Federal Register, Volume 59 Issue 55 (Tuesday, March 22, 1994)

[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 NOX burner
applications accurately represents all the assembled data. According to
the correlations developed, performance of non-OFA low NOX burners
can range from 30 percent at an uncontrolled emission rate of 0.55 lb/
mmBtu to 60 percent at an uncontrolled emission rate of 1.35 lb/mmBtu,
with the majority of affected boilers expected to achieve NOX
reductions in the range of 40 percent to 50 percent, while performance
of low NOX burners with OFA can range from 60 percent at an
uncontrolled emission rate of 0.95 lb/mmBtu to 75 percent at an
uncontrolled emission rate of 1.35 lb/mmBtu. The correlations show that
systems with OFA have a 9 percent to 13 percent incremental increase in
NOX reductions over systems without OFA (e.g., if a boiler
achieves a 40 percent reduction with low NOX burners, the expected
reduction when adding OFA would range from 49 percent to 53 percent).
The correlations also suggest that boilers with an uncontrolled
emission rate higher than 1.0 lb/mmBtu will not meet the presumptive
limit using low NOX burners without OFA, and that most boilers
retrofitting low NOX burners with OFA can meet the presumptive
limit regardless of uncontrolled emission rate.
Based on the analysis of all available data (see Docket Item IV-A-
10), EPA believes that the promulgated emission limitations can be
achieved by the majority of individual units and the entire class of
boilers on average. Additionally, EPA's Regulatory Impact Analysis
shows that a significant number of wall-fired boilers (58 percent in
Phase I and 43 percent in Phase II) and almost all tangentially fired
boilers (90 percent in Phase I and 86 percent in Phase II) cannot meet
the emission limitations without OFA. However, when close-coupled
overfire air (LNC 1) is included, the number of units that cannot meet
the emission limitation drops significantly to 74 percent (Phase I) and
67 percent (Phase II).
Tangentially fired boilers. The EPA's proposed rule presented
performance retrofit ranges for three types of commercially available
retrofit NOX emission combustion control systems as applied to
tangentially fired boilers (all of which include some degree of
overfire air):
(1) Low NOX coal and air nozzles with close-coupled OFA (LNC
1) with an anticipated 25 percent removal efficiency;
(2) Low NOX coal and air nozzles with separated OFA (LNC 2)
with anticipated 35 percent removal efficiency; and
(3) Low NOX coal and air nozzles with close-coupled and
separated OFA (LNC 3) with an anticipated 45 to 55 percent removal
efficiency.
Commercial applications of retrofit NOX controls as applied to
tangentially fired boilers were limited to a relatively few
installations at the time of the proposed rule was published.
Furthermore, all of the applications were made at facilities where
uncontrolled NOX emission levels are relatively low. The span of
uncontrolled emission rates covered by data from these installations
was not sufficient to support development of a correlation with
performance level as was done for low NOX burners on dry bottom
wall-fired boilers. In view of this lack of data and considering the
expectations that performance would be higher at higher levels of
uncontrolled NOX emissions, EPA included reviews of projections by
manufacturers, utilities, and utility research groups in the
development of the above NOX control performance estimates.
More information is now available since proposal of the rule,
concerning commercial retrofits of tangentially fired boilers with
combustion NOX controls, but the information is still limited when
compared to that concerning wall fired boiler low NOX burner
retrofits. The EPA assembled a database of four LNC 3 applications,
nine LNC 2 applications, two LNC 1 applications, and two LNC 1
applications that were not typical and, as such, designated LNC 1+.
These data are shown in Table 2. The EPA was not able to identify any
performance data from commercially available low NOX burner
combustion technology used on tangentially fired boilers that does not
include the use of overfire air.

Table 2.--LNBT Retrofits on Tangentially Fired Boilers
----------------------------------------------------------------------------------------------------------------
Average
Combustion NOX emission
Plant and unit Utility control\1\ reduction
(percent)
----------------------------------------------------------------------------------------------------------------
Gallatin Unit 4......................... TVA.................................... LNC 1 8
Hunter Unit 2........................... Utah Power and Light................... LNC 1 31
Fiddlers Ferry Unit 1................... UK Utility............................. LNC 1+ 38
Smith Unit 2............................ Gulf Power............................. LNC 1+ 37
Bowen Unit 4............................ Georgia Power.......................... LNC 2 31
Cherokee Unit 4......................... Pub. Service Colorado.................. LNC 2 37
Eastlake Unit 2......................... Cleveland Elec. Illum.................. LNC 2 33
Kingsnorth Unit 2....................... UK Utility............................. LNC 2 21
Smith Unit 2............................ Gulf Power............................. LNC 2 32
Valmont Unit 5.......................... Pub. Service Colorado.................. LNC 2 35
Vermillion Unit 2....................... Illinois Power......................... LNC 2 29
Wansley Unit 1.......................... Georgia Power.......................... LNC 2 30
Yates Unit 6............................ Georgia Power.......................... LNC 2 32
Brown Unit 3............................ Kentucky Utilities..................... LNC 3 30
Fucina Unit 2........................... Italian Utility........................ LNC 3 52
Labadie Unit 4.......................... Union Electric Co...................... LNC 3 40
Smith Unit 2............................ Gulf Power............................. LNC 3 40
----------------------------------------------------------------------------------------------------------------
\1\LNC 1 = low NOX coal and air nozzles with close-coupled OFA; LNC 1+ = modified LNC 1 system; LNC 2 = low NOX
coal and air nozzles with separated OFA; LNC 3 = low NOX coal and air nozzles with close-coupled and separated
OFA.

