ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 51, 52, 70, and 71

[EPA-OAR-HQ-2006-0089; FRL- xxxx-x]

RIN-2060-AN77

Prevention of Significant Deterioration, Nonattainment New Source
Review, and Title V:  Treatment of Certain Ethanol Production Facilities
Under the “Major Emitting Facility” Definition

AGENCY:  Environmental Protection Agency (EPA).

ACTION:  Final Rule.

SUMMARY:  This final rule finalizes proposed changes made to the
definition of “major emitting facility” under 40 CFR parts 51, 52,
70, and 71 (see 71 FR 12240, March 9, 2006).  Two of the regulatory
changes proposed addressed the major source threshold for PSD sources
(40 CFR 51.166(b)(1)(i)(a) and 52.21(b)(1)(i)(a)).  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 prevention of significant
deterioration, nonattainment new source review 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 code 325193 or 312140 from the definition
of “chemical process plants.”

DATES:  This final rule is effective on [INSERT DATE 30 DAYS AFTER
PUBLICATION IN THE FEDERAL REGISTER].

ADDRESSES:  Docket.  The EPA has established a docket for this final
rule under Docket ID No. EPA-HQ-OAR-2006-0089.  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   HYPERLINK
"http://www.regulations.gov"  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 place on the Internet and will be
publicly available only in hard copy form.  Publicly available docket
materials are available either electronically through   HYPERLINK
"http://www.regulations.gov"  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 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.  Hours of operation are 8:30 a.m. to 4:30 p.m.,
Monday through Friday, excluding legal holidays.  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.  The telephone number for the Public
Reading Room is<PHONE_NUMBER>, and the telephone number for the Air and
Radiation Docket and Information Center is<PHONE_NUMBER>.

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:    HYPERLINK<EMAIL_ADDRESS><EMAIL_ADDRESS>.

SUPPLEMENTARY INFORMATION:

	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.	What implementation issues are related to this final rule?

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 and are classified under NAICS
codes 325193 and 31240; and State/local/Tribal governments.  Categories
and entities potentially affected by this action are expected to
include:

Industry Group	SICa	NAICSb

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 New Source Review (NSR) website,
under Regulations & Standards, at   HYPERLINK "http://www.epa.gov/nsr"
http://www.epa.gov/nsr .

II.	Background

Today’s regulatory changes affect the applicability provisions of two
separate permitting programs:  the major New Source Review (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
prevention of significant deterioration (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 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 a 100 tons per year (tpy) threshold applies.  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 also 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.

Today’s 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 effect
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” and within the definition of “major emitting facility”
(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 include 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

	Today, we finalize 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.  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 definition of terms
under 40 CFR 52.24, and paragraph (h) no longer lists source categories.

While 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, we changed the language from our proposal.  In
1981, when we originally defined 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
classification system.  Under the NAICS classification system, as
compared to the SIC classification system, there are over 350 more
industries classified.  Federal Government agencies have adopted the
NAICS classification system to collect statistics from industry
establishments more relevant to today’s economy.  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 and will never be updated or changed.

The NAICS 325193 (Ethyl Alcohol Manufacturing) includes denatured
alcohol, nonpotable ethanol, and nonpotable grain alcohol.  The NAICS
31214 (Distilleries) includes potable ethyl alcohol and grain alcohol
beverages.  Even though ethyl alcohol manufacturing (fuel ethanol and
industrial ethanol) has been classified under NAICS’ Chemical
Manufacturing subsector, unlike under the SIC classification of 2869
(Industrial Organic Chemicals, Not Elsewhere Classified), it is narrowly
defined for ethyl alcohol production.

The Agency has discussed 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 inappropriate to ignore the existence of the NAICS
as a potential tool to address the commenters’ concerns.  Accordingly,
in response to commenters, our final rule references the NAICS code
325193 and 31214 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 nations
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 a
permitting agency actually distinguished the two types of ethanol
production 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 are not changing the fundamental
premise 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 (P.L. 109-58) established a renewable fuel standard (RFS) that
requires an increasing use of renewable fuels in our nation.  Moreover,
we believe that promoting the production of ethanol, especially from a
variety of cellulosic feedstocks, will lead to many environmental
benefits including the potential for reducing toxic emissions, ozone
levels, and green-house gas emissions.  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 fuel to ethanol plants 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 environmental harm.  Nonetheless, even if our
consideration of potential environmental consenquences understates the
disbenefits , we believe that the potential for other environmental
benefits and the desire to support our nation’s energy policy
objectives outweigh any environmental disbenefit 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.   We
received numerous comments supporting our finding.  Although some
commenters pointed to differences in the production process, we are not
persuaded that the differences are so great that it warrants 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.

