[Federal Register: May 1, 2007 (Volume 72, Number 83)]
[Rules and Regulations]
[Page 24059-24078]
[DOCID:fr01my07-11]

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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

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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<PHONE_NUMBER>. 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<PHONE_NUMBER>. 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:<PHONE_NUMBER>; fax number: (919)
541-5509, e-mail address<EMAIL_ADDRESS>
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

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

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

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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    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.
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    \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.
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    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

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

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

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.

    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

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

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

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

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

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

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

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<PHONE_NUMBER>.
    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,

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