The LNC 1+ applications were Fiddler's Ferry Unit 1 and Lansing
Smith Unit 2. The windbox for Fiddler's Ferry Unit 1 required waterwall
modifications and extends above the top burner level far enough to
enhance NOX emission reduction performance but not far enough to
be considered a system employing LNC 2. For Lansing Smith Unit 2, air
leakage from the separated OFA ports during testing enhanced NOX
reduction performance, and the air velocity through the close-coupled
OFA ports was uncommonly high resulting in atypical performance. [See
Docket Item II-I-96.]
As with the dry bottom wall-fired boilers, the tangentially fired
boilers were grouped into subsets according to coal characteristics and
measurement period. However, the resulting subsets were too small to
provide meaningful results. Correlations could not be determined given
the limited amount of data. However, a comparison of percent emission
reduction and controlled NOX emission rate with uncontrolled
NOX emission rate for the nine LNC 2 applications indicated a
constant emission reduction of approximately 31 percent. Assuming the
effectiveness of LNC 2 at 31 percent, the incremental change for the
other two control systems was determined to be 6 percent lower for LNC
1 and 9 percent higher for LNC 3 resulting in performances of 25 and 40
percent, respectively. The method of determining performance of LNC 1
and 3 by comparing their results to that of LNC 2 was considered more
accurate than determining a straight average for each control system,
because of the relatively higher confidence in the LNC 2 results.
The resulting performance estimates were not entirely satisfying
because: (1) The boilers used in this analysis had low uncontrolled
NOX emissions thereby requiring only minimal NOX reductions,
and (2) the manufacturers of these control systems predict consistently
higher NOX removal. The removals are based on short-term testing
of the retrofit control systems for the purpose of establishing a
guaranteed maximum NOX emission level for each boiler.
In order to more accurately represent what each NOX control
system could achieve, a range of performance for each system was
established. For LNC 2 and 3, the ranges have, as a lower bound, the
performance averages determined from the above analysis and, as an
upper bound, the performance averages projected by the manufacturer for
each NOX control system. For LNC 1, since the manufacturer
projects an average NOX removal efficiency lower than the
performance determined by the above analysis, the manufacturer's
estimate was used as the lower bound and the analysis average was used
as the upper bound. The approach yields the following ranges of
performance:
LNC 1: 20--25
LNC 2: 30--40
LNC 3: 40--50
The EPA believes that these ranges bracket the likely performance
that these NOX control systems will achieve once applied to a
representative sampling of tangentially fired units.
Comment: During the combustion of coal in a utility boiler, a
percentage of coal is not combusted and exits the boiler as part of the
flyash. This percentage of uncombusted coal is referred to as unburned
carbon (UBC) or, in some cases, as loss on ignition (LOI) and indicates
the percentage of combustible carbon present in the flyash. UBC is
undesirable because it is fuel that is not used and, as such, reflects
as a loss in boiler efficiency. Also, if a utility sells a portion of
its flyash to cement product companies, a maximum UBC level is
typically specified, above which level the flyash is unacceptable. This
level (usually 5 percent UBC) is set because the presence of carbon
will darken light-colored concrete without contributing to its
strength. Several commenters have expressed concern that the addition
of OFA on dry bottom wall-fired boilers or the addition of separated
OFA on tangentially fired boilers will significantly increase post-
retrofit UBC levels and affect both boiler efficiency and flyash
salability.
Response: As discussed below, EPA reviewed the relationship of UBC
to boiler efficiency and to flyash sales.
UBC and boiler efficiency. The EPA conducted a review of all recent
literature containing information on UBC and LOI levels in coal-fired
utility boiler flyash. (See Docket Item IV-A-10.) Pre- and post-
retrofit UBC data were assembled for seven U.S. coal-fired utility
boilers. Of the seven boilers, four were dry bottom wall-fired and
three were tangentially fired. All four dry bottom wall-fired boilers
retrofitted low NOX burners, one of which included OFA. All three
tangentially fired boilers retrofitted low NOX coal and air
nozzles with separated OFA, while one also retrofitted close-coupled
overfire air.
After the retrofitting of low NOX burners without OFA on the
dry bottom wall-fired boilers, the average increase in UBC levels was
85 percent. The dry bottom wall-fired boiler that added OFA, initially
had an incremental increase in UBC levels of 37 percent, resulting in a
115 percent increase in UBC from pre-retrofit levels. However, after a
period of six months, UBC levels dropped to those experienced without
overfire air at the same time NOX emission reduction ranged from
55 to 62 percent. During this period there were no reported major
modifications in equipment that would impact the boiler's UBC levelor
NOX performance. (See Docket Item IV-J-17.) This case suggests
that over time, as utility operators train and familiarize themselves
with the new equipment, overall boiler performance is improved. The
above results are consistent with a leading manufacturer's estimates
that UBC levels will increase by 100 percent over baseline values when
retrofitting low NOX burners without OFA. However, results are not
consistent with the manufacturer's estimate of 150 percent (25 percent
incremental increase in UBC levels when adding OFA to low NOX
burners) increase in UBC levels when retrofitting low NOX burners
with OFA.
Considering the limited amount of data and the difficulty of
entering a human factor (operator improvement over time) into the UBC
analysis, EPA decided to assign a 25 percent incremental increase in
UBC levels when OFA is included, based on the manufacturer's estimates.
(See Docket Item IV-A-10.) This results in an increase in UBC levels of
125 percent over baseline values when incorporating OFA. For the
tangentially fired boiler that retrofitted LNC 1, the UBC level
increased 6 percent from baseline values. One boiler initially
retrofitted LNC 3 and experienced an incremental increase in UBC levels
of 41 percent from pre-retrofit levels. After a six month period the
same boiler sealed (unsuccessfully) the separated OFA ports, attempting
to simulate LNC 1 and decreased the UBC levels from 41 percent to 6
percent over baseline measurements. It is unknown how much technology
versus operator training contributed to this improvement in UBC.
In summary, in the case of LNBT applied to dry bottom wall-fired
boilers, the results show that there is a significant increase in UBC
levels when applying low NOX burners, and a smaller incremental
increase when adding OFA. This increase in UBC levels results in a
decrease in boiler efficiency by an average of 0.27 percent for non-OFA
low NOX burner retrofits, and of 0.43 percent for low NOX
burners including OFA retrofits.
For tangentially fired boilers, the largest data set (LNC 2 UBC
data on three boilers) shows a 9 percent decrease in UBC levels when
retrofitting a boiler with NOX controls, and thus a slight
increase in boiler efficiency. A definitive impact on UBC levels
resulting from LNC 1 could not be determined with the available data.
However, changes in UBC levels are expected to be negligible. For the
installation of LNC 3 on one boiler, UBC levels increased, resulting in
a decrease in boiler efficiency of 0.17 percent. These results appear
to be consistent with a major NOX control manufacturer's estimates
and measurements. (See Docket Item IV-J-18.)
In conclusion, EPA acknowledges that there is an increase in UBC
for dry bottom wall-fired boilers applying LNBT and this results in a
slight reduction in boiler efficiency. This decrease in boiler
efficiency is too small to significantly affect any aspect of plant
operations or electric grid system reliability. However, it results in
an additional annual cost associated with the retrofit of LNBT and, as
such, has been simulated in the Regulatory Impact Analysis. Results of
this analysis are included in section III.A.3 of this preamble entitled
``Cost of Low NOX Burner Technology.'' For tangentially fired
boilers, the available information though limited, suggests that UBC
levels after retrofit of all three control systems remain unchanged on
average. The early indication is that with additional operator
experience with LNC 2 retrofits, a slight improvement in efficiency may
be gained. Thus, the concern expressed by some commenters that the
inclusion of OFA in a low NOX burner retrofit could have a
significant adverse effect on UBC is not supported by the retrofit
data. The addition of OFA on the wall-fired unit resulted in a
negligible increase in UBC while on the tangentially fired units the
addition of OFA appeared to have a slight beneficial effect.
UBC and flyash sales. Approximately two-thirds of all coal-fired
plants sell or use a portion of their flyash and bottom ash, although
an EPA study identified over a dozen institutional barriers that affect
utility boiler ash usage. Although flyash quality and consistency are
two of these factors, many other factors are important, such as
transportation costs, competition from traditional material sources,
demand for by-product, utility marketing experience, by-product
industry and by-product end user acceptance, and contractual
environmental considerations. (See Docket Item IV-A-10.) Though a
significant portion of the utility flyash sold is used by concrete and
cement product companies, other flyash applications include use as road
base material or structural fill, and in building products. Overall,
only 19 percent of the flyash produced by utilities in 1989 was used.
Of the flyash that was used, a fifth was used internally by utilities,
as structural fill road based material, and the remainder was sold to
external sources. A significant part of the external sources are the
concrete and cement producers, and since they usually specify an
acceptable UBC in the flyash level of 5 percent, in some instances
increases in UBC levels can affect the salability of flyash. There are,
however, some corrective measures that a utility facing such a problem
can take, such as improving coal fineness, operating at higher excess
oxygen levels or fine tuning its LNBT equipment.
The EPA's UBC study shows that tangentially fired boilers
installing LNBT with baseline UBC levels below 5 percent are unlikely
to increase their UBC levels to above 5 percent. For dry bottom wall-
fired boilers that sell flyash that must have an UBC level lower than 5
percent, it is likely that level will increase above 5 percent when
installing low NOX burners with or without overfire air. The
inclusion of OFA will only affect salability in isolated instances
where UBC is already near the 5 percent level due to the installation
of low NOX burners without OFA. (See Docket Item IV-A-10.)
However, since more than 50 percent of the affected boiler population
are tangentially fired boilers, and since their UBC levels are not
expected to change with the retrofit of LNBT, they can easily replace
ash previously sold by dry bottom wall-fired units. Therefore, on a
national level, increases in UBC due to the installation of systems
including overfire air are not expected to affect flyash sales beyond
that associated with other forms of LNBT.
The EPA's UBC study further showed that, in some cases, retrofits
will improve (i.e., reduce) the UBC content of flyash, thus making some
flyash salable that was not salable before retrofit. The EPA also
learned that at plants where the UBC level of one boiler rises above 5
percent, at least some of those plants will have other boilers with
acceptable flyash that they can substitute. Considering these findings
and a further finding that transportation cost is the major determinant
in the salability of flyash, EPA concluded that even though flyash
sales may be an issue at some plants, the number of such plants will be
small and in the aggregate, flyash sales will not be affected by
increases in the UBC content.
3. Cost of Low NOX Burner Technology
In the 1997 rulemaking, EPA must establish annual emission
limitations for Group 2 boilers (e.g., wet bottom wall-fired, cyclone,
cell burners, and other utility boilers not in Group 1) and, according
to section 407(b)(2) of the Act, can only consider NOX controls
that are comparable to the cost of low NOX burner technology as
applied to Phase I, Group 1 boilers. Pursuant to this statutory
requirement, EPA must establish cost ranges of low NOX burner
technology as applied to Phase I, Group 1 boilers. The major issue is
what material, labor, and operational impacts should be included when
estimating the cost associated with a low NOX burner technology
installation.
Comment: Considerable comments were received, mostly from utilities
and industry associations. Many commenters disagreed with EPA's cost
estimates for low NOX burner technology, claiming that these costs
were based on budgetary or pre-bid estimates. Some of these commenters
supplied new cost data. Some commenters believe that EPA should include
operational penalties (i.e., increases in unburned carbon in the fly
ash, carbon monoxide, boiler waterwall corrosion, slagging, temperature
imbalances) in determination of cost associated with the installation
of low NOX burner technology. One commenter believes that
alternative technologies should be exempted from any comparative cost
tests.
Response: In the analysis in support of the proposed rule, EPA
developed curves relating capital cost to unit size for the retrofit of
combustion NOX controls to dry bottom wall- and tangentially fired
boilers. These curves, with the exception of that for LNC 1, were
derived from cost data for retrofit combustion NOX controls
presented in two Department of Energy (DOE) Comprehensive Reports to
Congress. The data were based on estimates of expected capital costs
for retrofitting combustion NOX controls and were compared to
aggregate costs supplied by three utilities. (See Docket Item II-B-12.)
Since the proposal, many utilities have begun retrofitting
combustion controls on Group 1 boilers. Of these, a large number have
contracted with architectural and engineering (A&E) firms to supply
pre-bid estimates, evaluate vendor bids, and oversee the installation
of the combustion NOX controls and all associated equipment.
In an effort to more accurately represent costs associated with the
retrofit of LNBT, EPA likewise contracted with a major A&E firm to
perform a study of costs associated with the retrofit of combustion
NOX controls to dry bottom wall- and tangentially fired boilers.
(See Docket Item IV-J-16.) The study applied low NOX burners with
and without OFA to one generic 300 MW dry bottom wall-fired boiler and
low NOX coal and air nozzles with close-coupled and separated OFA
(LNC 1, 2, and 3) to one generic tangentially fired boiler. The two
boilers and their associated characteristics (e.g., heat input, heat
release rates, steam flows, NOX emissions, coal properties) were
selected by the A&E firm from its in-house database as representative,
on average, of U.S. Group 1 affected boilers. The modifications
required with the retrofit of combustion NOX controls as well as
expected performance, were based on actual retrofit projects and
published literature. The costs associated with all combustion NOX
control modifications were derived from the A&E's in-house database and
validated with vendor supplied information.
The study developed total levelized costs including incremental
operating and maintenance costs using as a guideline, the EPRI
``Technical Assessment Guide'' (TAG) class II criteria. (See Docket
Item IV-J-16.) The increased UBC levels associated with the retrofit of
combustion NOX controls were included in boiler operating costs
and increased coal consumption. The study evaluated impacts on other
boiler parameters such as excess air levels, fan capacities, emissions
of other pollutants including particulate matter, and pulverizer
performance.
As a result of this study, cost algorithms relating capital cost to
unit size were developed for the following combustion NOX control
systems: (1) Wall fired boilers (including low NOX burners with
and without OFA); and (2) tangentially fired boilers (including those
with low NOX coal and air nozzles with close-coupled OFA or LNC 1,
with separated OFA or LNC 2, and with close-coupled and separated OFA
or LNC 3).
The cost algorithms also reflected the impacts of ancillary cost
elements (e.g., additional fan capacity, asbestos removal, burner
management systems, major structural modifications) and indirect costs
or total capital costs. Table 3 compares the capital costs as estimated
in the proposed rule with the estimates developed by the A&E firm
incurred by a typical 300 MW boiler retrofitting combustion NOX
controls, excluding these ancillary costs.

Table 3.--Capital Costs for Retrofit Controls
------------------------------------------------------------------------
Proposed Final
capital capital
NOX control system\1\ costs ($/ costs
KW) ($/KW)
------------------------------------------------------------------------
Wall-fired:
LNB................................................ 19.3 19.5
LNB and OFA........................................ 22.5 .......
LNB/AOFA........................................... 25.6 25.8
Tangentially fired:
LNC 1.............................................. 5.0 10.4
LNC 2.............................................. 14.3 11.2
LNC 3.............................................. 23.1 15.0
------------------------------------------------------------------------
\1\LNB=low NOX burners without overfire air; OFA=overfire air;
AOFA=Advanced overfire air; LNC 1=low NOX coal and air nozzles with
close-coupled OFA; LNC 2=low NOX coal and air nozzles with separated
OFA; LNC 3=low NOX coal and air nozzles with close-coupled and
separated OFA.

As shown in Table 3, the costs remain similar for NOX controls
as applied to dry bottom wall-fired boilers. For LNC 1, the revised
estimates are double the costs estimated in the proposed rule. This
difference is because the estimated LNC 1 costs in the proposed rule
were assumed at a constant dollar per kilowatt ($/KW) based on an EPRI
estimate since cost data for this system were not available at the time
of proposal. The actual cost associated with LNC 1 will probably be
higher than 10.4 $/KW since all retrofits of this system reported to
date have also included replacement of the original windbox, an item
not included in the A&E firm's study. For LNC 2 and 3, the revised cost
estimates are 20 to 35 percent lower than the cost presented in the
proposed rule. This difference is probably due to increased competition
in the area of retrofit NOX controls as applied to tangentially
fired boilers.
To evaluate the accuracy of the current cost algorithms, EPA
compared its outputs to actual retrofit costs for 15 U.S. coal-fired
boilers, 8 wall fired boilers, and 7 tangentially fired boilers. The
actual costs were similar to all but the cost algorithms for LNC 1. The
available actual costs of retrofitting LNC 1 were for two twin furnace
boilers that require replacement of eight furnace corners as compared
to four for single furnace boilers, and are therefore not
representative of the remaining Group 1 tangentially fired boilers.
When the actual costs for these two retrofits were reduced to half,
they agreed closely with estimates made using the cost algorithms for
LNC 1.
Costs associated with the retrofit of alternative technologies have
not at this time been determined, since they are not within the
definition of LNBT for Group 1 boilers.