Commenters assert that we are not entitled to deference because the
statutory definition is subject to a “plain meaning interpretation”
of the CAA.  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.”  One definition offered by the
commenter is so broad it would encompass nearly every manufacturing
activity regardless of source category.  In interpreting the statute, we
must generally try to give meaning to all the terms in the statute such
that none are rendered meaningless.  If we applied the definition
offered by one commenter, it would render other categories on the source
category meaningless.  For example, it would have been unnecessary for
Congress to separately list petrochemical plants, because the broad
meaning of chemical process plant would capture every petrochemical
plant.  The specific chemical process relevant here, fermentation, is
also common to many industries.  For example, fermentation is used by
non-ethanol producing food manufactures who Congress chose not to
subject to the 100 tpy.  Accordingly, we find no “plain meaning”
definition of “chemical process plant” that can be applied in light
of these facts.  Moreover, based on the category list as defined by
Congress, we do not believe that whether or not an industry engages in a
“chemical process” and specifically whether it engages in
“fermentation” can be used as a decisive factor in determining
whether Congress intended the industry to be included within the
“chemical process plants” category.

We also disagree that section 169 clearly shows Congress’s intent on
what factors we must consider in making source category determinations.
As discussed below, we have used a variety of considerations in making
source category determinations.  We generally have not conducted
economic analysis in making these decisions, nor have we based our
decision on the end product produced or strictly followed an SIC
approach for all categories.  Nonetheless, we agree that economic
considerations can be relevant to our overall policy decisions to change
an existing interpretation of a definition.  Thus, in response to
comments we looked more closely at how fuel ethanol competes with
gasoline.

In 2004, ethanol fuel represented only 2.5% of 140 billion gasoline
consumed.  Ethanol is not currently cost competitive with gasoline, and
the market for fuel ethanol is heavily influenced by Federal incentives
and regulations.  For example, ethanol production is encouraged by a
Federal tax credit of 51 cents per gallon.  Small ethanol producers also
qualify for an additional production tax credit.  Some argue that the
fuel ethanol production industry would not survive with out these
incentives.  In other words, although fuel ethanol may be trying to
compete with the gasoline market, it is not currently doing so
successfully.  For this reason, we decline to retain our existing
definition of “chemical process plant” and decline to include the
fuel for ethanol facility within the petroleum refineries source
category as some commenters suggested.  We also do not believe that
today’s rule will place fuel ethanol plants at a competitive advantage
to petroleum facilities.  Moreover, fuel ethanol production would not be
profitable for most facilities and probably could not survive without
tax credits, which allow for and assist producers in meeting production
quotas driven by the Energy Policy Act of 2005.  Therefore, we believe
the ethanol industry is not comparable to other industries on the
section 169(l) list that have high profit margins, or that successfully
compete with gasoline.

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, fuel ethanol, 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.

	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
fuel ethanol 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 §169(1), needs to
discern whether a facility’s primary activity is a type listed as a
100 tpy “major” source in §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 today’s rule represents a change in our definition of
“chemical process plants”, it does not represent a change in our
general source category.  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.

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 assessment to determine whether a particular
stationary source belongs in a given source category.  (Docket No.
EPA-OAR-HQ-2006-0089-0086).

	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.

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.  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.  Today, with this action, we are acting in light of that
continuing discretion and the facts before us now .

Comment

Several commenters assert that EPA places too much reliance on
Congress’ use of the report submitted by Research Corporation of New
England (“Research Corp. report”) and the fact that ethanol
production was not specifically addressed in the report.  Commenters
assert that Congress’ silence can not be taken as an intent to exclude
ethanol from the “chemical process plants” definition.  One
commenter believes, that the mere fact that chemical processes occur and
that toxic chemicals are added is enough to conclude that Congress would
intend to regulate the industry as a chemical process plant.  A
commenter also stated that Congress used broad terms like “chemical
processing plants” precisely to capture new ways of making products
and to avoid having to change the statute in the future to capture these
activities.

Response

As noted in the proposal preamble and repeated here, section 111 of the
CAA requires the Administrator of EPA to establish Federal standards of
performance for new stationary sources which may significantly
contribute to air pollution and was intended by Congress to complement
the other air quality management approaches authorized by

the 1970 CAA.  After enactment of section 111, EPA hired Research
Corporation of New England (Research Corp.) to study stationary sources
of air pollution in order to establish priorities for developing and
promulgating NSPSs.

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 produces beverage, industrial, and
fuel ethanol 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.  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 fuel
ethanol 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 fuel ethanol production facilities are more
like refineries than an alcohol for consumption facility.  They argued
that fuel ethanol 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.  The majority
of ethanol produced in the U.S. is produced from sugar or starch-based
feedstock (e.g., corn, millet, beverage waste) using two basic
processes: the dry mill process and the wet mill process.  The key
difference between these two processes is the initial treatment of the
grain.  In the wet mill process, the grain is soaked and then ground to
remove germ, fiber, and gluten from the starch prior to cooking.

