[Federal Register Volume 59, Number 55 (Tuesday, March 22, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-5721]
[[Page Unknown]]
[Federal Register: March 22, 1994]
_______________________________________________________________________
Part II
Environmental Protection Agency
_______________________________________________________________________
40 CFR Part 76
Acid Rain Program; Nitrogen Oxides Emission Reduction Program; Final
Rule
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 76
[AD-FRL-4845-9]
RIN 2060-AD45
Acid Rain Program; Nitrogen Oxides Emission Reduction Program
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: This action promulgates standards establishing nitrogen oxides
(NOX) emission limitations for certain coal-fired utility units,
as specified in section 407(b)(1) of the Clean Air Act (``the Act'').
This action also establishes other requirements and procedures for all
coal-fired utility units subject to NOX emission limitation
requirements under Phase I or Phase II of the Acid Rain Program. This
rule will reduce annual emissions of NOX, a principal precursor to
acidic deposition.
EFFECTIVE DATE: March 22, 1994. The incorporation by reference of
certain publications listed in the rule is approved by the Director of
the Federal Register as of March 22, 1994.
ADDRESSES: Docket. Docket No. A-92-15, containing information
considered during development of the promulgated standards, is
available for public inspection and copying between 8:30 a.m. and 3:30
p.m., Monday through Friday, at EPA's Air Docket Section (LE-131),
Waterside Mall, room M1500, 1st Floor, 401 M Street SW., Washington, DC
20460. A reasonable fee may be charged for copying. Additional data and
information pertaining to the rule may be found in Docket No. A-90-39.
Background information document. The background information
document containing responses to public comments on the proposed
standards may be obtained from the docket. Please refer to ``Nitrogen
Oxides Emission Reduction Program--Response to Comments Document''.
FOR FURTHER INFORMATION CONTACT: Peter Tsirigotis, Source Assessment
Branch, Acid Rain Division (6204J), U.S. Environmental Protection
Agency, 401 M Street SW., Washington, DC 20460 (202-233-9620).
SUPPLEMENTARY INFORMATION: The information in this preamble is
organized as follows:
I. Background
A. Purpose of Acid Rain NOX Emission Reduction Program
B. Statutory Authority
C. Summary of Final Rule
D. Applicability
II. Public Participation
III. Summary of Major Comments and Responses
A. Low NOX Burner Technology
1. Definition of Low NOX Burner Technology
2. Performance of Low NOX Burner Technology
3. Cost of Low NOX Burner Technology
B. Alternative Emission Limitations
1. Eligibility Requirements
2. Demonstration Period and Operating Period
3. Data and Certification Requirements
4. Testing Requirements
5. Inclusion of Alternative Emission Limitation Procedures for
Alternative Technologies
C. Emissions Averaging
1. Separate Designated Representative for NOX
2. Common Designated Representative
3. Emissions Averaging as a Prerequisite for an Alternative
Emission Limitation
4. Emissions Averaging Across State Lines
5. Title IV NOX Program's Relationship to Title I
D. Early Election
1. The Benefits of Early Election and its Inclusion in the Final
Rule
2. The Date and Eligibility for Receiving Grandfathering
3. The Ability of Early Election Units to Average Emissions with
Phase I Units
4. The Ability of Early Election Units to Average Emissions with
Phase II Units
5. The Consequences of the Failure to Maintain the Phase I
Standards
6. The Option to Elect Out of Early Election
E. Banking Issues
IV. Administrative Requirements
A. Docket
B. Executive Order 12866
C. Paperwork Reduction Act
D. Regulatory Flexibility Act
E. Miscellaneous
I. Background
A. Purpose of Acid Rain NOX Emission Reduction Program
The primary purpose of the Acid Rain NOX Emission Reduction
Program is to reduce the adverse effects of acidic deposition on
natural resources, ecosystems, visibility, materials, and public health
by substantially reducing annual emissions of NOX, a principal
acidic deposition precursor, from coal-fired electric utilities.
Electric utilities are a major contributor to NOX emissions
nationwide: in 1980, they accounted for 30 percent of total NOX
emissions and, by 1990, their contribution rose to 38 percent of total
NOX emissions. Approximately 80 percent of electric utility
NOX emissions come from coal-fired plants of the type addressed by
section 407 of the Act. Further, recent findings from the National
Academy of Sciences' study on ozone control provide additional support
for utility NOX emission controls. (See Docket Item II-I-110.)
They indicate that such controls would produce dual benefits to many
geographic areas, particularly in the northeastern United States, by
reducing not only atmospheric loadings for acidic deposition but also
ground-level ozone for ozone non-attainment areas.
Although sulfate deposition is considered to be the major
contributor to long-term aquatic acidification, nitric acidic
deposition plays a dominant role in the ``acid pulses'' associated with
the fish kills observed during the springtime meltdown of the snowpack
in sensitive watersheds. Furthermore, the atmospheric deposition of
nitrogen oxides is a substantial source of nutrients that damage
estuaries such as the Chesapeake Bay by causing algae blooms and anoxic
conditions. Nitrogen dioxide and particulate nitrate also contribute to
pollutant haze. Acidic deposition and ozone contribute to the premature
weathering and corrosion of building materials such as architectural
paints and stones.
B. Statutory Authority
The statutory authority for the regulations in 40 CFR part 76 is
contained in section 407 of the Act. Section 407(b) requires the
Administrator to establish NOX emission limitations (on a pound
per million British thermal unit (lb/mmBtu), annual average basis) for
coal-fired utility units of different boiler types. Under section
407(b)(1), The Administrator must establish NOX emission
limitations for two types of utility boilers: (1) Tangentially fired
boilers and (2) dry bottom wall-fired boilers (other than units
applying cell burner technology). The emission rates (in lb/mmBtu) are
not to exceed the rates specified in section 407(b)(1)(A)-(B), although
EPA may set a higher rate for one or both types of boilers if the
Administrator finds that the listed rate(s) cannot be achieved using
low NOX burner technology. The EPA believes that a majority of
each type of boiler can meet the emission limitations specified in the
statute using properly designed and properly operated low NOX
burner technology.