B. Alternative Emission Limitations

Section 407(d) of the Act requires EPA to authorize an AEL less
stringent than the applicable limitation upon a determination that a
specific unit ``* * * cannot meet the stated limitation using low
NOX burner technology'' (section 407(d)(1)). In such
circumstances, the AEL is to be granted to the owner or operator after
it has been shown to the satisfaction of the permitting authority that
the owner or operator:
(1) Has properly installed appropriate control equipment designed
to meet the applicable emission rate;
(2) Has properly operated such equipment for a period of fifteen
months (or such other period of time as the Administrator determines
through the regulations) and provides operating and monitoring data for
such period demonstrating that the unit cannot meet the applicable
emission rate; and
(3) Has specified an emission rate that such unit can meet on an
annual average basis. If these criteria have been satisfied, then an
operating permit is required to be issued at the conclusion of an
operational period that demonstrates the long-term emission rate that
the unit is able to achieve.
The AEL application process is designed to verify these three
criteria in an incremental manner. First, the unit must demonstrate
that the applicable emission rate cannot be met using low NOX
burner technology in accordance with section 407(d)(1). The requirement
to have installed low NOX burner technology incorporating overfire
air serves this function. Secondly, the unit must demonstrate that the
installed technology was ``designed to meet the applicable emission
rate'' (section 407(d)(1)). If these two criteria have been met, the
utility must then demonstrate eligibility by showing the inability of
the unit to meet the applicable emission limitation during proper
operation of the unit with the installed NOX control technology
(section 407(d)(2)). The final step is a long-term demonstration of the
unit's inability to meet the applicable emission limitation and a
demonstration of the emission rate that the specific unit is able to
achieve.
To successfully implement the AEL provisions, it is necessary to
develop procedures that will ensure that units with a legitimate need
for an AEL are able to obtain one, while preventing the AEL provisions
from being used as an easily obtainable detour around the generally
applicable NOX emissions limitations. The procedures must be based
on a consistent and technically valid foundation and reflect the
following principles:
(1) The AEL is intended for units that have made a good faith
effort to attain the applicable NOX limitation but are unable to
do so;
(2) It is the utility's responsibility to show to the satisfaction
of the Administrator that such an effort has been made;
(3) It is the responsibility of the permitting authority to verify
through internal evaluation and through public notice and comment, the
reasonableness of the information received from the utility prior to
issuing the final AEL; and
(4) It is in the best interests of both EPA and the utility to
develop AEL issuance procedures which are as straightforward as
possible in light of the highly site-specific nature of combustion
modification NOX control technologies.
Comments received from the utility industry, equipment
manufacturers, regulatory bodies, and environmental groups have
provided considerable guidance toward developing a fair and workable
process. The major issues identified by the commenters are AEL
eligibility requirements, operating and demonstration periods, data
certification requirements, testing requirements, and inclusion of
alternative technologies in the AEL provisions. Comments and responses
to these issues are presented below.
1. Eligibility Requirements
The central issue is whether a unit has shown sufficient effort in
attempting to reach the applicable limitation that it may be issued a
permit to operate at a higher emission rate than that to which all
other units are subject. The Agency believes that Congress intended the
AEL provision to provide a ``safe harbor'' for units that, despite a
good faith effort, cannot meet the limitation because of variability in
the effectiveness of low NOX burner technology.
Comment: Commenters noted that the circumstances under which OFA is
technically or economically infeasible should be more clearly defined,
particularly terms such as ``destructive operating conditions.''
Commenters also requested that units that installed low NOX burner
technology prior to promulgation of the rule not be denied the use of
the AEL provisions.
Response: It is the position of EPA that a unit must comply with
the minimum requirements set forth in section 407(d) of the Act in
order to be eligible to operate with an emission rate higher than that
set by the Administrator. These minimum requirements include
installation of equipment designed to meet the applicable emission
limitation and proper installation and operation of that equipment. An
owner or operator must demonstrate these requirements have been met in
the petition for an AEL operating period. Because of the site-specific
nature of NOX control equipment effectiveness, some degree of
flexibility is necessary when evaluating these requirements in special
instances. However, such flexibility must be consistent with the
underlying requirement that the utility has made a good faith effort to
achieve the applicable limitation.
Such a good faith effort is evidenced in part by the utility having
solicited equipment designed to meet the applicable emission
limitation. It is difficult to see how a utility that seeks bids on
equipment but fails to specify a level of performance adequate to meet
the applicable emission limit could be making a good faith effort to
meet the limit. Therefore a utility must show that it initially
requested that vendors submit bids for low NOX burner technology
designed to meet the applicable emission limitation over long-term,
load dispatch operation of that specific unit. Moreover, a utility that
receives several bids for equipment not designed to meet the limitation
and that installs such equipment cannot be eligible for an alternative
emission limitation if the utility has also received a legitimate bid
for equipment designed to meet the limitation. Installation of
equipment not designed to meet the limitation is in direct
contradiction to the requirements set forth in section 407(d) for
obtaining an AEL.
In addition, the determination that a unit cannot meet the
applicable limitation using low NOX burner technology (section
407(d)(1)) is to be based on whether the unit was equipped with the
best performing LNBT which incorporates overfire air. Only units that
are unable to meet the limitation after proper operation of the most
effective low NOX burner technology will be provided the
opportunity to apply for an AEL.
Comments concerning conditions under which overfire air is not a
necessary requirement for receiving an AEL highlights the site specific
nature of low NOX burner technology application. Terms such as
``technically infeasible'' can be interpreted in many ways, and setting
a strict definition does not account for the significant variations in
boiler age, size, or operational characteristics. Installations of low
NOX burner technology that would require major modifications of
the boiler's supporting structure are clearly beyond the intent of the
Act and would clearly be seen as meeting the ``technical
infeasibility'' condition. In general, the demonstration of the
utility's good faith effort to install and operate the most effective
level of low NOX burner technology including utilization of OFA
must be made during the AEL application process and will be reviewed on
a case-by-case basis.
The EPA is in agreement with comments that units that have
installed low NOX burner technology prior to promulgation of this
rule should be allowed to seek an AEL if the owners or operators of
such units can demonstrate the same good faith effort to achieve the
applicable emission limitation using low NOX burner technology
which incorporates overfire air. Such a demonstration must include the
utility having solicited equipment designed to meet the applicable
emission limitation and a showing of proper installation and operation.
2. Demonstration Period and Operating Period
The Act requires that the owner or operator properly operate low
NOX burner technology for a period of fifteen months (or other
period of time determined by the regulations) to verify the long-term
inability of the unit to achieve the applicable emission rate. The
proposed rule calls for a six month operating period followed by a
fifteen month demonstration period. An interim limit will be specified
in the Acid Rain permit governing each eligible unit to cover the
demonstration period.
Comment: Utilities generally supported the interim operating limits
and suggested the interim limit be set at the maximum emission rate
recorded during the six month operating period. They also suggested
incorporating some or all of the operating period into the
demonstration period. Some commenters expressed concern over the lack
of specific time limitations for approval or denial of the
demonstration period plan. Other commenters suggested the six month
operating period was unnecessary.
Response: The EPA's position that the two time periods specified in
the proposed rule, i.e., the three-to-six month operating period
followed by a fifteen month demonstration period, are adequate and
necessary to accomplish the tasks associated with the AEL procedure.
The two together provide time for a responsible utility to take
corrective action to lower NOX emissions if possible and thereby
eliminate the need for an AEL or to demonstrate such need and the long-
term emission limitation the unit can achieve if the corrective actions
are unsuccessful.
The EPA favors providing flexibility in the lengths of these time
periods, but does not favor an approach that will impair the ability of
a utility to achieve the applicable emission limitations where
possible. The operating period immediately following the installation
of the NOX control equipment must be adequate for utilities to
verify their inability to meet the stated limits and to allow
troubleshooting of the low NOX combustion system to take place.
The demonstration period must be adequate to verify the long-term
inability of the unit to meet the emission limitation and to define the
emission rate that the unit is able to achieve during long-term
operation.
In order to provide additional flexibility in the AEL application
procedure, the final rule is modified to allow a utility to conduct its
operating period for at least three months following commencement of
operation of low NOX burner technology before the utility may
apply for the demonstration period. The utility may subsequently
demonstrate the inability of the unit to achieve the stated limits over
an additional period of at least twelve months and no more than fifteen
months. This period will retroactively include the three month
operating period plus the time after that period, not to exceed 30
days, to submit the application. This approach provides utilities with
a window of at least fifteen months from the time operation with low
NOX burner technology begins until the application for the final
alternate emission limit is received by the permitting authority. Under
this arrangement, the unit must operate a minimum of three months
before it may notify the permitting authority of its intent to seek an
AEL. A shorter period of time between commencing operation with low
NOX burner technology and stating an intent to seek an AEL would
call into question the level of effort expended to achieve the
applicable limitation.
The demonstration period may be extended if the utility
demonstrates that such an extension is necessary for the utility to
install or modify equipment on the specific unit to achieve lower
NOX emissions. Such an extension is intended for units that have
identified means of reducing NOX emissions during the
demonstration period, but require additional time to implement these
changes due to equipment lead times or outage schedules.
Commenters raised several concerns as to regulatory liability
during the operating and demonstration periods. The proposed rule
provided for an interim alternative emission limitation to which a unit
seeking an AEL would be subject during the demonstration period. This
interim rate would be no greater than the maximum emission rate
recorded during the operating period and would allow the utility to
make adjustments to equipment settings and operating practices to
improve NOX reductions without undue concern over the consequences
of failed tests.
However, no provision was made for a special emission limitation to
cover the operating period. The EPA's position is that a unit that has
not demonstrated the minimum eligibility requirements for an AEL
remains subject to the applicable emission limitation in Secs. 76.5,
76.6, or 76.7. Since the minimum eligibility requirements cannot be
demonstrated prior to the conclusion of the operating period, a unit
seeking an AEL remains subject to the original emission limitation for
that particular unit. If a unit submits a petition for an AEL
demonstration period which is subsequently approved, then the operating
period will retroactively become subject to the interim alternative
emission limitation that has been set for the demonstration period.
3. Data and Certification Requirements
The final rule requires the primary equipment vendor to certify
proper design, proper installation, and proper operation of the low
NOX burner technology. The purpose of the vendor certifications is
to ensure that the criteria are met and that Congressional intent that
utilities make a reasonable and sincere effort to achieve the
applicable emission limitations is carried out.
Comment: Utilities felt very strongly that relying on vendor
certification of proper installation and the requirement that the
utility must install equipment upgrades and new equipment recommended
by the vendor could put the utility in the position of being held
hostage by the vendor. Commenters also stated that use of vendor
certification could place the vendor in a position of conflict of
interest. The vendor would be acting both as the supplier of equipment
(from which the vendor would profit) and supplier of the regulatory
certification of the utility's good faith effort to achieve the stated
emission limitations (in which the vendor must act as an objective
third party). Additional commenters felt that the use of vendor
certification effectively places the vendor in the position of acting
as the regulatory authority.
Response: The EPA is requiring the owner or operator through the
designated representative to submit certifications of proper design and
installation from the vendor in order to provide the permitting
authority with the highest level of expertise regarding the design and
installation of the low NOX combustion equipment and to reduce the
appearance of opportunity for self-regulation by the utility. The
vendor is the party with the greatest expertise to evaluate proper
design and installation of the low NOX burner technology; such
expertise cannot be ignored. Certification that equipment designed to
meet the applicable emission limitation was originally requested by the
owner or operator will be determined by requiring submittal of the bid
solicitation to EPA by the owner or operator. In the initial
discussions between the utility and the vendor, the operating
conditions that have been agreed to by both parties can significantly
affect the NOX reduction of the low NOX burner technology
that is ultimately installed. By requiring the utility to submit a
certification from the primary equipment vendor that states the
equipment was designed to meet the applicable emission limitation in
long- term load dispatch operation and was properly installed, EPA is
trying to ensure these latter two prerequisites for an AEL under the
Act have been met. These certifications do not go beyond any agreement
that should be made between any responsible utility and any reputable
vendor, if the utility is making a good faith effort to achieve the
emission limitations set forth in the Act. In addition, these
certifications do not allow a vendor to require additional equipment or
upgrades to be purchased beyond what was originally negotiated by the
utility in order for that utility to obtain the necessary
certifications.
Certification that the low NOX burner technology has been
operated properly is the sole responsibility of the utility owner or
operator. ``Proper operation'' is considered to be operation that is in
accordance with the conditions for which the equipment was originally
designed. Therefore, in order to be eligible for an AEL, the unit is
obligated to operate in a manner consistent with these conditions. If
the unit is not operated in such a manner, the question remains open as
to whether the utility is making a good faith effort to meet the
emission limitation and whether the unit is therefore eligible to
receive an AEL. In this and all other instances, the ultimate burden of
proof or qualification for an AEL lies with the utility.
4. Testing Requirements
The proposed rule provided a list of tests that a utility would be
required to conduct prior to obtaining an AEL. These tests were
designed as a means of verifying proper operation of the installed
equipment.
Comment: Commenters characterized the testing requirements set
forth in the proposed Sec. 76.13 as burdensome, impractical, or having
no relation to NOX emissions.
Response: The EPA's position that the criterion of proper operation
that is required to be met before an AEL can be issued can only be
verified through testing of the specific unit and that to omit these
tests would be neglecting the Congressionally mandated requirement to
verify proper operation of the unit. The tests chosen for inclusion in
the proposed rule were done so on the basis of their ability to provide
information to support a utility's claim that the equipment has been
properly operated.
However, the mere collection of data does not ensure that the
utility has made a good faith effort to reduce NOX emissions.
Proper operation is to be verified through a ``technical report'' that
explains the reasons for the failure of the equipment to perform as
designed and why it is not possible to rectify the identified problems
within the scope of the requirements of this rule. Although a simple
explanation of the failure may not be possible, the report will show at
a minimum that the owner or operator has attempted to determine through
a reasonable program of testing that the unit is operating at
conditions that minimize long-term NOX emissions. As a means of
providing flexibility in the testing procedures, EPA provides in the
final rule that the utility may substitute for or delete tests that can
be shown to be irrelevant to the NOX emissions at that specific
unit. Tests also may be added where they are shown to be relevant for a
specific unit. The EPA believes that the tests listed in the rule are
those that a responsible utility would conduct during an in-depth
evaluation aimed at evaluating the new equipment's operation and
minimizing NOX emissions. The report showing that these tests have
been performed is a clear indication of good faith effort to meet the
stated limitations. (See Docket Item IV-J-21.) In support of these
testing requirements, documents reviewed by EPA during the development
of today's rule indicate that the operating conditions specified in bid
solicitations and in vendor performance guarantees include parameters
that are covered by the tests required by the rule. (See Docket Item
IV-D-163.) These documents are all the more significant in that they
were prepared prior to the publication of the proposed rule. The
position of EPA that such tests are those normally required by
utilities as a verification of proper performance is strongly supported
by these documents. In addition to providing this test and performance
information to the permitting authority, report summaries will also be
made available to the public, thereby allowing other utilities to
observe the success or failure rates of the equipment offered by
various vendors and aiding in their choice of equipment.
Further comments were received concerning the requirement in the
proposed rule that overfire air be installed where it will achieve a
predicted additional reduction in NOX of 0.05 lb/mmBtu or more.
The 0.05 lb/mmBtu criterion for determining the potential effectiveness
of overfire air has been removed from the final rule. In light of our
adoption of a definition of low NOX burner technology as low
NOX burners including overfire air, the 0.05 lb/mmBtu criterion is
not necessary. In order to receive an AEL, the utility must install
overfire air, unless installation of overfire air is shown to be
technically infeasible on the specific boiler.
5. Inclusion of Alternative Emission Limitation Procedures for
Alternative Technologies
Alternative technologies were included in the proposed AEL
provisions in order to provide a similar ``safe harbor'' provision for
NOX control techniques other than low NOX burner technology.
These provisions were structured in a manner similar to those for low
NOX burner technology and required verification of proper design,
installation, and operation prior to receiving an AEL.
Comment: Nearly all comments were in support of providing access to
AELs for alternative technologies. Several commenters suggested that
alternative technologies be considered equivalent to low NOX
burner technology for the purpose of receiving an AEL. Other commenters
felt that failure to equate alternative technologies with low NOX
burner technology will result in a disincentive to the installation of
alternative technologies. It was also suggested that the use of the
term ``low NOX burner technology'' was not meant to specify a
particular technology, but was only used to place a limit on the cost.
Comments were received stating that since costs of alternative
technologies have fallen relative to low NOX burner technology,
alternative technologies have become competitive on a cost basis and
the lack of an AEL for these systems makes the relative risks of low
NOX burner technology installation much less than installation of
alternative technology. Further comment was received suggesting that
allowing an AEL for alternative technologies assigns all the benefits
of successful application of these technologies to the utilities, while
leaving all the risk associated with their failure to the environment;
this commenter suggested removal of the AEL provision for alternative
technologies. In general, however, there was widespread support for
inclusion of alternative technologies in this section to encourage
their development and use.
Response: The final rule allows a unit that installs an alternative
technology to receive an AEL if that unit achieves a reduction in
NOX emissions of 65 percent or greater and is still unable to meet
the applicable limitation. The EPA maintains that Congress did not
intend to discourage alternative technologies. In fact, the development
and application of new technologies may provide significant benefit to
the environment by lowering the cost of implementing pollution control
through improved efficiency and increased competition in the control
technology market. However, there may still be instances in which
application of alternative technologies to units with very high
baseline emissions may result in controlled emissions greater than the
applicable limitations albeit fewer emissions than if low NOX
burner technology had been used. In such cases, the units involved
should be eligible for an AEL.
The approach taken in the proposed rule was to require the owner or
operator to show the reduction achieved by the alternative technology
was greater than what could be achieved by low NOX burner
technology on the same unit. It was felt this showing could be made
either by presenting evidence in the form of vendor bids that low
NOX burner technology was not able to achieve such reductions or
by presenting numerical modeling results indicating the inability of
low NOX burner technology to achieve the required reductions. In
the first case, this relies on the low NOX burner technology
vendors, who are in competition with the alternative technology
vendors, presenting in effect documentation that the alternative
technology is superior to their own products. It is not reasonable to
expect low NOX burner technology vendors to act in this manner and
so this approach could seriously impair the competitive position of
alternative technology vendors. The second approach relies on computer
models, which typically use a number of empirically based factors that
could be too easily used to adjust the model to obtain results
favorable to the modeler.
A third approach, and the one which is taken in this rule, is to
require the NOX reductions achieved by an alternative technology
to be greater than or equal to that which could reasonably be attained
by the best performing low NOX burner technology for the
alternative technology to be eligible for an AEL. While this approach
may appear to limit the application of alternative technologies,
alternative technologies cannot be considered equal to low NOX
burner technology because section 407(d) specifically requires a unit
applying for an AEL demonstrate that low NOX burner technology
cannot meet the applicable emission limitation. From a technical
perspective, NOX control technology installations have tended to
begin with combustion controls (emphasizing low NOX burner
technology) and only then to turn to alternative technologies as
increasingly greater NOX reductions are sought. While costs of
alternative technologies have fallen relative to low NOX burner
technology in the period since the passage of the Act, the rule must
follow the Act's requirements and must treat alternative technologies
fundamentally differently than low NOX burner technology by
requiring alternative technologies to demonstrate reductions equivalent
to the best performing low NOX burner technology alone. In this
way, the final rule implements the statutory language without
discouraging the use of alternative technologies that would perform as
well or better than low NOX burner technology.
The comment that all risks of alternative technology failure are
assigned to the environment and not to the utility seems to arise from
a perception that alternative technologies are more likely to fail than
low NOX burner technology. The requirements of today's rule mean
that, to obtain an AEL a unit using an alternative technology must
achieve at least as great a reduction that is representative of what is
achievable with the best performing low NOX burner technology.
Thus, this provision in the rule does not increase the potential damage
to the environment.