In the dry mill process, the grain or feedstock is not separated into
its constituent parts prior to cooking.  Both wet and dry milling
operations produce ethanol as well as other coproducts.  “Co-products
from the dry mill process, separated from the ethanol in the
distillation step, include distiller’s dried grain (DDG) and solubles
(S), which are often combined and referred to as DDGS. DDGS is used as
an animal feed. I n 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.”

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
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
fuel ethanol 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 fuel ethanol 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 §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

3.  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 fuel ethanol.  They
supported their position by stating that several plants currently use
milo along with corn to make fuel ethanol, 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.

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.  (Docket No. EPA-HQ-OAR-2006-0089-xxxx).  There is
currently no commercial cellulosic ethanol production plant operating in
the U.S., however, there are several existing pilot plants, and several
commercial plants are in the planning stages.

Based on the process diagrams and information received from commenters
that indicate that the fermentation and distillation processes are
similar (included as part of the technical record), even though the
pre-steps and after-steps may differ, we are expanding the exclusion of
the definition of “major emitting facilities” to include ethanol
production facilities that produce ethanol through natural fermentation
processes included in NAICS codes 325193 or 312140.

We are not excluding other chemicals (e.g., citric acid and propylene
glycol made from corn) made from renewable sources with this final rule.
 The scope of this rule is ethanol production and processes and there
was no solicitation, or sufficient basis provided, to support expansion
of exclusion to other chemicals.

B.	Why are ethanol production facilities regulated differently under
different programs and standards?

Several commenters provided input on the historic regulatory treatment
of wet and dry corn milling facilities which produce ethanol fuel.  Some
of the commenters stated that EPA’s proposal to exclude wet and dry
corn milling facilities from the definition of “chemical process
plants” was consistent with historic regulatory treatment, while
others argued that it was inconsistent with historic regulatory
treatment.

Comments:

The following comments were received on the historic and current
regulatory treatment of wet and dry corn milling facilities that produce
ethanol fuel.

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 C.F.R. 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 C.F.R. § 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 synthetic organic chemical
manufacturing industry (SOCMI) chemical for which 40 CFR part 60,
subpart YYY (SOCMI wastewater units) applies, however, the proposed rule
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
used this same list for determining from which source categories
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 and appropriate legislative rule.”  The
proposed rule Option 1 would 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 fuel
ethanol production from the list of facilities identified by EPA,
pursuant to CAA §302(j).  One commenter stated that the EPA can not
avoid making the necessary determinations to list a facility or source
pursuant to 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 for which fugitive emissions
should be counted.  The 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 fuel-ethanol 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 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 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 sources 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 302(j) rulemaking requirement that applies when
categories are added to the list.

Nonetheless, even if our action today triggers the 302(j) rulemaking
requirement, we believe this rulemaking constitutes a sufficient 302(j)
rule that is consistent with the way we interpreted that requirement in
1980 and re-affirmed in 1984.  (45 FR 52690 and 49 FR 43202).
Specifically, we determined that our action to list a category under
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 Adminstrator’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
51931.  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
302(j) rulemaking since the affected sources were afforded an
opportunity to comment on our policy decision.

In 1984, after re-examining our interpretation of the 302(j)
requirements, we affirmed that the rulemaking requirements of 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…

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 fed.reg. 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 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 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 302(j)
rulemaking, few ethanol facilities existed and inclusion of ethanol
manufacturers was not specifically analyzed in our 302(j) rule.
Irrespective of these potential shortcomings, when we examined the issue
more closely in 1981, we made a policy decision without conducting
technical analysis, to include fuel ethanol manufacturing within the
category.  We based this decision on a desire to maintain consistency
with use of SIC 28 and ease of implementation.  Thus, before today, we
considered this industry to be a source within the listed category.
Today, 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
302(j) determination not to count fugitive emissions from such
facilities.

Today’s decision is precisely the kind of “flexibility to provide
industry-by-industry consideration and appropriate tailoring of
coverage” envisioned by the Alabama Power Court (cite).  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 §169(1) of the
CAA, 42 USC §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
to 60-489, which govern the synthetic organic chemical manufacturing
industry.

The commenter stated that the EPA formally charged that fuel ethanol
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 USC 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 part 60.482-1 to 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 rip out 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 sans controls options, then EPA may face future
law suits 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,
which it is not, 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.

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
significant unreviewed emissions increases that would not occur in
absence of this rulemaking.

Response:

We acknowledge that there may be some unreviewed emissions increases as
a result of this rulemaking.  As mentioned previously, ethanol
production increases have been influenced and will continue to be
influenced by the Energy Policy Act of 2005 (P.L. 109-58), which
required the use of 4 billion gallons of renewable fuels in 2006,
increasing each year to 7.5 billion gallons in 2012.  In order to meet
the quotas driven by the Energy Policy Act of 2005, either new
facilities will be constructed or existing facilities will need to be
expanded.  The revision of the major source threshold applicable to the
fuel ethanol industry will allow for the construction of larger, more
efficient plants under existing State regulations without subjecting
them to a sometimes lengthy PSD permitting process which could impede
our nation’s ability to meet the policy mandates set out in the Energy
Policy Act.