A Phase I coal-fired utility unit with a tangentially fired boiler
or a dry bottom wall-fired boiler (not applying cell burner technology)
must comply with the promulgated annual NOX emission limitations
on January 1, 1995, or the date the unit is required to meet sulfur
dioxide (SO2) emission reduction requirements under sections 404
and 409 of the Act. The EPA may, by January 1, 1997, revise these
NOX emission limitations to be more stringent for Phase II utility
units if the Administrator determines that more effective low NOX
burner technology has become available. Under section 407(b)(2), EPA
must establish NOX emission limitations (on a lb/mmBtu annual
average basis) for wet bottom wall-fired boilers, cyclones, units
applying cell burner technology, and all other types of utility boilers
by January 1, 1997.
Section 407(c), Revised Performance Standards, requires EPA to
revise the NOX emission limitations under existing new source
performance standards (NSPS) for fossil-fuel-fired steam generating
units, including electric utility and nonutility units (40 CFR 60,
subparts D, Da, Db) to reflect improvements in methods for NOX
emission control. The revised NSPS are being developed by EPA under a
separate rulemaking and are not a part of today's rule implementing the
Acid Rain NOX Emission Reduction Program.
Section 407(d), Alternative Emission Limitations, allows the owner
or operator of an affected coal-fired utility unit to request a less
stringent NOX emission limitation upon a determination that: (1) A
unit subject to section 407(b)(1) cannot meet the applicable
promulgated emission limitation (referred to hereafter as ``applicable
emission limitation'') using low NOX burner technology, or (2) a
unit subject to section 407(b)(2) cannot meet the applicable emission
limitation ``using the technology on which the Administrator based the
applicable emission limitation.'' Section 407(d) also specifies the
criteria and process the permitting authority must use in authorizing
an alternative emission limitation (AEL). Finally, section 407(d)
states that, ``units subject to [section 407(b)(1)] for which an
alternative emission limitation is established shall not be required to
install additional control technology beyond low NOX burners.''
Under section 407(d), EPA may grant the owner or operator of a
Phase I coal-fired utility unit subject to section 407(b)(1) a 15-month
extension from the January 1, 1995, compliance deadline if the
technology necessary to meet the promulgated NOX emission
limitation is not in adequate supply to enable its installation and
operation at the unit, consistent with system reliability, by the
prescribed date. Section 407(d) specifies the criteria and process the
permitting authority must use in authorizing the Phase I extension.
Section 407(e), Emissions Averaging, provides the owner or operator
of two or more units subject to NOX emission limitations
promulgated pursuant to section 407(b)(1) or section 407(b)(2) with the
option of averaging emissions among its units in lieu of complying on a
unit-specific basis with the applicable emission limitation. Under
section 407(e), the actual Btu-weighted annual emission rate averaged
over the units in an averaging plan must be no greater than the Btu-
weighted annual average emission rate for the same units had they been
operated, during the same period of time, in compliance with the
applicable emission limitations. The individual emission limitations
granted to units in an averaging plan are to be effective in lieu of
the applicable emission limitation only as long as the units operate
under the conditions specified in their respective permits.
C. Summary of Final Rule
Title IV of the 1990 Amendments provides for the reduction of
NOX emissions from coal-fired utility boilers in two phases. In
the first phase covered by this rulemaking, two categories of burners
are affected: dry bottom wall-fired and tangentially fired boilers
(Group 1). Group 1 boilers under Phase I must meet the performance
standards by January 1, 1995. About one-quarter of all Group 1 boilers
are covered in Phase I. If more effective low NOX burner
technology becomes available, EPA may promulgate more stringent
standards by January 1, 1997, for Phase II dry bottom wall-fired and
tangentially fired boilers. Such rulemaking would include NOX
emission limitations for all other coal-fired utility boilers (Group 2)
as well. However, Phase I units with Group 1 boilers will not be
subject to any revised requirements. If new standards are not revised
in 1997, Phase II units with Group 1 boilers will be subject, beginning
January 1, 2000, to the emission limitations promulgated in today's
rule.
The final rule includes annual NOX emission limitations of
0.50 lb/mmBtu for dry bottom wall-fired boilers and 0.45 lb/mmBtu for
tangentially fired boilers. The rule encourages early compliance with
the Phase I, Group 1 standards by allowing Phase II units with Group 1
boilers that comply with the Phase I emission limitations by calendar
year 1997, to be grandfathered from any revisions to the Group 1
standards until 2008 (all other Phase II units will have to meet the
revised standards in 2000). The rule also establishes procedures
allowing utilities with the same owner or operator, and the same
designated representative, to average emissions among affected units to
comply with the NOX emission limitations. Further flexibility is
provided by establishing procedures to allow affected units with Group
1 boilers to obtain an alternative emission limitation where it is
demonstrated that they cannot meet applicable emission limitations
through the use of low NOX burner technology.
Also included in today's rulemaking are requirements for Phase I
compliance date extensions and the cost basis for determining
appropriate control technology and NOX emission limitations for
Group 2 boilers. The rule allows each affected unit to comply with the
applicable emission limitation using any NOX emission reduction
control technology approach, including low NOX burner technology,
alternative control technologies, fuel switching, and changes to boiler
operating parameters.
D. Applicability
The final rule applies to existing coal-fired utility units subject
to SO2 emission limitations or reduction requirements under Phase
I or Phase II of the Acid Rain Program pursuant to sections 404, 405,
and 409 of the Act, including substitution units designated and
approved as Phase I units in substitution plans that are in effect on
January 1, 1995. The rule also applies to new coal-fired units that are
affected units allocated allowances under section 405 of the Act.
The provisions of part 76 apply to each coal-fired utility unit
subject to sections 404(d) or 409(b), on the date the unit is required
to meet SO2 emission reduction requirements under the Acid Rain
Program, except for a substitution unit designated in a substitution
plan that is not in effect on January 1, 1995. Thus, the granting of a
Phase I SO2 compliance extension pursuant to section 404(d) of the
Act or a repowering extension pursuant to section 409(b) of the Act
would similarly extend the required date for compliance with NOX
emission limitations under the Acid Rain Program.