C. Emissions Averaging

Section 407(e) of the Act requires EPA to establish an emissions
averaging compliance option to be utilized as an alternative method of
achieving compliance with NOX emissions limitations. Under the
proposal, this compliance option was designed to allow two or more
units with the same designated representative to average their
emissions together rather than relying upon strict unit-by-unit
compliance. Such an approach allows utilities maximum flexibility in
complying with the NOX emissions reduction requirements of section
407.
Under the proposed rule, the designated representative of two or
more units subject to one or more of the applicable emission
limitations in Secs. 76.8, 76.9, or 76.10 could submit a proposed
averaging plan containing the information and data specified in
Secs. 76.14 and 76.17 of the rule to the applicable permitting
authority(ies). When a proposed averaging plan would govern units
located in the jurisdiction of more than one permitting authority, the
designated representative was required to file the same proposed plan
with each permitting authority having jurisdiction over any unit in the
plan.
The comments received from the utility industry, environmental
organizations, and State and federal regulatory authorities have
provided considerable input to EPA concerning the most appropriate and
reasonable way to implement the program. The major issues identified by
the commenters are the separate designated representative for NOX,
the common designated representative, emissions averaging as a
prerequisite for an AEL, emissions averaging across State lines or
permitting authorities, the relationship of the title IV NOX
program with the title I program, and banking issues. Each of these
issues is addressed below.
1. Separate Designated Representative for NOX
In the preamble to the proposed NOX rule, EPA solicited
comment ``on the desirability and practical consequences of allowing
separate designated representatives for NOX and SO2 and on
whether the proposed safeguards governing the dual designated
representatives by an affected source would preserve accountability for
compliance.''
The dual-designated representative option presented in the proposed
rule was designed to afford utilities even greater flexibility in
complying with the NOX emission limitations, especially for small
utilities. However, issues concerning accountability and liability of
such a dual designated representative system and restrictions were
presented for comment. The proposal required that the NOX
designated representative certify that the NOX compliance plans
developed for that designated representative's affected units were
consistent with the SO2 compliance plans for those units.
Comment: The concept of a separate designated representative for
NOX elicited strong comments on both sides. Some commenters felt
that the purpose of the Act's designated representative provision is to
ensure that a single person would be identified as a responsible
representative for the purpose of handling allowance transactions and
satisfying all acid rain permit compliance duties. They felt that
creating a second independent person responsible for compliance only
with acid rain NOX provisions could potentially conflict with
SO2 compliance and would undermine the clarity of compliance
responsibilities that the single designated representative approach was
intended to provide.
However, others support the use of a NOX-only designated
representative and feel that EPA provides the necessary accountability
for the system and no extra safeguards should be necessary.
Response: The EPA has evaluated the Act and legislative history
concerning this issue and found no statutory support for the concept of
a separate designated representative for NOX. To the contrary,
title IV consistently refers to a single designated representative,
rather than multiple designated representatives, for owners and
operators under the entire Acid Rain program whether for SO2 or
NOX emission limitations. For example, section 408(c)(1),
addressing Phase I permits covering SO2 indicates that Congress
intended for there to be only one designated representative for units
covered by both the SO2 and NOX provisions of title IV:

. . . the designated representative of the owners or operators,
or the owner and operator, of each affected source under Sections
404 and 407 shall submit a permit application and compliance plan
for that source . . .

(See 42 U.S.C. 7651g(c)(1).)

Similarly, sections 408(b) and (d)(2) require respectively that the
permit application and compliance plan for adding NOX provisions
to the Phase I permit and the Phase II permit application and
compliance plan covering both SO2 and NOX be submitted by the
``designated representative'' or the owner or operators. (See 42 U.S.C.
7651(d)(2), (b), and (g).)
The EPA also finds compelling the argument that, even with the
safeguards described in the proposal, the reconciliation of permit
applications and end-of-year compliance data from multiple designated
representative's with potentially varying responsibilities would be
problematic at best. (See e.g., 58 FR 3590, 3597; January 11, 1993
(explaining need for having one designated representative.)) To ensure
adequate enforceability, EPA feels it must have a single point of
contact for both SO2 and NOX.
2. Common Designated Representative
The proposed rule provided that units having a common designated
representative satisfy the statutory requirement that units in an
averaging plan have a common owner or operator. This definition would
allow utilities that have no ownership or operating relationship to
link together for the purpose of averaging NOX emissions.
Allowing a common designated representative to fulfill the common
owner/operator requirement function would give EPA a single point of
contact for each averaging plan. This approach was designed to ensure
that small utilities had the option to take advantage of the flexible
compliance provisions of the rule and would result in broader and more
populous averaging pools. A similar approach was adopted in the
proposed and final permits rule in 40 CFR part 72 regarding
substitution units, which must have a common owner or operator with
their respective Phase I units.
Comment: The EPA received comments on this issue from a broad
cross-section of the interested parties. The comments were generally
reflective of the different perspectives of these interests. Several
commenters approved of allowing the common designated representative
for averaging purposes and claimed that requiring a common owner or
operator in addition to the common designated representative would
defeat the purpose of the provision. An argument was made that by not
allowing small utilities to use a common designated representative to
qualify for averaging would unfairly disadvantage them.
Other commenters opposed this mechanism for expanding averaging by
noting that the Act clearly requires a common owner or operator, as
distinguished from a common designated representative. However, there
was some support for a broader interpretation to include a common
designated representative if the final rule imposed tight restrictions
on who could participate in averaging pools, and under what
circumstances (e.g., by requiring low NOX burner technology prior
to averaging and imposing restrictions on AEL's).
Comments were received from those that do not oppose multiple
ownership of units participating in a NOX emissions averaging plan
as long as liability can be established at all times. Concerns were
raised that owners or operators of a co-owned plant could be liable for
false or inaccurate certifications or submissions by other averaging
pool participants.
There also was support for individual unit liability rather than
liability for all units in the averaging pool.
Response: The EPA is in agreement that on its face, having a common
designated representative does not meet the statutory requirement of an
owner or operator under section 407. The language of section 407(e) of
the Act is clear:

The owner or operator of two or more units subject to the one or
more of the applicable [NOX] emission limitations set pursuant
to these sections, may petition the permitting authority for
alternative contemporaneous annual emission limitations (averaging
plans). . . .