There are an estimated 140 facilities that currently exist in the U.S.
that produce ethanol by natural fermentation as of January, 2007.  Of
these, an estimated 7 of the facilities are planning expansions.
Seventy-eight ethanol production facilities are currently under
construction.  (http:www.ethanolrfa.org/industry/locations/; Docket Item
No. EPA-HQ-OAR-2006-0089-xxxx).

We assessed an emissions inventory of “potential to emit” emissions
estimates for a 55 million gallon per year (mgy) denatured ethanol
production plant that is a hybrid wet-dry corn milling facility with 50
percent of its capacity being for dry corn milling ethanol production
(Conestoga Energy Partners, LLC, Liberal, KS.  (Docket No.
EPA-HQ-OAR-2006-0089-XXXX).  The following was observed regarding
overall plant emissions (with controls), and plant fugitive emissions:

For VOC emissions, it is estimated that plant controlled total emissions
are 100 tpy, where fugitives may account for an estimated 20 percent of
emissions.  Most of the uncontrolled fugitive emissions of VOC are from
the rail loadout.  Dry corn milling ethanol production emissions that
dry their distilled grain solubles tend to have higher emissions than
those that do not.  Because the inventory assessed was for a hybrid
plant with 50 percent of it’s capacity attributed to dry corn milling,
it is assumed that total controlled VOC emissions could be higher if 100
percent of the production was attributed to dry corn milling.

For CO emissions, it is estimated that total plant controlled emissions
are 100 tpy, none of which is considered fugitive.

For PM10 emissions, it is estimated that total plant controlled
emissions are 65 tpy, where fugitives may account for an estimated 13
percent of controlled emissions.  Most of the PM10 controlled fugitive
emissions reflect fugitive dust from facility roads.  No data was
available for PM2.5 emissions from ethanol production facilities.  It is
expected that PM2.5 emissions from these facilities would be small and
that mobile sources that transport ethanol from the facility would be
the largest source of PM2.5 emissions.

We also assessed some uncontrolled VOC emissions test data (which did
not include fugitive emissions) from a facility located in Minnesota
which includes uncontrolled DDSG dryer emissions.  The best measurement
of uncontrolled VOC emissions was done in 2002 at Ethanol 2000.  (See
Docket No. EPA-HQ-OAR- 2006-0089-XXXX).  Based on the assessed data, it
is estimated that an uncontrolled one mgy facility emits 14.7 tpy.
Based on this uncontrolled emission factor, a 7 mgy ethanol production
plant would emit 100 tpy of uncontrolled VOC emissions, and a 17 mgy
plant would emit 250 tpy uncontrolled VOC emissions.  Compensating for
some uncertainty, we assume that an 11 mgy ethanol production plant (7
mgy + 7/2 mgy = 10.5 mgy, or 11 mgy) would emit an estimated 100 tpy of
uncontrolled emissions and a 26 mgy ethanol production plant (17 mgy +
17/2 mgy = 25.5 or 26 mgy) would emit an estimated 250 tpy of
uncontrolled VOC emissions.

It has been EPA’s experience that there are many ethanol production
facilities in attainment areas that take on BACT or LAER controls in
order to be permitted as “synthetic minor” sources.
(EPA-HQ-OAR-2006-0089-XXXX).

	In nonattainment areas, ethanol production facilities will continue to
be subject to the 100 tpy threshold.    However, most ethanol production
facilities are located in attainment areas.  Conservatively,
approximately 17 of the 140 facilities (approximately 12 percent) are
located in nonattainment areas and it is assumed that most expansions
and new constructions in the future will continue to be in attainment
areas.

	One commenter provided that they estimated 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.  (EPA-HQ-OAR-2006-0089-0086).

Of the estimated facilities located in nonattainment areas, 4 of the
facilities have reported capacities between 3 and 5.5 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), they likely use
the fuel ethanol on-site, and it can be safely assumed that these kinds
of facilities are not and would not be affected by this rulemaking.

Approximately 7 of the facilities located in nonattainment areas are new
constructions that will be subject to the requirement to count fugitives
as major emitting sources as they began construction before the
effective date of this rulemaking.  Only one facility is currently
undergoing expansion in a nonattainment area.  This facility is subject
to Subpart 1 of Subpart D of the CAA requirements and is increasing
their ethanol production capacity from 67 mgy to 105 mgy.  The remaining
facilities located in nonattainment areas have ethanol production
capacities that range from 25 to 102 mgy.  It is assumed that all of
these facilities are subject to and will continue to be subject to LAER
controls.

As noted previously, PM10 fugitive emissions can account for 13 percent
of total facility PM10 emissions, and VOC fugitive emissions can account
for 20 percent of total VOC emissions.  We believe that it is unlikely
that there will be many (if any) of the specified ethanol production
facilities that will locate in nonattainment areas in the future, and
existing facilities currently permitted under nonattainment NSR must
continue to comply with their permit limitations unless, after
considering the air quality impacts of the revision, the permitting
authorizes a revision using the appropriate permitting procedures.