Appendix A to part 76 contains three lists to assist the owner or
operator of each Phase I unit in determining whether that unit must
comply with the NOX emission limitations in the final rule and, if
so, the applicable emission limitation: (1) Units with tangentially
fired boilers that are required to comply with the Phase I NOX
emission limitation for tangentially fired boilers; (2) units with dry
bottom wall-fired boilers (other than units applying cell burner
technology) that are required to comply with the Phase I NOX
emission limitation for dry bottom wall-fired boilers; and (3) units
with dry bottom wall-fired boilers applying cell burner technology that
are exempt from Phase I NOX emission limitations unless converted
to conventional burner technology on or before January 1, 1995.
Comments on the proposed rule pointed out several errors in Appendix A.
The Agency has corrected all errors of which it is aware and is
including the corrected appendix in the final rule. Phase I coal-fired
utility units with a Group 1 boiler that convert to a fluidized bed or
other type of utility boiler not included in Group 1 boilers on or
before January 1, 1995, are exempt from the NOX emission
limitations in today's final rule but will be required to comply with
any NOX emission limitations promulgated pursuant to section
407(b)(2) of the Act. Appendix A is provided for guidance only, and any
misclassifications or omissions of units in Appendix A do not excuse
the owners or operators from their NOX emission limitation
responsibilities under section 407 of the Act and the rule.
Pursuant to section 407(b)(2) of the Act, not later than January 1,
1997, the Administrator may revise the NOX emission limitations in
the final rule for Group 1 boilers to be more stringent, if the
Administrator determines more effective ``low NOX burner
technology'' has become available. Generally, revised limitations would
apply to existing Phase II coal-fired utility units with Group 1
boilers; compensating units with Group 1 boilers; and substitution
units with Group 1 boilers not subject to Acid Rain SO2 emission
reduction requirements on January 1, 1995. Phase I units with Group 1
boilers (other than compensating units and substitution units not
subject to Acid Rain SO2 emission reduction requirements on
January 1, 1995) are statutorily exempt from any revised NOX
emission limitations for Group 1 boilers. The exempt Phase I units
include Phase I units with Group 1 boilers that have been granted a
Phase I extension for SO2.
II. Public Participation
Regulations were proposed in the Federal Register on November 25,
1992 (57 FR 55632). The notice invited public comments and copies of
the proposed rule were made available to interested parties.
The EPA held two public hearings to provide interested parties the
opportunity for oral presentation of data, views, or arguments
concerning the proposed regulations. The first hearing was held on
December 15, 1992, in Chicago, Illinois and the second hearing was held
on December 21, 1992, in Washington, DC. A total of four persons
testified at the hearings concerning issues related to the proposed
regulations. The hearings were open to the public, and each attendee
was given an opportunity to comment on the proposed regulations. (See
Docket Items IV-F-1 and IV-F-2.) In addition, the initial public
comment period (November 25, 1992 to January 25, 1993) was extended to
February 8, 1993 in response to written requests. (See Docket Item IV-
I-1.)
III. Summary of Major Comments and Responses
A total of 145 comment letters were received regarding the proposed
regulations. Commenters included utilities and industry associations,
environmental organizations, States, and technology manufacturers and
suppliers. A copy of each comment received is included in the
rulemaking docket. A list of commenters, their affiliations, and the
EPA docket number assigned to their correspondence is included in the
background information document.
Most of the comment letters contained multiple comments, which have
been organized and addressed under the following general topics: Low
NOX Burner Technology, Alternative Emission Limitations, Emissions
Averaging, Early Election, and Banking Issues. These comments have been
carefully considered, and where determined to be appropriate by the
Administrator, changes have been made in the final regulations. A
summary of the major comments received and the Agency response thereto
is set forth in the following sections.
A. Low NOX Burner Technology
1. Definition of Low NOX Burner Technology
Section 407(b)(1) of the Act identifies maximum emission
limitations (often referred to as the ``presumptive limits'') for Phase
I tangentially fired and wall-fired boilers that Congress considered
achievable using low NOX burner technology. In addition, section
407(d) states that an AEL shall be authorized if ``a unit subject to
subsection (b)(1) cannot meet the applicable limitation using low
NOX burner technology.'' However, section 407(d) also states that:
``[u]nits subject to subsection (b)(1) for which an alternative
emission limitation is established shall not be required to install any
additional control technology beyond low NOX burners.''
There has been substantial controversy as to whether Congress
intended ``low NOX burner technology'' to be equivalent to ``low
NOX burners'' and whether ``low NOX burners'' include all
forms of combustion air staging or only those physically contained
within the burner assembly.
The proposed rule contained two regulatory options for defining
``low NOX burner technology.'' Option 1 defined low NOX
burner technology as ``low NOX burners incorporating overfire
air'' for wall-fired boilers and as ``low NOX burners
incorporating separated overfire air'' for tangentially fired boilers.
Option 2 also defined low NOX burner technology as ``low NOX
burners incorporating separated overfire air'' for tangentially fired
boilers, but excluding overfire air (OFA) from the definition for wall-
fired boilers.
Comment: Comments on the proposed rule were highly polarized with
respect to the definition of ``low NOX burner technology.'' Some
commenters favored the most narrow definition that would exclude
``separated overfire air'' for tangentially fired boilers and all forms
of combustion air staging outside the burner assembly for wall-fired
boilers. (While this definition was not put forward as an option in the
proposed rule, the preamble evaluated this alternative and solicited
comment on this approach.) Other commenters favored the least narrow
definition (Option 1) of ``low NOX burner technology'' that would
include all forms of combustion air staging, and specifically overfire
air, for both tangentially fired and wall-fired boilers. The regulatory
implications of incorporating or eliminating overfire air from the
definition of low NOX burner technology include setting minimum
control technology requirements that must be met prior to receiving an
AEL as well as cost and performance standards for future regulatory
requirements.