42 U.S.C. 7651g(e) (emphasis added)

Moreover, the Act explicitly distinguishes between designated
representatives and owners and operators. (See 58 FR 3599, January 11,
1993.) On one hand, the Act states that designated representatives
represent owners and operators, and in that capacity are responsible,
along with owners and operators, for holding and transferring
allowances and submitting and complying with permit applications and
compliance plans. (See 42 U.S.C. 7651a(26); 7651b(b); 7651g(c)(1),
(d)(2), and (h)(1).) On the other hand, the Act makes only owners and
operators responsible for meeting emissions limitations and monitoring
requirements. (See 42 U.S.C. 7651c(a), 7651d(a), and 7651k.)
While in the January 11, 1993 rules, the Agency had provided that
in certain cases a designated representative would be considered an
operator, e.g., where units in a substitution plan otherwise lack a
common owner or operator, the Agency subsequently proposed to reverse
its position with regard to substitution plans and modify the January
11, 1993 regulations. (See 58 FR 60950, November 18, 1993.) Although
the Agency has not decided whether to adopt the reasoning in the
November 18, 1993 proposal with regard to substitution plans, the
Agency has concluded that this reasoning is fully applicable to
NOX averaging plans.
Section 407(c) explicitly allows submission of NOX averaging
plans only for ``the owner or operator of two or more units.'' 42
U.S.C. 7651g(e). Consequently, units with no common owner or operator,
but with a common designated representative, would qualify for such
plans only if the designated representative were an operator. In the
preamble of the January 11, 1993 regulations, the Agency determined
that ``[i]n some cases'' the designated representative's ``duties and
level of responsibility can be equivalent'' to those of an operator. 58
FR 3600. One such case, identified by the Agency, was where a
designated representative represents multiple sources participating in
a substitution plan and lacking a common owner or operator. In that
case, the designated representative's responsibilities are allegedly
``broad enough to bring him or her within the definition of operator.''
Id. In order for a designated representative to be considered an
operator in the case of a NOX averaging plan, this same line of
reasoning must apply. The problem is that it is difficult to see how a
designated representative's responsibilities in a NOX averaging
plan are actually any broader or of a higher level than they are under
other compliance options under title IV of the Act for SO2 or
NOX.
In order to use a NOX averaging compliance option, a
designated representative must certify and submit a NOX averaging
plan that covers all the units involved and that is included in the
permit applications of the sources at which such units are located. The
same plan must be submitted to all permitting authorities with
jurisdiction over the units. 40 CFR 76.11(b) and (c). The plan must
state the alternative contemporaneous emissions limitations and
assigned annual heat input values for these units and show that these
figures meet the test for group compliance. 40 CFR 76.11(c). The
designated representative must coordinate among owners and operators of
the units that he or she represents to the extent necessary to arrive
at agreed-upon figures and to ensure that he or she is authorized to
submit the plan. 40 CFR 72.21(b). Once the NOX averaging plan is
approved, the owners and operators of all the units governed by the
plan are potentially liable for violations of the plan at any of the
units. 40 CFR 76.11(d)(2).
Designated representatives have similar responsibilities under
other multi-unit compliance options. For example, Phase I extension
plans for SO2 under section 404(d) of the Act can involve a
control unit at one source and transfer units at other sources and the
sources involved need not have common owners or operators. In that
case, the designated representatives of the sources involved must
coordinate among owners and operators of the sources, agree on a single
Phase I extension plan, and certify, sign, and submit the plan as part
of their respective permit applications. See 40 CFR 72.40(b)(1)(i) and
72.42(b)(2)(ii). Under an approved Phase I extension plan, owners and
operators are potentially liable for violations of the plan by other
units governed by the plan. See 40 CFR 72.42(f) (1) and (4).
The situation is similar for reduced utilization plans for SO2
under section 408(c)(1)(B) of the Act, which can involve a Phase I unit
and compensating units located at multiple sources. All the designated
representatives must agree on and certify and submit a single plan. See
40 CFR 72.40(b)(1)(i) and 72.43(b)(4). Further, under Sec. 72.91(a),
the designated representatives of the Phase I unit and compensating
units under a plan must use consistent figures in their annual
compliance certification reports to calculate the adjusted utilization
of the respective units. See 40 CFR 72.91(a)(3)(ii) and (4). Again,
owners and operators are potentially liable for violations of the plan
by other units governed by the plan. 40 CFR 72.43(f)(3).
Moreover, the designated representative's responsibilities under
some single-unit compliance options are also at least as extensive as
under a NOX averaging plan. In particular, although the
alternative emission limitation compliance option does not involve
multiple units, the designated representative bears a high level of
responsibility in obtaining approval of the option and must have fairly
in-depth knowledge about the unit and its operations. The designated
representative must first certify and submit a petition for an
alternative emission limitation demonstration period. Such a petition
must include, inter alia: a showing that the unit's NOX control
system was designed to meet applicable emission limitations and was
properly installed; a certification that the owners or operator
operated the unit so as to achieve maximum NOX reduction and meet
the conditions on which the NOX control system was based; and a
plan detailing completed or planned equipment modifications and
upgrades to improve NOX reduction and the tests that will be
performed to evaluate the performance during the demonstration period.
See 40 CFR 76.10(d) and 76.14(a)(2). The designated representative must
subsequently certify and submit a petition for a final alternative
emission limitation, which includes, inter alia: certifications and
information concerning the operation of the unit and the NOX
control system and the completion of planned modifications and upgrades
and other steps taken to maximize NOX reduction; and an
alternative emission limitation that is the lowest NOX emission
rate that the unit can achieve. See 40 CFR 76.10(e).
The designated representative must coordinate with the owners and
operator of the unit and be sufficiently knowledgeable to make the
necessary certifications required for the above-described petitions.
However, it is the owners and operator of the unit that are potentially
liable for all violations of the approved alternative emission
limitation demonstration period plan and final alternative emission
limitation.
In short, the common designated representative's responsibilities
under a NOX averaging plan are not broader or more complex than
those of designated representatives under several other compliance
options, under which the designated representative is not treated as an
operator and does not bear the same liability as an operator. The
Agency concludes that there is no basis for treating a designated
representative in the context of NOX averaging plans differently
than in the context of other compliance options. Moreover, there is
nothing unique in the nature of NOX averaging plans that would
make the designated representative, rather than the owners and
operators, responsible for meeting emissions limitations or monitoring
requirements that are applicable to all units. Under all these
compliance options, the designated representative actually has
different and less extensive responsibilities than, and thus should not
be considered to be, an operator.
In addition to considering the statutory language and the
designated representative's role under various compliance options, EPA
analyzed the effects of limiting averaging pools to commonly owned or
operated units and did not find that disallowing a common designated
representative would dramatically increase the number of units that are
unable to average or are able to average with only one other unit. Only
13 of 153 Phase I/Group 1 (and 40 of 923 Phase I and Phase II/Group 1)
units are unable to average under this scenario (which assumes that
interstate averaging is allowed). Only 18 of 153 Phase I/Group 1 (and
44 of 923 Phase I and II/Group 1) units are able to form 2-unit pools
only.
However, as discussed above concerning the separate designated
representative for NOX, EPA also agrees with commenters who argue
that a single point of contact is necessary where units are
participating in averaging pools, particularly given the possibility of
multi-jurisdictional permitting and compliance.
Accordingly, the final emissions averaging rule has been modified
to accommodate a two-tiered approach to assembling averaging pools. All
units in a pool will first be required to have at least one common
owner and/or operator to be eligible to average. Once this eligibility
requirement is met, the units in the pool will then be required to
share a single common designated representative for administrative
purposes. This is consistent with Congressional intent as identified in
section 408(c)(1) for units covered by both SO2 and NOX
requirements:

* * * the designated representative of the owners or operators,
or the owner and operator, of each affected source under Sections
404 and 407 shall submit a permit application and compliance plan
for that source * * *

(See 42 U.S.C. 7651g(c)(1).)

The EPA does not feel this second administrative requirement is
overly burdensome. Currently, the designated representatives for Phase
I sources represent, almost exclusively, entire operating companies, if
not entire holding companies. This second, administrative requirement
will ensure a single point of contact for all matters pertaining to the
averaging pool, will address the concerns about enforceability, and
should lessen the utilities' overall burden of administering an
averaging pool.
By hewing closely to the statutory language in section 407(e)
requiring the same owner or operator for averaging plans, EPA is not
backing away from the concept of flexible compliance options, but
merely ensuring appropriate restrictions in accordance with
Congressional intent.
3. Emissions Averaging as a Prerequisite for an Alternative Emissions
Limitation
The concept of requiring emissions averaging as a prerequisite for
the issuance of an AEL was not addressed in the proposed rule. However,
during the comment period for the proposed rule, the Agency received
comment on requiring plants seeking an AEL to first adopt emissions
averaging programs. Such a requirement would allegedly help ensure that
anticipated NOX emissions reductions are achieved.
Section 407(d), which describes AELs, requires a demonstration that
the applicant's unit cannot meet its applicable emission limitation
using low NOX burner technology. It is argued that EPA should
construe the ``cannot meet'' language of section 407(d) to require a
demonstration that the applicant cannot meet its control obligations
with the adoption of emissions averaging.
Comment: The EPA received comments both favoring and opposing this
concept. The proponents argued that EPA's rule should recognize the
integrated nature of section 407 compliance provisions by requiring
that an applicant for an AEL must employ available emissions averaging
opportunities prior to receiving an AEL. They argued that companies
applying for plant-specific variances must first be required to adopt
emissions averaging programs and demonstrate that a variance is still
needed after ``all feasible averaging plans have been implemented.''
Opponents of this concept argued that the proposed rule did not
require averaging as a prerequisite and that the statute contemplated
that emissions averaging, AELs, and Phase I compliance extensions were
independent of each other. The commenters cited the statutory
requirements for obtaining an AEL and argued that EPA had neither the
statutory nor the discretionary authority to require averaging as an
additional prerequisite for granting an AEL. They claimed that Congress
intended Title IV reductions to be achieved in a flexible, cost-
effective manner ``through alternative methods of compliance,'' not
through cumulative requirements that restricted flexibility and
increased costs.
Response: The AEL provisions will not be changed to incorporate a
requirement for averaging prior to the issuance of an AEL. The EPA can
find no statutory mandate to require the consideration or adoption of
averaging as a condition for receipt of an AEL. Section 407(d)
expressly provides that a unit seeking an AEL must show that it cannot
meet ``the applicable limitation established under subsection (b)(1) or
(b)(2) (of section 407).'' There is no reference in section 407(d) to
any additional requirement that the unit also be unable to meet the
``alternative contemporaneous annual emissions limitation'' or unable
to join with other units to achieve the same ``Btu-weighted average
annual emission rate'' as if the unit had complied with the applicable
limitation.
4. Emissions Averaging Across State Lines
Section 407(e) of the Act is silent on whether or not averaging
should be allowed to take place across State lines. However, in its
proposal, EPA took the position that the emissions averaging program
allows units that are located in different States to participate in the
same averaging pool.
Involving more than one permitting authority complicates the
process. Obviously, there are difficulties in implementing such a
program, and provisions such as contemporaneous emissions limitations
and earlier deadlines for multi-jurisdictional plans were adopted in
the proposal in an attempt to address these hurdles.
Comment: The difficulties of implementing a broad averaging program
were central to all comments on this issue. The primary concern of
those objecting to interstate averaging was the concern for
enforceability by a State or other permitting authority.
Several commenters did not oppose multi-state averaging plans as
long as liability could be established at all times and participating
States could be given enough time to accomplish the necessary
interstate permitting.
Specifically, the States that commented requested that the final
rule require States likely to be involved in multi-state compliance
plans to provide points of contact for coordinating reviews and to set
up protocols for communication in advance of the submittal of the first
averaging plan. A related comment suggested that time limits be placed
in the final rule to require States to complete their coordinated
review by a certain date.
Some members of the Acid Rain Advisory Committee felt that the
problems of multi-jurisdictional averaging plans could be overcome if
each permitting authority had copies of the application and end-of-year
compliance certifications for all of the units in the plan, not just
the units in the authority's jurisdiction. This requirement was
included in the proposed rule.
Those opposed to multi-state averaging maintained that the Act, by
its silence on the subject of crossing State lines to average, in fact
limits averaging to different units of the same company within the same
State or within the jurisdiction of the same permitting authority. Many
opponents encouraged EPA to allow averaging only within the
jurisdiction of the same permitting authority for ease of
implementation and enforcement and to better guarantee reductions in
individual States.
Proponents of interstate averaging saw it as being consistent with
the national scope of the program and in keeping with the flexible
nature of the compliance options. They desired fast-track permit
modifications for units in multiple permitting jurisdictions and
regulatory language that prohibits a jurisdiction from delaying or
otherwise interfering with the implementation of a multi-jurisdictional
averaging plan.
Response: The EPA believes that the Act implicitly addresses
interstate averaging. At the time Congress enacted section 407(e), it
presumably had basic knowledge of the structure of the utility industry
and was aware that 15 utilities (representing 312 units) had Phase I
and Phase II/Group 1 units scattered across State boundaries. Yet
Congress did not adopt any provision that would keep utilities from
averaging across those lines. Additionally, the Acid Rain Program is
national in scope, and its requirements do not vary from State to State
even in Phase II where the States may be the permitting authorities.
The EPA believes that, consistent with this national scope, averaging
should not be restricted by State lines (or for that matter, the
jurisdictional boundaries of other types of permitting authorities).
Moreover, the complexity associated with plans involving multiple
permitting authorities is not a basis for limiting interstate
averaging. An averaging plan can involve multiple permitting
authorities even if it is limited to a single State since local air
pollution control agencies in a State can be permitting authorities.
Overall, the EPA can find no statutory authority to limit NOX
averaging pools to one State or permitting authority for companies that
have holdings across State lines.
Although permitting across State lines is a complicated process,
EPA feels it has addressed the associated logistical problems. The Act
provides for alternative contemporaneous emissions limits to provide a
mechanism for an enforceable approach to this situation. By requiring
unit-specific NOX limits for all members of an averaging pool, EPA
has attempted to ensure that liability is easily identifiable and
enforcement is simplified as much as possible. Any unit in excess of
its limit will be in violation and will only be able to avoid paying
the $2,000 per ton fee under 40 CFR part 77 by demonstrating that its
entire averaging pool meets the standard for group compliance.
The EPA is sensitive, however, to State concerns that they have
adequate time to permit an interstate averaging plan. The EPA agrees
with commenters that the deadlines in the proposal are inadequate.
Thus, EPA has changed the required lead time for the submittal of an
averaging plan involving units under more than one permitting authority
from June 30 of the year in which the plan takes effect, to January 1
of that year. The date for the filing of an averaging plan involving
units under only one permitting authority is also changed in the final
rule to June 30 of the year in which the plan is to take effect.
The EPA agrees that the permitting authorities must be held
accountable for acting on averaging plans submitted to them. Both for
averaging plans within one permitting authority's jurisdiction and for
multi-jurisdictional averaging plans, final action must be taken by the
permitting authorities within six months of the date of submittal.
If final action is not taken within six months, the plan will go
into effect as submitted unless the permitting authority notifies the
utility, in writing, that, due to flaws in or the need for revisions to
the plan, it cannot be finalized on time. This must be done prior to
the end of the six month period.
This deadline for approving interstate averaging plans is designed
to allow utilities whose plans involving multiple permitting
authorities are disapproved an opportunity to submit new plans
involving one permitting authority prior to the deadline for the same
year.
5. Title IV NOX Program's Relationship to Title I
A major issue is whether affected units subject to the title I
NOX requirements should be allowed in the title IV emissions
averaging pools. Many commenters felt that it was inappropriate for
units that are forced to achieve reductions under another title be
eligible for inclusion in an emissions averaging pool. Although EPA did
not raise, or seek input on, this issue in the proposal, comments were
received during the public comment period, and it is appropriate that
EPA respond.
Comment: Those that opposed the inclusion of title I affected units
in averaging pools argued that NOX averaging plans under the Acid
Rain Program should not be allowed to take credit for NOX controls
required for ozone nonattainment areas under title I. If a unit subject
to an emission limit more stringent than those promulgated under
section 407(b)(1) or (b)(2) (e.g., title I), it is not acceptable, they
argue, that such a unit is able to use compliance with more stringent
limits to increase emission rates at other units not subject to ozone
nonattainment.
These commenters argued that emission rate reductions beyond those
required by section 407 categorical limits should be ``averageable''
only to the extent that they are ``surplus'' or not otherwise required
by Federal law. Trading against title I NOX limits would allegedly
have significant adverse environmental consequences and increase total
regional and national loadings of NOX.
Proponents of allowing title I units to average suggested that EPA
specifically state in the regulation that title I NOX reductions
will not be limited or excluded from NOX emissions averaging. This
will ensure that utilities have maximum flexibility for compliance.
Another commenter suggested that averaging times for reasonably
available control technology (RACT) limits for title I (30 days) are
equivalent to the annual limits for title IV and that title I's limit
should be adopted.
Response: Section 407(e) of the Act does not authorize EPA to
restrict participation in an averaging plan by any units (e.g., units
also required to make NOX reductions under title I) required to
comply with NOX emissions limitations under section 407 when the
plan is in effect. This contrasts with section 404(b)(5), which
concerns substitution plans and expressly requires EPA to ensure that
the plans do not result in fewer SO2 emissions reductions than
without the plans, and section 408(c)(1)(B), which concerns reduced
utilization plans and whose legislative history indicates that such
plans were specifically aimed at protecting the achievement of SO2
emissions reductions under title IV in Phase I; section 407 lacks any
analogous language or underlying legislative history. Thus, allowing
the averaging, under section 407(e), of title I emissions reductions
will not undermine Congressional intent.