Assuming that a currently controlled 100 tpy VOC facility with LAER
controls is a 110 mgy facility (counting fugitives) and that 20 percent
of VOC emissions are fugitives that would no longer be included in NSR
applicability calculations, facilities that produce between 88 mgy and
110 mgy ethanol would be the only facilities that would be impacted if
constructed/expanded after the effective date of this rule.  The only
facility in existence that is undergoing expansion in a nonattainment at
this time that would fall in that range is the facility that is
expanding from 67 mgy to 105 mgy.  This facility would be allowed to
emit 20 tpy more than it would have been able to prior to this
rulemaking (which is only an estimated 0.001 percent of national VOC
emissions (an estimated 1.5 million tpy), and only an estimated 1
percent of the nonattainment areas’ total VOC emissions).

It is important to note that all fuel ethanol plants employ an active
leak detection and repair (LDAR) program to minimize VOC emissions from
tanks, valves, pumps and piping.  Fugitive particulate emissions from
vehicular traffic are controlled by a combination of paving and cleaning
plant roads and other dust suppression methods.  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 the fugitive
control measures that are employed at these facilities, we do not
believe that this rulemaking will result in significant unreviewed
emissions increases in nonattainment areas.

In attainment areas, as within nonattainment areas, some sources have
very low capacities that would fall below both a 100 tpy and 250 tpy
threshold and ethanol production is likely a secondary process at the
facility (e.g., reportedly, Central Wisconsin Alcohol in Plover, WI has
an ethanol production capacity of 11 mgy from seed corn; 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 and ethanol production
capacity of 2.6 mgy from cheese whey).  These sources, as noted for the
sources in nonattainment area sources, are more than likely producing
ethanol as a secondary source and are not in the business of producing
fuel ethanol for distribution/sale.

	Most of the existing ethanol production facilities in attainment areas
have capacities greater than 26 mgy and would (if they were constructed
after the effective date of this rule) therefore be considered “major
emitting facilities” under a 250 tpy threshold unless they took on
limits to be synthetic minor sources.  These sources are likely
currently permitted as synthetic minor sources or PSD major emitting
facilities under the 100 tpy threshold.  Units at these facilities would
continue to be subject to their permitted requirements under PSD.  There
are only an estimated 14 existing facilities with ethanol production
capacities between 11 mgy and 26 mgy.  These facilities are likely
controlled as synthetic minor sources or major emitting facilities under
the PSD 100 tpy threshold.  Most of the new constructions and expansion
facilities are greater than 26 mgy (there are only an estimated 4
facilities that are being constructed or expanded that have, or are
adding to their capacities at levels less than 26 mgy).  These new
constructions and expansions are likely permitted under the 100 tpy PSD
threshold or have taken on controls and limits as synthetic minor
sources.

	Assuming that a currently controlled 100 tpy VOC emissions facility
with BACT controls is a 110 mgy facility and that a controlled 250 tpy
VOC emissions facility produces 250 mgy, the impact of this rule would
only affect those facilities that would increase from a 100 tpy facility
to a 250 tpy facility.  Under the worse case scenario, this could occur
if such facility increases emissions by 250 tpy (up to the major source
threshold). =Provided that there are only about 10 facilities in
existence or under expansion that (which we will assume are controlled)
that fall in that range, there would only be an increase in VOC
emissions of 2,500 tpy nationally (or about 0.17 percent of VOC
nationally).

We believe that a larger plant that is able to produce more fuel ethanol
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.  Given the Energy
Policy directive, and the liklihood of larger capacity facilities being
better able to reduce emissions per gallon of ethanol produced, 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.

Additionally, research indicates that the use of fuel ethanol (85
percent ethanol fuel) in automobiles reduces tailpipe CO emissions by as
much as 30%, toxics content by 13% (mass) and 21% (potency), and
tailpipe fine PM emissions by 50%.  The use of fuel ethanol “also
reduces secondary PM formation by diluting aromatic content in
gasoline.”  (Docket Item No. EPA-HQ-OAR-2006-0089-XXXX).

In conclusion, though we acknowledge that there may be some unreviewed
emissions increases as a result of this rulemaking, we weighed and
considered the environmental consequences, the U.S. Energy Policy Act
directives, and potential environmental benefits from the use of high
grade fuel ethanol and determined that the consequences were acceptable
given the benefits to our nation.

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 fuel-ethanol plants (which tend to be
significantly larger than food-ethanol 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 fuel-ethanol will
result in much greater emissions of conventional pollutants such as NOx,
SO2, and PM, as well as increases in toxic pollutant such as mercury
that are not expressly regulated by the PSD program.  They also argued
that the use of coal will result in dramatic 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.