Response: The Act does not define the term ``low NOX burner
technology.'' Where, as in this case, Congress has not explicitly
spoken, the Agency is afforded broad deference in defining statutory
terms. (See Chevron U.S.A. v. NRDC, 467 U.S. 837 (1984).) Here EPA must
exercise its discretion and adopt a definition it believes is
consistent with the statutory language, the legislative history, and
Congressional intent underlying the provisions in the Act. Several
industry commenters contend that the legislative history indicates that
Congress had a clear understanding of the meaning of ``low NOX
burner technology'' and that the term does not include any type of
overfire air. (See pp. 42-50 of Docket Item IV-D-111.) Most
importantly, these commenters contend that the language of the
Conference Report, which provides that the ``NOX reductions from
existing units mandated under section 407 are to be accomplished by use
of conventional, available burner technology (`low NOX
burners'),'' provides clear evidence of Congressional intent with
respect to overfire air. Their contention is that low NOX burner
systems incorporating overfire air were not commercially available at
the time of enactment and, thus, conventional available burner
technology does not include overfire air.
The EPA disagrees with the commenters' contention that the
definition of low NOX burner technology included as Option 1 in
the proposed rule is inconsistent with the statutory language or the
Congressional intent underlying section 407 of the Act. For the reasons
set forth below, EPA believes that Option 1, which is being adopted
today, is a reasonable interpretation of the term ``low NOX burner
technology.''
This determination is based on EPA's evaluation of low NOX
burner technology viewed from several perspectives: the fundamental
chemical process of low NOX combustion; the history and
application of low NOX combustion technology as viewed by the
technical community; the intent of Congress as voiced by the Act; and
the actual application of NOX control technology.
Fundamental chemical process. One perspective that is useful in
determining the appropriate definition of low NOX burner
technology is to understand the fundamental chemical process governing
low NOX combustion techniques. This process clearly distinguishes
low NOX burners and overfire air from alternative control
technologies such as selective noncatalytic reduction (SNCR), selective
catalytic reduction (SCR), and reburning, which are based on
fundamentally different chemical processes.
The combustion of pulverized coal is an extremely complex process
involving chemical reactions, heat, and mass transfer of a highly
heterogeneous solid material. A simplified description of these
processes can be given in four major steps: (1) The temperature of the
particle of coal increases rapidly as it enters the combustion zone;
(2) the inherent moisture is evaporated and the volatile matter is
driven off; (3) the volatile matter ignites almost instantly, further
driving the heating and devolatilization of the particle; and (4) the
remaining carbon-based char particle is then consumed at high
temperature leaving the ash and a small amount of unburned carbon. (See
Docket Item IV-J-14.) It is during this process that nitrogen oxides
are formed, primarily in the form of NO.
The chemistry of NOX formation adds another layer of
complexity to the coal combustion process. There are two primary
formation processes of NOX during the combustion of pulverized
coal, thermal NOX and fuel NOX. Thermal NOX is produced
by the chemical combination of atmospheric oxygen and atmospheric
nitrogen at high temperatures and is produced by all high temperature
reactions in air. Thermal NOX can be effectively controlled by
either limiting the availability of either of the two reactants (oxygen
and nitrogen) or by limiting the reaction temperature, since the
NOX formation reaction is highly temperature dependent. Fuel
NOX is produced from a reaction of the nitrogen found in the fuel
with the oxygen in the combustion air and can be reduced by limiting
the availability of oxygen during the period when the fuel-bound
nitrogen is released during the devolatilization stage of combustion.
In coal combustion, thermal NOX accounts for 20 to 50 percent
of the total emissions, and fuel NOX accounts for the remaining 50
to 80 percent. (See Docket Item IV-J-12.) Reduction of NOX
emissions in practical systems is accomplished by modification of the
combustion process to achieve ``low NOX combustion.'' These
process modifications reduce the formation of fuel NOX in full
scale applications by a process known as ``staging,'' whereby a portion
of the combustion air is introduced to the stream of pulverized coal
and ``primary'' air (which is used both to transport the coal and to
provide the initial combustion air) in incremental stages, rather than
in a single step. By staging the air to the fuel stream, the
devolatilization of the coal particles takes place in an oxygen
deficient environment, preventing the fuel-bound nitrogen from
combining with oxygen to form NOX. (See Docket Item IV-J-2.) This
staging process also reduces peak combustion temperatures, thereby
reducing thermal NOX as well; however, the primary reduction is in
fuel NOX. An ideal low NOX combustion process would
incrementally add oxygen to the coal stream in small, continuous
stages; this ideal is impractical in full scale applications due to
limitations in furnace sizes and the need to rapidly transform the
fuel's chemical energy to heat.
Staging can be achieved in coal-fired boilers by several methods. A
technique known as ``burners out of service'' (BOOS) was an early
implementation of staging in wall-fired boilers where the feed system
discontinued the flow of coal to one or more of the burners in the
upper burner row, but retained the flow of air through those burners. A
fuel-rich zone was produced in the lower furnace volume, with the air
added through the ``out of service'' burners being sufficient to
complete the combustion process with reduced emissions of NOX.
However, the use of BOOS usually required the boiler to operate below
its rated load. (See Docket Item IV-A-4.) The next development was to
install dedicated air injection ports above the top row of burners to
provide the additional air and allow the boiler to maintain its rated
load. This implementation of staging was termed ``overfire air'' (OFA),
and it remains a primary technique for achieving the staged combustion,
which is the key to low NOX coal combustion. This technique has
also been referred to as ``staged air combustion'' or ``external
staging''; the ports through which the staging air is introduced have
been referred to as ``overfire air ports,'' ``NOX ports,''
``staging ports,'' or ``additional air ports.'' (See Docket Items IV-A-
1, IV-A-2, IV-A-4, and IV-A-6.)