D. Early Election

The EPA proposed to allow Phase II units with Group I boilers that
comply with the Phase I annual performance standards on or before
calendar year 1997 to elect to have these units become subject to the
applicable Phase I NOX emission limitations before January 1, 2000
(the date on which the limitations would otherwise apply). As an
incentive to comply early with the Phase I performance standards, these
``early-election units'' were proposed to be exempt from any revision
that might be made to the Group 1, Phase I limitations pursuant to
section 407(b)(2) of the Act. Under section 407(b)(2), the
Administrator ``may revise'' these emission limitations not later than
January 1, 1997, if the Administrator ``determines that more effective
low NOX burner technology is available.'' Section 407(b)(2) makes
clear that no Phase I Group I unit can be subject to such a revised
limitation. (Any revisions to the Phase I limitations for Phase II
units with Group 1 boilers will herein be referred to as the ``Phase II
standards.'') If no revisions are made to the Phase I limitations,
Phase II units with Group 1 boilers will have to meet the Phase I
limitations in the year 2000.
Although title IV of the Act does not explicitly provide for an
early election program, EPA maintains that the establishment of this
type of program is within the Administrator's discretion so long as the
program is consistent with the purposes of section 407 of the Act. The
Agency has carefully evaluated the potential environmental consequences
of specific provisions of an early election program and crafted the
final provisions to ensure that the program will facilitate, and not
compromise, achievement of the purposes of section 407.
Consequently, the provisions for early election units are not
identical to those applicable to Phase I units. For example,
grandfathering from any Phase II standards for early election units is
limited to the period 1997 through 2007, whereas the grandfathering for
Phase I units is indefinite under section 407(b)(2) of the Act. By
further example, in Secs. 76.8 of the final rule, the use of early
election units in averaging plans is more circumscribed than the
averaging of Phase I units under section 407(e) of the Act. In the
absence of these and other appropriate provisions to safeguard
achievement of the purposes of section 407, the Agency would reject the
discretionary adoption of an early election program.
The EPA requested comment on the value and features of the proposed
early election program in the proposed rule. The Agency received 59
comments on early election. The major issues commenters identified for
early election are: the benefits of early election and its inclusion in
the final rule; the date and eligibility for receiving grandfathering;
the ability of early election units to average NOX emissions with
Phase I units; the ability of early election units to average NOX
emissions with Phase II units; the consequences of the failure to
maintain the Phase I standards; and the option to elect out of early
election.
1. The Benefits of Early Election and its Inclusion in the Final Rule
Though no statutory provisions address early election, EPA proposed
to grandfather early election units from any future Phase II standards
in order to encourage early compliance and realize its concomitant
benefits. Such benefits include: (1) Protection of electricity supply
and reliability by reducing the potential for unplanned or overlapping
outages that could occur if all Phase II units wait until the latter
part of the 1990's to retrofit their boilers; and (2) early
environmental benefits from units that might otherwise comply later.
Comment: The majority of the commenters indicated complete support
of the early election proposal. They believe that grandfathering will
provide an incentive for Phase II units to install NOX controls
during planned outages prior to 1997. This in turn will ensure electric
system reliability by spreading out the outages that would have
otherwise had to occur between the years 1997 and 1999 in preparation
for compliance with the Phase II standards by the year 2000. With early
election, utility units that retrofit their boilers between 1994 and
1997 will have certainty as to the standards they need to achieve and
assurance that these standards will not change in the year 2000.
In an attempt to project the environmental benefits from early
election, one commenter's analysis determined that 550,000 additional
tons of NOX would be reduced per year for the years 1996-1999 from
early election. However, this commenter included title I units in its
analysis, likely inflating the benefits of early election because title
I units have to reduce their NOX emissions to levels most likely
below the title IV Phase I standards by 1995 for purposes of title I of
the Act. (See Docket Item IV-D-111.)
Another commenter pointed out that EPA has conducted none of its
own studies or analyses to support the claims that early election will
improve electric reliability or that the early environmental benefits
outweigh the NOX reductions that would otherwise be achieved by
the early election units with lower Phase II standards in the year
2000.
Response: In response to the comments, EPA analyzed the
environmental benefits of early election and also collected data on the
retrofit schedule of the Phase II boilers for compliance in the year
2000. (See Docket Items IV-A-9 and IV-A-11 for the complete details of
the EPA early election analysis.) Based on the analysis and comments
received, EPA has decided to keep early election in the final rule as a
way to encourage early retrofits and relieve the compact outage
schedule, but limit the grandfathering to the year 2007 to ensure that
there will be no adverse effect on the environment in the event that
Phase II emission limitations are made tighter than the limitations in
Phase I.
In the analysis, EPA looked at the worst and best possible outcomes
that early election could have with regard to the environment. In the
worst case scenario, only Phase II units that are already at or below
the Phase I standards (but above the Phase II standards, approximately
26 units) and thus do not need to retrofit to meet the Phase I
standards will early elect. Assuming lower Phase II standards are
promulgated in 1997 (to take effect in 2000), the environment is
adversely affected because those units already at or below the Phase I
standards did not need to reduce to qualify for early election but will
still receive a 7-year deferral from 2000 to 2007, or under the
proposal an indefinite deferral, from having to meet the Phase II
standards. The rest of the Phase II units that did not early elect will
have to meet the Phase II standards in the year 2000. Under this
scenario, approximately 14,700 tons of NOX will be added to the
environment each year from the years 2000-2007 (a cumulative adverse
impact of 117,600 tons). If the Phase II standards are the same as
those for Phase I, then there will be no benefit or harm to the
environment from early election if only units already at or below the
Phase I standards early elect.
In the best case scenario, EPA assumed that 20 percent of the Phase
II units (about 80 units, not including any title I units ((about 184
units)), which have to reduce their NOX emissions to levels most
likely below the title IV Phase I standards by 1995 for purposes of
title I of the Act or any units already at or below the Phase I
standards) will retrofit ahead of their already planned outages due to
the early election policy. If the standards are not revised in 1997,
then there is an environmental benefit of approximately 184,000
additional tons of NOX reduced each year from 1997 to 1999
(552,000 cumulative tons). In this scenario, the benefit of early
election will be the same for each year until 2000 if lower emission
standards are promulgated in 1997 and take effect in 2000. However,
starting in 2000, the cumulative benefits accrued by early election
between 1997 and 2000 begin to diminish if the standards are revised.
The cumulative benefits erode because early election units are allowed
to stay at higher emissions limitations instead of having to meet the
lower Phase II limitations imposed in 2000 on other Phase II units and
approximately 55,700 tons of reductions a year are thereby lost. As a
result, after the year 2010, the cumulative benefits fall below zero
and the environment is actually harmed.
The EPA assumed for the scenarios described above that the Phase II
standards would be 0.43 lbs/mmBtu for wall-fired units and 0.38 lbs/
mmBtu for tangentially-fired units on an annual basis. These standards
have been proposed by the State and Territorial Air Pollution Program
Administrators/Association of Local Air Pollution Control Officials
(STAPPA/ALAPCO) as the RACT standards for NOX under title I of the
Act that units should be able to meet. The EPA used the STAPPA/ALAPCO
standards (even though they are designed for a 30-day rather than 356-
day average) for purposes of the analysis because they are recommended
for State adoption by an established air pollution control association.
However, the use of these standards for the analysis in no way suggests
that EPA will adopt them as the Phase II emission limitations. The
Agency has not yet determined whether revisions to the Phase I
standards are necessary or appropriate.
The EPA then examined a ``realistic'' case scenario of early
election and its effect on the environment. The EPA believes that it is
unlikely that 20 percent of the Phase II units (not including title I
units or units already at or below the Phase I standards) will be able
to early elect because, as discussed below, a large number of retrofits
must be scheduled between 1995 and 1999; nor does it believe that only
title I units and units already at or below the standards will choose
to early elect. The actual number of units that will early elect cannot
be precisely determined in advance; however, EPA estimates that 15
percent of the units will early elect (about 54 units, again excluding
approximately 184 title I units and about 65 units already at or below
the Phase I standards). If 15 percent of these Phase II units early
elect the annual benefit to the environment will be approximately
137,900 tons a year with a cumulative benefit of 413,700 tons for the
years 1997-1999. However, with revised standards taking effect in 2000,
the annual benefits of early election cease in 2000, and the cumulative
benefits cease after the year 2007. This occurs because the cumulative
reductions that would be achieved through the imposition of tighter
Phase II standards eventually become greater than the cumulative
reductions achieved through early election. Therefore, to ensure that
early election has no negative effects on the environment in the event
that lower Phase II standards are promulgated, EPA is limiting
grandfathering to the year 2007 with 2008 being the first year in which
early election units will have to meet any tighter Phase II standards.
If Phase II standards are not tightened, the cessation of the
grandfathering becomes irrelevant.
The EPA originally assumed that only 10 percent of the Phase II
units (again excluding title I units and units already at or below the
Phase I standards) would reduce early because of the early election
incentive. Based on this assumption, EPA initially set the year
grandfathering would end at 2005. (See Docket Item IV-A-9.) After the
analysis was completed however, EPA received late comments from
utilities and the U.S. Department of Energy (DOE) indicating that more
than 10 percent of the Phase II units are likely to retrofit early due
to early election. Furthermore, they argue in their comments that
restricting the grandfathering to the year 2005 is too short and may
have the unintended effect of discouraging participation and denying
expected benefits to the environment. The DOE provided its own analysis
because it believed that EPA's analysis shows overly conservative
results because the analysis does not explore a number of different
possible outcomes. In response, EPA used a similar an ``expected
probability'' approach using assumptions derived from its previous
analysis. EPA found the two analytical approaches to be reasonably
consistent when the same assumptions are used. Thus, the expected
outcome resulting from this analysis confirmed EPA's original results.
(See Docket Items IV-H-2 and IV-B-8.) Based on the comments that more
than 10 percent of the Phase II units would likely early elect, EPA has
run as an addendum to the original analysis a scenario of 15 percent
early election, which shows that the benefits cease in 2007. (See
Docket Item IV-A-11.)
The EPA's analysis confirms the high probability of the year 2007
being the last year of environmental benefit using realistic
assumptions. Thus, EPA is convinced that the 10 percent early election
assumption was unnecessarily conservative and believes using the
midpoint of EPA's probable range (20 percent + 10 percent/2 = 15
percent) is a realistic expectation for the number of units which will
early elect due to this provision.
The selection of the year 2007 as the limit on grandfathering also
makes sense in terms of utilities' planning schedules. The extension of
the possible Phase II compliance date for early election units to
calendar year 2008 allows utilities to utilize installed equipment for
over 10 years without modification prior to any additional NOX
reduction retrofits, if necessary to meet the Phase II limit. Further,
it is expected that this equipment would most likely continue in use
even if the Phase II limit is lower, requiring some degree of
supplementary equipment to lower the emission rate.
There is a possibility, albeit unlikely, that early election could
result in increased NOX emissions of approximately 14,700
additional tons per year (or 117,600 cumulative) from 2000 through the
year 2007, the year early election units must comply with any tighter
Phase II standards. This would occur if few or no Phase II units are
encouraged by the grandfathering benefit to reduce early and only those
already meeting the Phase I standards or reducing for purposes of title
I early elect. The EPA believes that the possibility of this result is
small enough, and the benefits of the more likely result (15 percent
retrofit early due to early election) are great enough that early
election should be allowed.
The Agency also notes that even under the unlikely scenario that
only title I units and units already below the Phase I standards early
elect, early election would facilitate, and make less costly,
achievement of the Phase II NOX reductions for those units that
did not early elect. This is because early election would increase the
use of planned outages between 2000 and 2007 for maintenance, rather