However, as another commenter (Docket No.  EPA-HQ-OAR-2006-0089-0074)
reported, and we agree, that while coal combustion is a source of
concern for some groups within the environmental community, today's
clean coal combustion technologies make it a viable fuel source and an
environmentally-friendly alternative to the volatile and higher priced
natural gas market.  (Docket No.  EPA-HQ-OAR-2006-0089-0074).

Comment:

Several commenters provided specific examples of situations where
implementation of our proposed Option could cause or contribute to the
negative impact of 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 nearly exceed 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 delegated State or local
government regulations/minor NSR program can be implemented to mitigate
such impacts.  In fact, a delegated State is allowed to maintain the 100
tpy threshold or other lower threshold in order to best serve their air
quality/economic needs.  If a State’s regulations provide that their
major PSD thresholds cannot be more stringent than those prescribed by
the Federal programs, their 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 is local and Regional concerns that this
rule is contrary to the purposes of the PSD program.  It is true that
purpose of the PSD program is to ensure that new sources do not cause or
contribute to an area that is in attainment to become a nonattaiment
area.  However, we believe that 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 NSPSs (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),
and subpart DDDDD (boilers).  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?

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 C.F.R.
part 60 are applicable for estimating the total mass emissions of VOCs,
as defined in 40 C.F.R. 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 webpage (  HYPERLINK
"http://www.epa.gov/ttn/emc/prelim/otm11.pdf"
http://www.epa.gov/ttn/emc/prelim/otm11.pdf ).  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 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?

[Note:  This section is under development.]

VI.	What implementation issues are related to this final rule?

[Note:  This section is under development.]

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 (RFA)

The 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 statue
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 today's 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.  Today’s 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, today’s rule is not subject to the
requirements of sections 202 and 205 of the UMRA.

E.	Executive Order 13132 - Federalism

Executive Order 13132, entitled "Federalism" (64 FR 43255, August 10,
1999), requires EPA to develop an accountable process to ensure
"meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications."
"Policies that have federalism implications" is defined in the Executive
Order to include regulations that have "substantial direct effects on
the States, on the relationship between the national government and the
States, or on the distribution of power and responsibilities among the
various levels of government."

Under section 6(b) of Executive Order 13132, EPA may not issue a
regulation that has federalism implications, that imposes substantial
direct compliance costs, and that is not required by statute, unless the
Federal government provides the funds necessary to pay the direct
compliance costs incurred by State and local governments, or EPA
consults with State and local officials early in the process of
developing the proposed regulation.  Under section 6(c) of Executive
Order 13132, EPA may not issue a regulation that has federalism
implications and that preempts State law, unless the Agency consults
with State and local officials early in the process of developing the
proposed regulation.

EPA has concluded that this final rule will not have federalism
implications.  It will not impose substantial direct compliance costs on
State or local governments, nor will it preempt State law.  Thus, the
requirements of sections 6(b) and 6(c) of the Executive Order do not
apply to this rule.

In the spirit of Executive Order 13132, and consistent with EPA policy
to promote communications between EPA and State and local governments,
the EPA specifically solicited comment on the proposed rule from State
and local officials.

F.	Executive Order 13175 - Consultation and Coordination with Indian
Tribal Governments

Executive Order 13175, entitled “Consultation and Coordination with
Indian Tribal Governments” (65 FR 13175, November 9, 2000), requires
EPA to develop an accountable process to ensure “meaningful and timely
input by tribal officials in the development of regulatory policies that
have tribal implications.”  This final rule does not have tribal
implications, as specified in Executive Order 13175.  Thus, Executive
Order 13175 does not apply to this rule.

Although Executive Order 13175 does not apply to this final rule, EPA
specifically solicited comment on the proposed rule from tribal
officials.

G.	Executive Order 13045 - Protection of Children from Environmental
Health Risks and Safety Risks

Executive Order 13045, entitled "Protection of Children from
Environmental Health Risks and Safety Risks" (62 FR 19885, April 23,
1997), applies to any rule that: (1) is determined to be "economically
significant" as defined under Executive Order 12866; and (2) concerns an
environmental health or safety risk that EPA has reason to believe may
have a disproportionate effect on children.  If the regulatory action
meets both criteria, the Agency must evaluate the environmental health
or safety effects of the planned rule on children, and explain why the
planned regulation is preferable to other potentially effective and
reasonably feasible alternatives considered by the Agency.

EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern health or safety risks, such that the
analysis required under section 5-501 of the Executive Order has the
potential to influence the regulation.  This final rule is not subject
to Executive Order 13045 because it is not “economically
significant” as defined in Executive Order 12866 and because the
Agency does not have reason to believe the environmental health or
safety risks addressed by this action present a disproportionate risk to
children.

H.	Executive Order 13211 - Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

These final amendments do not constitute a  “significant energy
action” as defined in Executive Order 13211, “Actions Concerning
Regulations That Significantly Affect Energy Supply, Distribution, or
Use” (66 FR 28355, May 22, 2001), because they will not likely have a
significant adverse effect on the supply, distribution, or use of
energy.