Staged combustion in the form of OFA was initially applied to
reduce NOX from oil and gas combustion in the early 1960's,
followed by application to coal-fired boilers in the 1970's. (See
Docket Items IV-A-4 and IV-J-14.) The next step in the development of
low NOX combustion systems was the modification of individual
burners to alter the air and fuel flows in such a way that the same
staged combustion principles used by OFA were achieved within the
individual burner flames. (See Docket Item IV-A-4.) The modified
burners reduced the mixing rate of the fuel and air to delay the
combustion process and/or separated the air and fuel flows inside the
burner so their subsequent combination could occur in a staged manner
external to the burner. Both of these approaches relied on the staged
combustion principles previously demonstrated by OFA; these modified
burner assemblies were known as ``low NOX'' burners. Low NOX
combustion developments have continued, emphasizing both NOX
reduction and operating flexibility. To maximize the NOX reduction
performance of a specific boiler, OFA is often employed in combination
with low NOX burners to optimize the air staging principle in
``real world'' applications. These combinations reflect the fact that
overfire air is in essence a continuation of the staging process begun
in the burner itself and that the combined use of staging methods is a
means of approaching the ideal, continuous staged combustion process.
To eliminate overfire air from the definition of low NOX
burner technology is to ignore the fundamental physical and chemical
process of low NOX combustion, which acts to prevent the formation
of NOX. The staged combustion process is the basis of design for
both low NOX burners and overfire air and is the key principle in
defining low NOX burner technology. With this perspective one
cannot reasonably classify overfire air as an alternative control
technology. Low NOX burner technology prevents the formation of
NOX; the available alternative technologies of SNCR, SCR, and
reburning destroy NOX after it is formed. Therefore, based on the
combustion chemistry, EPA believes it would be arbitrary and illogical
to artificially exclude the use of overfire air which is an integral
part of the combustion staging process designed to minimize NOX
emissions. The most accurate and technically sound interpretation of
the combustion process is therefore given by Option 1. And thus, it
follows that ``conventional available burner technology'' does include
the low NOX burner technology contemplated under Option 1.
Review of technical literature. In determining whether low NOX
burner technology included overfire air, EPA also reviewed the
technical literature discussing utility applications of low NOX
combustion equipment. The purpose of this review was to determine a
reasonable technical meaning of ``low NOX burner technology'' as
used by those involved in the development and application of low
NOX combustion equipment prior to the controversy that arose
during the development of the proposed rule.
The key finding of this review was that vendors, utilities, and
research organizations alike frequently referred to low NOX
combustion equipment, not as individual items, but as integrated
systems. Repeated references to ``burner systems'' or ``combustion
systems'' were found, with the ``systems'' in question including not
only the discrete burner assemblies but also separated overfire air
injection and often related items such as coal and air piping, fans,
controls, and coal pulverizing equipment. (See Docket Items IV-J-3, IV-
J-8, IV-J-9, and IV-J-11.) By integrating all these and other related
systems to create a combustion system that is as efficient as possible,
actual design practice blurs the ability to distinguish between
different components of burner technology. References to ``externally
staged burner concepts'' and to ``integral NOX ports'' as part of
a burner assembly can even support a view that overfire air is not only
an integral component, but can be considered as part of the burner
itself. (See Docket Items IV-J-7 and IV-J-14.)
More common, however, is the approach of considering burner nozzles
and air ports as integral components of a complete combustion system
and not as separate technologies, as indicated by the following
examples:
(1) A retrofit burner system for wall-fired boilers was designed
``to employ a technique for separating the fuel and air streams in the
primary combustion zone. The complete systems also incorporate the
standard OFA configuration.'' (See Docket Item IV-J-18.)
(2) A discussion of a low NOX burner retrofit project for
tangentially-fired boilers noted, ``the PM firing system included new
windboxes with integral (`close coupled') OFA ports, [and] separate
compartments for additional (`separated') OFA. . . .'' (See Docket Item
IV-J-9.)
(3) The Electric Power Research Institute (EPRI) recently assembled
a document to provide guidance to utilities as they planned their
response to the requirements of the Act. In this document, they listed
the combustion controls available for meeting the NOX reduction
requirements as: overfire air; low NOX burners with OFA; and
slagging combustors. (See Docket Item IV-J-13.) The only caveat
associated with this list was that OFA may not be feasible for boilers
equipped with cell burners.
(4) A respected utility industry reference, discussing the location
of OFA ports, noted that, ``In some applications, ports are placed
beneath or within the burner zone'' (see Docket Item IV-J-14); and
(5) The integral nature of overfire air in low NOX combustion
systems is particularly true for tangentially fired boilers, for which
the primary question is where, not whether, the overfire air is to be
injected. (See Docket Item IV-J-10.)
This view of an integrated system design is not new. During the
late 1970's and early 1980's, one of the major low NOX combustion
development efforts was sponsored by EPA's Fundamental Combustion
Research Program, which led to the construction and testing of the
Distributed Mixing Burner (DMB). [See Docket Items IV-J-19 and IV-J-
12.] The DMB, developed for retrofit to wall-fired boilers, had as part
of its basic design a series of ``tertiary air ports'' that were
separated from the burner. Advances in the state of the art in burner
system design achieved during the development program were applied to
commercial systems offered by a number of vendors. These advances often
employed the integrated system approach of low NOX burners with
overfire air.
For example, one manufacturer noted in 1982, when discussing two
low NOX combustion systems, that ``Overfire air has been retained
as an integral part of both systems.'' (See Docket Item IV-J-3.)
Another vendor noted during the same period that their design
philosophy was to use ``no more than 20 percent overfire air.'' (See
Docket Item IV-J-4.) Overfire air or staging played a significant role
in other vendors' research programs, leading to developments of ``a
burner with an integrated air port for staged combustion'' and a burner
``designed for two stage combustion'' with staging air being ``provided
through the overfire and underfire air systems.'' (See Docket Items IV-
J-5 and IV-J- 6.) Numerous other citations of a similar nature show the
integral nature of overfire air as part of low NOX burner
technology. [See Docket Item IV-J-15.]