than additional forced outages as would likely be the case if all Phase
II units were required to comply with tighter standards in 2000.
According to the EPA study of the retrofit schedule of Phase II
boilers, about 80 percent (approximately 450 units) of all Phase II
units will need to be shutdown for compliance retrofits between 1997
and 1999. (See Docket Item IV-A-7.) Forced outages result in increased
costs to the utilities and ultimately to consumers. Early election
could encourage Phase II units to install NOX controls during
planned outages either prior to 1997 instead of waiting until the
latter part of the 1990's or between 2000 and 2007.
The EPA considered barring title I units and units already below
the Phase I standards from early electing in order to eliminate the
possibility of any detriment to the environment from early election.
However, EPA has determined, consistent with the approach taken in the
NOX averaging provisions, that inclusion of title I units does not
undermine the purposes of the Act. Further, barring units that were
already below the Phase I standards (e.g., before the November 15, 1990
enactment of title IV) would require demonstrations by each prospective
early election unit that the emission reductions it achieved occurred
after the cutoff date. These requirements would be difficult to
implement because, in many cases, emissions of NOX have not
previously been monitored. The EPA believes that the environmental
integrity of early election is maintained by limiting grandfathering to
the year 2007, and as mentioned in the upcoming discussion, prohibiting
early election units from participating in averaging plans during Phase
I.
2. The Date and Eligibility for Receiving Grandfathering
The proposed rule allowed early election of Phase II units provided
that on or before promulgation of the Phase II standards, the owner or
operator has: (1) Commenced installation of low NOX burner
technology; (2) initiated some other NOX emission control (i.e.,
fuel switching, boiler operational changes); or (3) notified EPA that
the unit has already attained the Phase I standards. The EPA requested
comment on whether the deadline by which a unit must meet one of these
requirements in order to be grandfathered should be the date EPA
proposes Phase II standards rather than the date of promulgation of the
standards. According to the proposal, early election compliance plans
must be submitted to EPA by January 1 of the year for which the
election is to take effect, but not later than January 1, 1997.
Comment: Comments were mixed on this issue. Some commenters wanted
EPA to adopt January 1, 1997, as the date a unit must ``commit'' to
install NOX technology, but not requirements to meet the standards
until 1998. A delayed cutoff would also allow utilities to decide
whether to early elect already knowing whether Phase II standards will
be tightened and if so, what the standards will be. One commenter
believed that January 1, 1997, is ample time for unit modifications and
should be the cutoff date for early election. Another commenter,
claiming that NOX emissions on its Phase II boiler have
historically not been monitored and that time is needed to install
monitors and collect at least a year of data, would like the cutoff
date to be the date of promulgation of the Phase II standards.
Commenters also wanted clarification as to the forms of NOX
control required to be eligible for early election.
Response: The final rule states that eligibility for early election
is based solely on achievement of the Phase I performance standards by
calendar year 1997. In order to eliminate confusion and to avoid
prescribing what forms of NOX controls are allowed for early
election, the final rule simply requires that units must early elect by
no later than January 1, 1997 and demonstrate compliance with the Phase
I standards pursuant to appendix E to part 75 of the regulations by no
later than calendar year 1997.
The EPA believes that demonstration of compliance by 1997 is
reasonable because some units will need to begin NOX retrofits in
1998 anyway in order to meet either the Phase I or Phase II standards
by the year 2000. Thus, allowing units to early elect as late as 1998
is likely to result in no additional benefit to the environment and in
fact will create additional harm to the environment because these units
will be grandfathered from having to meet tighter Phase II standards in
the year 2000. Another argument for demonstration of compliance by the
end of 1997 is the fact that allowing compliance as late as 1998 would
mean that units could make the early election decision after they know
whether the Phase II standards will be tightened and, if so, at what
level. If the Phase II standards are tightened and are considerably
lower than the Phase I standards, it is likely that many units would
early elect to avoid the tighter standards. Early election should not
be used to avoid tighter standards, but as an incentive to reduce early
with the assurance that no additional NOX controls will be
required for a number of years.
3. The Ability of Early Election Units To Average Emissions With Phase
I Units
In the proposed rule, early election units are allowed to
participate in an averaging plan during Phase I provided: (1) The unit
achieves an annual average emission rate less than or equal to the
applicable emission limitation; and (2) the unit applies NOX
emission controls (which can include fuel switching or boiler
operational changes) that reduce the unit's annual emissions rate on or
after November 15, 1990.
Comment: The commenters generally support allowing early election
units to participate in averaging plans during Phase I. They claim that
averaging would encourage use of early election, improve the cost-
effectiveness of averaging plans, and because of the increased number
of units to average with, decrease the number of AELs. A few commenters
would like any unit that meets the Phase I standards to be able to
average regardless of when controls were installed. They claim that the
proposal penalizes those units that have made pre-1990 reductions.
Another commenter is concerned, however, that a Phase II unit that
is already below the Phase I standards, could make a minor modification
to its boiler after November 15, 1990 and thereby become eligible to
average under EPA's proposed rules. This could result in an increase in
total emissions since the actual reduction from the early election unit
would be small, but the unit would make available for averaging the
entire amount of difference between its new emission rate and the Phase
I emission rate. Emission reductions would be lost because Phase I
units in the averaging pool would not need to reduce, or would need to
reduce less, in order to achieve compliance. The commenter wants the
requirements to average limited to ``actual'' reductions achieved below
1990 baseline levels.
Response: The EPA believes that allowing early election units to
average with Phase I units would undermine the required Phase I
NOX reductions that Congress intended under title IV. Even if EPA
only allowed early election units to average ``actual'' reductions
below 1990 baseline levels (assuming such reductions can be determined)
and the Phase I emission reduction goals of the program were met
through averaging, the Clean Air Act's requirement that NOX
emission reductions come from the Phase I units specified in title IV
would be compromised. The statutory compliance options for SO2
allows Phase II units to assure, as substitution units, the SO2
reduction obligations of Phase I units, but there is no analogous
statutory provisions for NOX. The EPA believes it should not
create a discretionary early election program that in effect allows
Phase I units to avoid the NOX reduction requirements of title IV.
Consequently, the final rule bars early election units from averaging
with Phase I units before the year 2000. However, EPA believes it is
reasonable to allow early election units to average with Phase I or
Phase II units in the year 2000. At that time, Phase I sources will
have reduced emissions and the Phase I reduction goals of the program
will have been met.
To determine the effects of averaging in Phase I on the required
Phase I reductions, EPA performed an analysis that simulated averaging
pools of Phase I units that were associated with Phase II units either
through a common holding company or operating utility. This is
consistent with the averaging requirements in the final rule. According
to the EPA analysis, if early election units were allowed to average
with Phase I units, the reductions that would be achieved by the Phase
I units alone (in their own averaging pools) would be diminished by
approximately 15 percent or about 66,000 tons a year until the year
2000. Phase I reductions will equal approximately 493,000 tons per year
without such averaging while they would equal 427,000 tons per year
with such averaging. (See Docket Items IV-A-9 and IV-A-11 for the
complete details of the EPA analysis on early election units and
averaging.)
4. The Ability of Early Election Units to Average Emissions With Phase
II Units
The proposed rule was clear in allowing early election units to
average during Phase I, but silent on their ability to average during
Phase II. Commenters wanted EPA to clearly state that early election
units would be allowed to average during Phase II.
Response: The EPA has decided that early election units can average
with Phase II units starting in the year 2000, provided that in the
averaging plan, early election units are subject to the emissions
limitations in effect for the Phase II units, and not the emissions
limitations at which they were grandfathered, if the emissions
limitations differ.
To illustrate the reason for this decision, assume the Phase II
standards are lowered in the year 2000 to (0.43 lb/mmBtu and 0.38 lb/
mmBtu) and early election units were allowed to participate in
averaging pools at their grandfathered rate (0.5 lb/mmBtu and 0.45 lb/
mmBtu). A wall-fired early election unit that operates at an annual
emission rate of 0.44 lb/mmBtu but is subject to the Phase I emission
rate of 0.5 lb/mmBtu, participates in an averaging plan with a wall-
fired Phase II unit that operates at an annual emission rate of 0.46
lb/mmBtu but is subject to the lower Phase II emission rate of 0.43 lb/
mmBtu. The annual heat inputs of both these units is 2 million mmBtu
for purposes of simplicity. According to the final rule, the Btu-
weighted annual average emission rate averaged over the units in the
plan must be less than or equal to the Btu-weighted annual average
emission rate for the same units had each been in compliance with the
applicable emission limitations (i.e., the average of each unit's
actual emission rate must be less than or equal to the average of each
unit's allowable emission rate). This scenario would translate into the
following averaging plan:

TR22MR94.000

The annual average emission rate of 0.47 lb/mmBtu, however, is
above the annual average emission rate of 0.43 lb/mmBtu that would have
been required for these two units had each been in compliance with the
Phase II standard of 0.43 lb/mmBtu. Therefore, whenever an averaging
plan involved an early election unit at its grandfathered limit, the
result could be a higher Btu-weighted annual average emission rate for
the pool than would have otherwise occurred, resulting in a loss of
expected emissions reductions. Again, EPA does not believe it should
compromise required Phase II NOX reductions through the
discretionary establishment of early elections and should require early
election units to average at the same standard that is required for
other Phase II units.
5. The Consequences of the Failure To Maintain the Phase I Standards
The EPA did not address in the proposed rule the consequences of a
unit failing to maintain the Phase I standards after it has early
elected. Commenters asked EPA to address this issue in the final rule.
Response: If an early election unit fails to maintain the Phase I
standards, it is no longer eligible to receive grandfathering status.
The unit must: (1) Meet the required standards for Phase II units in
the year 2000 if the failure occurs before 2000; or (2) meet the
required standards for Phase II units in the year immediately following
the year of failure if the failure occurs during or after 2000. In
addition, the unit violating the Phase I standard during or after 2000,
will be subject to excess emissions provisions for the year of
noncompliance with the Phase I standard. In either case, the unit may
during or after 2000, apply for an AEL, if necessary, according to the
procedures stated in the rule; or participate in a Phase II averaging
plan. Once an early election unit fails to meet the standards, it can
not regain its grandfathering status or submit a new early election
plan even if it achieves the Phase I standards again after the
violation.
Upon failure to meet the Phase I standards, early election units
will lose their grandfathering status immediately, and be subject to
the same standards as other Phase II units depending on when the
violation occurred. This is reasonable because if early election units
fail to comply early (i.e., prior to 2000), this violates the primary
purpose of, and reduces the expected benefit to the environment from,
early election. Moreover, if early election units that fail to comply
with the unrevised Phase I limitations after 2000, but continued to be
grandfathered, they would be subject to penalties only for emissions in
excess of the unrevised Phase I limitations, not for emissions in
excess of any revised more stringent limitations. The purpose of early
election is to obtain early compliance, not to reduce liability for
noncompliance.
6. The Option To Elect Out of Early Election
The issue of whether early election units should be able to elect
out of early election before the end of 2007 was not mentioned in the
proposed rule or addressed by the commenters.
Response: The EPA believes that early election units should be
allowed to elect out of early election once they have committed to it.
Since early election is voluntary, units should have the option of
ceasing early election status if they so choose. However, once a unit
ceases early election, it cannot be reinstated. Electing out and back
in (after the year 2000) could be used as a way to avoid compliance
penalties if a unit foresees a likely emissions violation in the
future. To assure all compliance obligations are met by early election
units wanting to elect out of early election, termination of early
election and subjection to any applicable Phase II standards will
become effective at the start of a new year, following submission of a
notice to the appropriate permitting authority made no later than
January 1 of the year the unit chooses to terminate early election
status.