I.	National Technology Transfer and Advancement Act

As noted in the proposed rule, section 12(d) of the National Technology
Transfer and Advancement Act of 1995 (NTTAA), Public Law 104-113, 12(d)
(15 U.S.C. 272 note), directs EPA to use voluntary consensus standards
in its regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical.

Voluntary consensus standards are technical standards (for example,
materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary consensus
standards bodies.  The NTTAA directs EPA to provide Congress, through
OMB, explanations when the Agency decides not to use available and
applicable voluntary consensus standards.

These final rule amendments do not involve technical standards.
Therefore, EPA did not consider the use of any voluntary consensus
standards.

J.	Executive Order 12898 - Federal Actions to Address Environmental
Justice in Minority Populations and Low-income Populations

Executive Order 12898 (59 FR 7629 (Feb. 16, 1994)) establishes Federal
executive policy on environmental justice.  Its main provision directs
Federal agencies, to the greatest extent practicable and permitted by
law, to make environmental justice part of their mission by identifying
and addressing, as appropriate, any disproportionately high and adverse
human health or environmental effects of their programs, policies, and
activities on minority populations and low-income populations in the
United States.

	EPA has determined that this final rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not affect
the level of protection provided to human health or the environment
because, even though changes are being made to the, major nonattainment
NSR, and title V programs, it does not change a permitting authority’s
obligation to maintain the NAAQS.

K.	Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating the
rule must submit a rule report, which includes a copy of the rule, to
each House of the Congress and to the Comptroller General of the United
States.  EPA will submit a report containing this rule and other
required information to the U.S. Senate, the U.S. House of
Representatives, and the Comptroller General of the United States prior
to publication of the rule in the Federal Register.  A major rule cannot
take effect until 60 days after it is published in the Federal Register.
 These final rule amendments do not constitute a “major rule” as
defined by 5 U.S.C. 804(2).  Therefore, this rule will be effective [30
DAYS AFTER PUBLICATION IN THE FEDERAL REGISTER].

VIII.	Judicial Review

	Under section 307(b)(1) of the Act, judicial review of today’s final
action is available by filing of a petition for review in the U.S. Court
of Appeals for the District of Columbia Circuit by [INSERT DATE 60 DAYS
AFTER PUBLICATION IN THE FEDERAL REGISTER].  Any such judicial review is
limited to only those objections that are raised with reasonable
specificity in timely comments.  Under section 307(b)(2) of the Act, the
requirements of today’s final action may not be challenged later in
civil or criminal proceedings brought by us to enforce these
requirements.

List of Subjects

40 CFR Parts 51 and 52

Environmental protection, Administrative practice and procedure, Air
pollution control, Intergovernmental relations, Nitrogen dioxide, Ozone,
Particulate matter, Reporting and recordkeeping requirements, Sulfur
oxides.

40 CFR Parts 70 and 71

Environmental protection, Administrative practice and procedure, Air
pollution control, Intergovernmental relations, Reporting and
recordkeeping requirements.

________________________

Dated:

_________________________

Stephen L. Johnson,

Administrator.

PART 51 – [AMENDED]

	1.  The authority citation for part 51 continues to read as follows:

	Authority:  23 U.S.C. 101; 42 U.S.C. 7401, et seq.

Subpart I – [Amended]

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

§51.165  Permit requirements.

	(a) * * *

	(1) * * *

	(iv) * * *

	(C) * * *

	(20)  Chemical process plants – The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

	(4) * * *

	(xx)  Chemical process plants – The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

	3.  Section 51.166 is amended by revising paragraphs (b)(1)(i)(a),
(b)(1)(iii)(t), and (i)(1)(ii)(t) to read as follows:

§51.166  Prevention of significant deterioration of air quality.

* * * * *

	(b)  Definitions. * * *

	(1)(i)  Major stationary source means:

	(a)  Any of the following stationary sources of air pollutants which
emits, or has the potential to emit, 100 tons per year or more of any
regulated NSR pollutant:  Fossil fuel-fired steam electric plants of
more than 250 million British thermal units per hour heat input, coal
cleaning plants (with thermal dryers), kraft pulp mills, portland cement
plants, primary zinc smelters, iron and steel mill plants, primary
aluminum ore reduction plants (with thermal dryers), primary copper
smelters, municipal incinerators capable of charging more than 250 tons
of refuse per day, hydrofluoric, sulfuric, and nitric acid plants,
petroleum refineries, lime plants, phosphate rock processing plants,
coke oven batteries, sulfur recovery plants, carbon black plants
(furnace process), primary lead smelters, fuel conversion plants,
sintering plants, secondary metal production plants, chemical process
plants (which does not include ethanol production facilities that
produce ethanol by natural fermentation included in NAICS codes 325193
or 312140), fossil-fuel boilers (or combinations thereof) totaling more
than 250 million British thermal units per hour heat input, petroleum
storage and transfer units with a total storage capacity exceeding
300,000 barrels, taconite ore processing plants, glass fiber processing
plants, and charcoal production plants;

* * * * *

	(iii) * * *

	(t)  Chemical process plants – The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

	(i)  Exemptions.