Thus, contrary to the assertions of some commenters, for at least
fifteen years prior to enactment of the 1990 CAAA, the ``common
understanding'' of the term low NOX burner technology has not been
the limited definition of burners alone, but the broader view that
fully incorporates separated overfire air. This is not to say that many
references to burners alone or overfire air alone do not exist; such
references are numerous. However, comments that imply a clear
engineering definition of low NOX burner technology that excludes
any and all forms of overfire air exists, and has always existed, are
not supported by the technical literature. Indeed, a definition that
artificially restricts low NOX burner technology is not based on a
reasoned technical understanding of low NOX combustion equipment
and does not accurately reflect the integrated nature of the
technology. For nearly twenty years, the correct engineering view has
incorporated both low NOX burners and separated overfire air as
elements of low NOX burner technology for both wall-fired and
tangentially fired boilers, contrary to the definition of Option 2 or
to definitions proposed by commenters. Option 1 is, therefore, the only
approach consistent with the technical usage of the term ``low NOX
burner technology.''
Congressional intent. The EPA also finds the Option 1 definition of
low NOX burner technology consistent with the performance levels
that section 407 seeks to achieve. By specifying emission limitations
no greater than 0.45 lb/mmBtu for tangentially fired boilers and 0.50
lb/mmBtu for wall-fired boilers, Congress indicated its intent that
utilities apply ``low NOX burner technology'' capable of achieving
these emission levels. While the Act's provision for AELs provides for
instances in which units are physically unable to meet those limits, it
is EPA's position that Congress intended for the emission limits set
forth in section 407(b) to be met by as many units as reasonably
possible and for the average emissions of the boiler population to
achieve the stated levels.
Certainly, inclusion of these performance standards indicates that
Congress did not intend for this program to take an approach that
specifies particular control equipment, as opposed to an approach that
allows use of a NOX control technology (and whatever equipment may
be involved), based on the physical and chemical process of low
NOX combustion, that modifies the combustion process by staging
combustion, whether within or outside the burner itself. Under an
approach that restricts low NOX burner technology for wall-fired
units to low NOX burner systems with combustion air staging
through the burner assembly only (or indeed one that mandates low
NOX burner systems incorporating overfire air for all units), the
equipment standard is controlling for many units and the performance
levels stated in section 407(b) become irrelevant. There is no question
that a significant number of wall-fired units will be able to achieve
the performance level set forth under the Act by using low NOX
burner systems with combustion air staging through the burner assembly
only. However, a definition of low NOX burner technology as
burners alone effectively removes the standard of performance from
those units that emit at higher rates and that can achieve the
performance standards only if they use overfire air. As noted,
elimination of overfire air from the definition of low NOX burner
technology would enable many utilities to obtain AELs and emit at
levels higher than the applicable emission limitation without
considering the full range of low NOX combustion techniques. Only
by including the most effective level of low NOX burner technology
that being low NOX burner systems incorporating overfire air will
the performance standard apply to the largest possible number of units.
Under the ``burners only'' approach, the performance standards and the
concomitant environmental benefits would be preempted for many units by
a mandate for installation of specific equipment regardless of its
performance. The Agency believes that it should adopt an approach that
both maximizes the applicability of the performance standards and
implements the combustion modification technology standard (i.e., low
NOX burner technology) in section 407 of the Act.
The EPA believes that a reasoned interpretation of the Act is one
that focuses on the limits listed in the statute for most units,
reserving the requirement of installing the best performing low
NOX burner technology to those circumstances where a utility seeks
permission for an AEL to allow an affected unit to emit at a rate
higher than the applicable emission limitation. It must be emphasized
that the inclusion of the various forms of overfire air in the
definition of low NOX burner technology does not require the
application of overfire air in all cases. Although such a requirement
has been implied by some commenters who oppose the inclusion of
overfire air in the definition, the actual application of overfire air
will remain the decision of each utility based on its evaluations of
the control systems offered by the different vendors. Only in cases in
which a unit is unable to meet the applicable emission limitation,
elects not to participate in an emissions averaging pool and seeks to
operate under an AEL, will overfire air be required. In these
instances, it is consistent with Congressional intent that the utility
make a reasonable effort to achieve the applicable emission limitation
set forth in section 407(b) by installing the most effective combustion
modification control technology, which is low NOX burner systems
incorporating overfire air.
Further, Congress made no distinction between low NOX burner
technology for wall-fired units and tangentially fired units,
indicating Congress intended a single definition to apply to both types
of units. Since the adoption of Option 2 would result in the
classification of overfire air as low NOX burner technology for
tangentially fired units, and as an alternative technology for wall
fired units, in contradiction to Congressional intent, Option 2 is not
appropriate. The only definition of low NOX burner technology
under which most units can meet the standards of performance in a
flexible manner and that maintains a consistent distinction between low
NOX burner technology and alternative technologies for both boiler
types is Option 1. The Agency therefore concludes that Option 1 is
fully consistent with Congressional intent.
Current and planned applications of low NOX burner technology.
Finally, the actual practices of the industry demonstrate that overfire
air is common and available low NOX burner technology. For wall-
fired units, 32 percent of all retrofit burner installations now in
progress or planned by 1995, as reported by two of the three major U.S.
burner vendors, incorporate overfire air as a part of their designs.
Including new units, 43 percent of all burner installations from these
two vendors incorporate overfire air. Far from being unconventional,
overfire air is viewed as a widely available NOX reduction
technology and is currently being installed by many utilities.
For tangentially fired boilers, the reported results provide
further support for EPA's final position. Today, there is no
commercially available low NOX burner technology for tangentially
fired boilers that does not incorporate combustion air staging through
the application of overfire air to achieve the performance
standards.\1\ Furthermore, over 65 percent of all Phase I units that
have reported actual or planned installations of low NOX burner
technology in tangentially fired boilers have chosen to install systems
that use separated overfire air. It is difficult to see how one could
claim that the community of plant operators considers the use of
overfire air to be experimental or unconventional. It is clear that
those who have the responsibility for meeting the performance standards
and who are intimately familiar with the practical aspects of
combustion technology, the community of boiler operators, have made the
technical decision that overfire air is an integral part of low
NOX burner technology for both wall-fired and tangentially fired
boilers. The adoption of Option 1 fully reflects this technical
reality. This is further supported and is an outgrowth of the vendor
community's offerings. All of today's major vendors include overfire
air in their suite of low NOX burner technology offerings. The
extent of its use being determined by the needs of the unit in question
on a case-by-case basis.
