70.2 is amended by revising paragraph (2)(xx) of the 
definition of ``Major source'' to read as follows:

Sec.  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]

0
9. The authority citation for part 71 continues to read as follows:

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

Subpart A--[Amended]

0
10. Section 71.2 is amended by revising paragraph (2)(xx) of the 
definition of ``Major source'' to read as follows:

Sec.  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