	(1) * * *

	(ii) * * *’

	(t)  Chemical process plants – The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

Appendix S to Part 51 – [Amended]

	4.  Appendix S to Part 51 is amended by revising paragraphs
II.A.4.(iii)(t), and II.F.(20) to read as follows:

Appendix S to Part 51 – Emission Offset Interpretative Ruling.

* * * * *

	II. * * *

	A. * * *

	4. * * *

	(iii) * * *

	(t)  Chemical process plants - The term chemical processing plant shall
not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

	II. * * *

	F. * * *

	(20)  Chemical process plants - The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

PART 52 – [AMENDED]

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

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

Subpart A – [Amended]

	6.  Section 52.21 is amended by revising paragraphs (b)(1)(i)(a),
(b)(1)(iii)(t), and (i)(1)(vii)(t) to read as follows:

§52.21  Prevention of significant deterioration of air quality.

* * * * *

(b)  Definitions. * * *

	(1)(i)  Major stationary source means:

	(a)  Any of the following stationary sources of air pollutants which
emits, or has the potential to emit, 100 tons per year or more of any
regulated NSR pollutant:  Fossil fuel-fired steam electric plants of
more than 250 million British thermal units per hour heat input, coal
cleaning plants (with thermal dryers), kraft pulp mills, portland cement
plants, primary zinc smelters, iron and steel mill plants, primary
aluminum ore reduction plants (with thermal dryers), primary copper
smelters, municipal incinerators capable of charging more than 250 tons
of refuse per day, hydrofluoric, sulfuric, and nitric acid plants,
petroleum refineries, lime plants, phosphate rock processing plants,
coke oven batteries, sulfur recovery plants, carbon black plants
(furnace process), primary lead smelters, fuel conversion plants,
sintering plants, secondary metal production plants, chemical process
plants (which does not include ethanol production facilities that
produce ethanol by natural fermentation included in NAICS codes 325193
or 312140), fossil-fuel boilers (or combinations thereof) totaling more
than 250 million British thermal units per hour heat input, petroleum
storage and transfer units with a total storage capacity exceeding
300,000 barrels, taconite ore processing plants, glass fiber processing
plants, and charcoal production plants;

* * * * *

	(iii) * * *

	(t)  Chemical process plants – The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

	(i)  Exemptions.

	(1) * * *

	(vii) * * *’

	(t)  Chemical process plants – The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

* * * * *

PART 70 – [AMENDED]

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

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

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

§70.2  Definitions.

* * * * *

	Major source * * *

	(2) * * *

	(xx)  Chemical process plants – The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

PART 71 – [AMENDED]

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

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

Subpart A – [Amended]

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

§71.2  Definitions.

* * * * *

	Major source * * *

	(2) * * *

	(xx)  Chemical process plants – The term chemical processing plant
shall not include ethanol production facilities that produce ethanol by
natural fermentation included in NAICS codes 325193 or 312140;

* * * * *

 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.”

 Yacobucci, Brent D., Congressional Research Service.  The Library of
Congress.  Fuel Ethanol: Background and Public Policy Issues.  March 3,
2006.  Order Code RL33290.  [Docket No. EPA-HQ-OAR-2006-0089-XXXX]

 See e.g. Memo. Edwin B. Erickson, Regional Administrator, to George
Clemon Freeman, Counsel for Reserve Coal Proportion Company, July 06,
1996 (Docket No. EPA-HQ-OAR-2006-0089-XXXX), 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 (Docket No. EPA-HQ-OAR-2006-0089-XXXX).

 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.  (Docket Nos. EPA-HQ-OAR-2006-0089-XXXX,
EPA-HQ-OAR-2006-0089-XXXX).

 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.  (EPA-HQ-OAR-2006-0089-XXXX).

 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.  (Docket No.
EPA-HQ-OAR-2006-0089-XXXX).

 Memorandum from Mary Lalley, Easter Research Group, Inc., to Bob
Rosensteel, U.S. EPA, July 2, 2002.

 Memorandum from Mary Lalley, July 2, 2002.  (Docket No.
EPA-HQ-OAR-2006-0089-XXXX).

 Documentation for the Final 2002 Point Source National Emissions
Inventory.  Emission Inventory and Analysis Group, Air Quality and
Analysis Division, U.S. Environmental Protection Agency, Research
Triangle Park, NC  27711.  February 10, 2006.  (Docket No.
EPA-HQ-OAR-2006-0089-XXXX).
(http://www.epa.gov/ttn/chief/net/2002inventory.html#documentation)

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March 20, 2007

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