---------------------------------------------------------------------------
\1\It should be noted that there have been very recent
installations of discrete low NOX burner assemblies in
tangentially fired boilers, and further developmental work is being
conducted toward this end. However, to date these installations have
eventually incorporated at least some degree of overfire air in
order to meet the 0.45 lb/mmBtu limit.
---------------------------------------------------------------------------
Conclusion. The conclusion that EPA draws from the foregoing
analysis is that the most reasonable and accurate definition of
conventional, available low NOX burner technology includes
overfire air as an integral component. The definition proposed by many
industry commenters that low NOX burner technology does not
include overfire air is artificial and is not based on the fundamental
mechanisms of low NOX combustion, the accepted technical view of
low NOX burner systems, Congressional intent, or the actual use of
NOX reduction systems being installed for title IV compliance. The
purpose of section 407 of the Act is the reduction of NOX
emissions to an average level set forth by Congress, and the most
reasonable approach to achieving these reductions is through the
flexible application of appropriate low NOX burner technology. The
approach taken by EPA in implementing the Congressional intent of these
NOX emission reductions has been to encourage a cost effective and
judicious application of the level of low NOX burner technology
required to achieve the stated average annual emission levels. Neither
low NOX burners nor overfire air are required to be installed on
all units or on any particular unit. Consistent with the intent of
section 407 of the Act, the decision as to what level of control
technology to install on any particular unit is left completely to the
utility, based on the specific financial and operational needs of that
utility. A reasonable and responsible utility will employ the full
range of conventional and available low NOX burner technology
components, including separated overfire air, in its response to the
performance requirements set forth by Congress prior to applying for an
exception to emit at a higher emission level. A unit that is unable to
meet the applicable emission limitation using low NOX burner
systems with air staging through the burner assembly only has several
compliance options: (1) Install a more effective NOX control
technology (e.g., selective catalytic reduction) and meet the
applicable limit; (2) install separated overfire air and apply for an
AEL if the limit still cannot be met; or (3) to the extent it meets the
requirements for averaging, participate in an averaging pool.
The definition of low NOX burner technology as the low
NOX burners incorporating separated overfire air is a sound,
logical, and reasonable approach based on the fundamental science,
technical history, Congressional intent, and the actual use of NOX
reduction systems. Furthermore, EPA maintains that the language in
section 407(d) of the Act supports this approach. Congress stated that
an AEL shall be established upon a determination that ``a unit subject
to subsection (b)(1) cannot meet the applicable emission limitation
using low NOX burner technology. . .'' and units ``shall not be
required to install any additional control technology beyond low
NOX burners'' 42 U.S.C. 7651f(d)(1). Considering that
conventionally available low NOX burner technology incorporates
the use of overfire air and that some of the actual applications of
``burners'' also incorporate overfire air, reading ``low NOX
burner technology'' (and ``low NOX burners'') to include overfire
air is reasonable and consistent with Congressional intent.
2. Performance of Low NOX Burner Technology
Section 407(b)(1) of the Act identifies maximum emission
limitations for Phase I units with Group 1 boilers, that Congress
considered achievable using low NOX burner technology. The EPA
believes Congress intended that a majority of Phase I units with each
type of Group 1 boiler be capable of complying with their applicable
emission limitation on an annual average basis using low NOX
burner technology. Accordingly, EPA was required to evaluate the
performance of all commercially available low NOX combustion
controls that could be encompassed by the term ``low NOX burner
technology'' to determine whether the maximum emission limitations
listed in the statute are indeed appropriate to promulgate. The EPA was
also required to assess the controls or combinations of controls
capable of achieving the final emission limitations being promulgated
today in order to establish eligibility criteria for ``appropriate
control equipment designed to meet the applicable emission limitation''
in the AEL application process.
Comment: The EPA received 15 comments on the performance of low
NOX burner technology applied to Phase I units with Group 1
boilers. These comments focused primarily, but not exclusively, on two
major issues: (1) Whether EPA's assumptions on the performance (i.e.,
percent NOX emission reduction) of various controls that could be
within the definition of ``low NOX burner technology'' are sound;
and (2) under which definition(s) of low NOX burner technology
would a majority of Phase I units be capable of complying with the
applicable emission limitation using controls encompassed by the
definition. Many commenters believe that EPA underestimated the
performance of low NOX burner systems with air staging through the
burner assembly only on wall-fired boilers; some provided new and/or
revised data illustrating NOX reduction levels associated with
these systems. These commenters also believe EPA underestimated the
performance of low NOX coal and air nozzles with close-coupled
overfire air applied to tangentially fired boilers. As a result, they
believe that a majority of Phase I units with Group 1 boilers can
achieve the target emission limitations listed in the statute by
applying these controls only and, thus, it is unnecessary to extend the
definition of low NOX burner technology to other (more effective)
combustion controls.
Another commenter affirms EPA's assumptions on the performance of
various controls that could be within the definition of low NOX
burner technology as applied to both wall-fired and tangentially fired
boilers. The commenter also provides, as examples, emissions data from
recent low NOX burner technology retrofits, but emphasizes the
wide variation in expected performance of low NOX burner
technology for both wall-fired and tangentially fired boilers.
Another commenter generally supported EPA's assumptions on the
performance of various controls plausibly within the definition of low
NOX burner technology, but disagreed with EPA's conclusion that
the emission limitations listed in the statute are appropriate to
promulgate as the performance standards for Phase I units with Group 1
boilers. This commenter believes that more stringent performance
standards can be supported by low NOX burner technology,
particularly given the compliance flexibility afforded by emissions
averaging and the AEL provisions.
Response: In response to the commenters' concerns, EPA reevaluated
performance ranges for wall- and tangentially fired boilers cited in
the analysis for the proposed rule.
Wall-fired boilers. The technical analysis for EPA's proposed rule
contained the anticipated performance ranges for two commercially
available retrofit NOX emission combustion controls applied to
wall-fired boilers:
(1) 35 to 40 percent emission reduction for low NOX burners
without overfire air; and
(2) 50 to 60 percent emission reduction for low NOX burners
with overfire air.
These ranges reflect NOX reductions that had been achieved in
commercial applications and demonstrations on full-scale utility
boilers under normal operating conditions. The underlying data for
these performance ranges showed highly variable performance across
applications.
Many new commercial retrofits of low NOX burner technology
have occurred subsequent to the proposed rule; and some have published
or given EPA post-retrofit emission data. The EPA has compiled a
database of 20 wall-fired boilers applying low NOX burners without
overfire air and 7 wall-fired boilers applying low NOX burners
with overfire air (Table 1). This database consists of all NOX
emission reduction data used for the proposed rule, data supplied by
commenters on the proposed rule, data listed in recently published
papers, data issued publicly at technical conferences, and data EPA
obtained by contacting utilities that had recently retrofit low
NOX burner technology on wall-fired boilers. Multiple sources of
data existed for some applications and, in certain instances, the
reported post-retrofit emission data varied by source. In these
instances, EPA evaluated the reliability of each source, and where
sources were determined to be equally reliable, EPA selected the most
recent data. As discussed below, EPA grouped these data into different
subsets according to type of coal (bituminous vs. subbituminous),
geographic source of coal (East vs. West), measurement period (short-
term vs. long-term data), uncontrolled NOX emission rate, boiler
size, and NOX control technology vendor, and analyzed performance
variability within each subset. (See Docket Item IV-A-10.)
Table 1.--LNBT Retrofits on Wall-Fired Boilers
----------------------------------------------------------------------------------------------------------------
Average
Combustion NOX emission
Plant and unit Utility control\1\ reduction
(percent)
----------------------------------------------------------------------------------------------------------------
Campbell Unit 3......................... Consumers Power........................ LNB 27
Cherokee Unit 3......................... Pub. Service Colorado.................. LNB 33
Colbert Unit 3.......................... TVA.................................... LNB 31
Cottam Unit 4........................... UK Utility............................. LNB 38
Drax Unit 6............................. UK Utility............................. LNB 51
Duck Creek Unit 1....................... Central Ill. Lt. Co.................... LNB 50
Edgewater Unit 4........................ Ohio Edison............................ LNB 41
Eggborough Unit 2....................... UK Utility............................. LNB 43
Four Corners Unit 3..................... Arizona Public Service................. LNB 51
Gaston Unit 2........................... Alabama Power.......................... LNB 50
Hammond Unit 4.......................... Georgia Power.......................... LNB 48
Harrison Unit 3......................... Monongahela Power Co................... LNB 50
Homer City Unit 2....................... Pennsylvania Electric.................. LNB 65
Hsin-Ta Unit 1.......................... Taiwan Utility......................... LNB 68
Johnsonville Unit 8..................... TVA.................................... LNB 48
N. Simpson Unit 5....................... Black Hills Pwr. & Lt.................. LNB 58
Pleasants Unit 2........................ Monongahela Power Co................... LNB 59
Quindaro St. Unit 2\2\.................. KS Bd. Pub. Utilities.................. LNB --
Ratcliffe Unit 2........................ UK Utility............................. LNB 35
Wabash Unit 5........................... PSI Energy Inc......................... LNB 21
Hsin-Ta Unit 1.......................... Taiwan Utility......................... LNB + OFA 80
Hammond Unit 4.......................... Georgia Power.......................... LNB + OFA 62
Gibson Unit 3........................... PSI Energy............................. LNB + OFA 37
Howard Down Unit 10..................... City of Vineland....................... LNB + OFA 65
Pleasants Unit 2........................ Monongahela Power Co................... LNB + OFA 68
San Juan Unit 1......................... NM Public Service...................... LNB + OFA 65
Wabash Unit 2........................... PSI Energy Inc......................... LNB + OFA 58
----------------------------------------------------------------------------------------------------------------
\1\LNB = Low NOX burners without overfire air; AOFA = Advanced overfire air; OFA = Overfire air.
\2\Only controlled NOX emission rates available.
Similar to the pre-proposal data, a wide variation exists, ranging
from 27 to 68 percent, in the average performance of low NOX
burners without overfire air. An equally wide variation exists, ranging
from 37 to 80 percent, in the average performance of low NOX
burners with overfire air.
In efforts to explain this wide variation in average performance,
the data were grouped into subsets according to coal characteristics
and period of measurement (i.e., short-term vs. long-term). The results
from averaging performance parameters within each subset show a small
variation from subset to subset but, overall, suggests that for these
applications, grouping the data by coal type, geographic region or
measurement period does not explain the variability in performance of
low NOX burner technology observed across the database.
Since the data did not correlate well with the physical conditions,
all data were regrouped and compared against boiler-specific
parameters. Boiler-specific parameters considered were uncontrolled
NOX emission rate, boiler size, and NOX control technology
vendor. The resulting comparisons showed no dependency of performance
with boiler size or technology vendor. However, for retrofit non-OFA,
low NOX burner applications a strong correlation between NOX
removal performance and the uncontrolled NOX emission rate was
observed. For dry bottom wall-fired boilers retrofitting low NOX
burners with OFA, there was an insufficient amount of data to determine
a correlation. However, since low NOX burners incorporating OFA
systems essentially extend the combustion staging process incrementally
beyond those using low NOX burners without OFA, it was assumed
that a similar correlation exists, but at incrementally greater levels
than the correlation developed for low NOX burners. This
correlation's lower boundary was set at an uncontrolled emission rate
of 0.95 lb/mmBtu since the database did not contain data for low
NOX burner with OFA retrofits on boilers with a lower uncontrolled
emission rate.
The correlation developed for non-OFA low NO