E. Banking Issues

In the preamble to the notice of proposed rulemaking, EPA
specifically solicited comment on whether ``banking'' of excess
NOX reductions should be allowed. (See 57 FR 55656, November 25,
1992.) As described in the proposal, NOx banking means giving
credit for emissions averaging that results in a group annual average
emissions rate that is lower than the maximum allowed under this rule.
The proposal also noted that the emissions that could be ``banked''
would only be those that exceeded title I nonattainment requirements
for those sources in nonattainment areas. As outlined in the proposal,
excess reductions could be allocated to individual units within the
averaging pool for subsequent calendar years or could be transferred to
other accounts and used to offset excess emissions in averaging plans
for the same or subsequent calendar years that resulted in emissions
greater than what would have occurred had the units operated at the
limits set by the rule.
Comment: Several commenters urged that EPA had the discretionary
authority under section 401(b) of the Act to allow banking as an
alternative means of complying with section 407(e). Section 401(b) of
the statute which sets forth the general purposes of for title IV
states that reductions of SO2 and NOX emissions may be met
``through alternative methods of compliance provided by an emissions
allocation and transfer system.'' Section 407(e) specifies the
emissions averaging plan for NOX emissions. It provides:

In lieu of complying with the applicable limitations under
subsection (b) (1), (2), or (d), the owner or operator of two or
more units subject to one or more of the applicable emission
limitations set pursuant to these sections, may petition the
permitting authority for alternative contemporaneous annual emission
limitations for such units that ensure that (1) the actual annual
emission rate in pounds of nitrogen oxides per million Btu averaged
over the units in question is a rate that is less than or equal to
(2) the Btu-weighted average annual emission rate for the same units
if they had been operated, during the same period of time, in
compliance with limitations set in accordance with the applicable
emission rates set pursuant to subsections (b) (1) and (2).
The question is whether the ``banking system'' described in the
proposal falls within the emissions averaging scheme contemplated by
Congress. The EPA also specifically sought comment on the usefulness
and environmental benefits of such a banking system.
Response: After a careful review of the comments and the underlying
statutory provisions, EPA has decided not to include a ``banking''
scheme as a part of emissions averaging. The EPA believes that the
language of section 407(e) providing EPA the authority to establish
emissions averaging does not encompass emissions banking as discussed
in the November 1992 proposal. Moreover, considering the NOX
emissions reductions provisions of section 407 as a whole, EPA
concludes that such banking is outside the statutory framework.
In section 407, Congress established a scheme whereby certain
emission limits were to be met and provided limited exceptions to
meeting those requirements e.g., an AEL, a NOx extension, or
emissions averaging. The NOX provisions, unlike the SO2
provisions, do not establish an allowance trading program. There are no
emissions caps or allowances under section 407. The absence of
provisions similar to the SO2 allowance trading provisions for NOX
is a strong indication that Congress did not intend to include a
NOX trading program.
This position is further supported by examining the legislative
history development of the NOx provisions. Earlier versions of the
1990 Amendments provided for NOx allowances and trading. These
provisions were ultimately deleted by Congress and replaced with the
averaging and AEL provisions. In contrast, Congress explicitly included
a banking and allowance program for the SO2 emissions. Thus, the
language and history of the statute indicate Congress did not intend to
establish banking for NOx at this time. Indeed, it specifically
considered and deleted such a provision before final passage of title
IV. Accordingly, EPA has decided not to include ``banking'' for
NOx emissions under section 407.
In addition to the language of the statute, the comments in
response to the proposal did not demonstrate any significant
environmental benefits that may arise from allowing banking. On the
other hand, several commenters expressed significant concern about the
ability to enforce and implement banking, particularly if banking were
allowed from one year to the next.

IV. Administrative Requirements

A. Docket

A docket is an organized and complete file of all the information
considered by EPA in the development of this rulemaking. The docket is
a dynamic file, since material is added throughout the rulemaking
development. The docketing system is intended to allow members of the
public and industries involved to readily identify and locate documents
so that they can effectively participate in the rulemaking process.
Along with the preamble of the proposed and final rule and EPA
responses to significant comments, the contents of the docket, except
for interagency review materials, will serve as the record in case of
judicial review. (See section 307(d)(7)(A).)

B. Executive Order 12866

Under Executive Order 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. The Order defines
``significant regulatory action'' as one that is likely to result in a
rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
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 will have an annual effect on the economy of approximately
$300 million. As such, this action was submitted to OMB for review.
Changes made in response to OMB suggestions or recommendations will be
documented in the public record.
In developing the final regulation, EPA considered several
regulatory options that were designed either to increase flexibility
and lower compliance costs or to evaluate the effects of requiring
different levels of technology for AEL eligibility. A total of three
distinct options plus two additional variants of one of the options
were analyzed using EPA's model. Under Option 1, wall-fired boilers
must install LNBs with OFA to qualify for an AEL, and tangentially
fired boilers must install low NOX coal and air nozzles with both
close-coupled and separated OFA (LNC 3). Under Option 2, wall-fired
boilers need install only LNBs without OFA to qualify for an AEL, and
tangentially fired boilers must install LNC 3. Option 3 is the same as
Option 2 for wall-fired boilers, but requires only low NOX coal
and air nozzles with close-coupled OFA for tangentially fired boilers
to qualify for an AEL. EPA also considered two variants of Option 1. In
one variant, a more limited version of emissions averaging would be
allowed; the emissions of a given unit could be averaged only within
the same state. In the other variant, no averaging would be allowed at
all; every unit would be required either to meet its presumptive limit
or to qualify for an AEL.
The option chosen by EPA (Option 1) is judged to be the optimum
selection. Option 1 with interstate averaging has the lowest cost per
ton of NOX removed ($159 per ton in Phase II). It achieves greater
emission reductions than the less stringent options, at a total cost
that is not much higher. In addition, it imposes a lower cost than the
less flexible variants while maintaining high NOX reductions.
Option 2 was found to have a total tonnage removal and total cost (1.86
million tons and $296 million in Phase II) similar to those under
Option 1, based on the assumption in EPA's model that the use of burner
technology would evolve in the same way under both options. However, as
presented in Section III.A.1 of this preamble, Option 2 as well as
Option 3 are inconsistent with the statutory language and the
fundamental chemical process of low NOX combustion. Additionally,
EPA believes that the NOX emission reductions achieved in practice
under either Option 2 or Option 3 could be significantly lower than
those predicted by EPA's model because the use of burner technology
would likely be different than under Option 1. Under Options 2 and 3
(but not under Option 1), units with poorly performing NOX
emission controls may qualify for alternative emission limitations,
rather than meeting the performance standard.
The annual emission reductions associated with the final rule are
estimated to be approximately 400,000 tons in Phase I, and 1.89 million
tons in Phase II. The emission reductions are projected to impose
annual costs ranging from approximately $77 million in Phase I, to $300
million in Phase II, resulting in an average national increase to the
average consumer's monthly electric bill of 0.13 percent in Phase II.
The early election program is expected to lower compliance costs for
some utility units if more stringent emission limitations for Phase II
units are promulgated. It is not, however, expected to significantly
impact the national cost of this rule. As presented in Section III.D of
this preamble, the cost reductions achieved through the early election
provision are expected to be accompanied by a net environmental benefit
over the life of the program.
The EPA does not anticipate major increases in prices, costs, or
other significant adverse effects on competition, investment,
productivity, or innovation or on the ability of U.S. enterprises to
compete with foreign enterprises in domestic or foreign markets due to
the final regulations.
In assessing the impacts of a regulation, it is important to
examine: (1) The costs to the regulated community, (2) the costs that
are passed on to customers of the regulated community, and (3) the
impact of these cost increases on the financial health and
competitiveness of both the regulated community and their customers.
The costs of this regulation to electric utilities are generally very
small relative to their annual revenues. (However, the relative amount
of the costs will definitely vary in individual cases.) Moreover, EPA
expects that most or all utility expenses from meeting NOX
requirements will be passed along to ratepayers. Consequently, the
regulations are not likely to have an impact on utility profits or
competitiveness.
Under today's rule the cost to ratepayers is very small, relative
to their current expenditures on electricity. The average increase in
electric rates across the United States is estimated to be only 0.03
and 0.13 percent under Phases I and II respectively.
The final regulation presented in this notice was submitted to the
OMB for review as required by Executive Order 12886. Any written
comments from OMB to EPA and any written EPA response to those comments
will be included in the docket. The docket is available for public
inspection at the EPA's Air Docket Section, which is listed in the
ADDRESSES section of this preamble.

C. Paperwork Reduction Act

The OMB has approved the information collection requirements
contained in this rule under the provisions of the Paperwork Reduction
Act of 1980, 44 U.S.C. 3501, et seq., and has assigned OMB control
number 2060-0258.
The control numbers assigned to collections of information in
certain EPA regulations by the OMB have been consolidated under 40 CFR
part 9. The information collection request for this rule was previously
subject to public notice and comment prior to OMB approval. As a
result, the EPA finds there is ``good cause'' under sections 553(b)(B)
and 553(d)(3) of the Administrative Procedure Act to amend the
applicable table in 40 CFR part 9 to display the OMB control number for
this rule without prior notice and comment. Due to the technical nature
of the table, further notice and comment would be unnecessary. For
additional information, see 58 FR 18014, April 7, 1993, and 58 FR
27472, May 10, 1993.
Public reporting burden for this collection of information is
estimated at 27,510 hours for all respondents through May 15, 1995.
This estimate includes time for reviewing instructions, searching
existing data sources, gathering and maintaining the data needed, and
completing and reviewing the collection of information.
Send comments regarding this burden estimate or any other aspect
of this collection of information, including suggestions for reducing
the burden, to Chief, Information Policy Branch (PM-223Y), U.S.
Environmental Protection Agency, 401 M Street SW., Washington, DC
20460; and to the Paperwork Reduction Project, Office of Information
and Regulatory Affairs, Office of Management and Budget, 726 Jackson
Place NW., Washington, DC 20503, marked ``Attention: Desk Officer for
EPA.''

D. Regulatory Flexibility Act

The Regulatory Flexibility Act (5 U.S.C. 601, et seq.) requires EPA
to consider potential impacts of proposed regulations on small business
``entities.'' If a preliminary analysis indicates that a proposed
regulation would have a significant economic impact on 20 percent or
more of small entities, then a regulatory flexibility analysis must be
prepared.
Current Regulatory Flexibility Act guidelines indicate that an
economic impact should be considered significant if it meets one of the
following criteria: (1) Compliance increases annual production costs by
more than 5 percent, assuming costs are passed onto consumers; (2)
compliance costs as a percentage of sales for small entities are at
least 10 percent more than compliance costs as a percentage of sales
for large entities; (3) capital costs of compliance represent a
``significant'' portion of capital available to small entities,
considering internal cash flow plus external financial capabilities; or
(4) regulatory requirements are likely to result in closures of small
entities.
Under the Act, a small business is any ``small business concern''
as identified by the Small Business Administration under section 3 of
the Small Business Act. As of January 1, 1991, the Small Business
Administration had established the size threshold for small electric
services companies at 4 million megawatt hours per year. Because all of
the utilities affected by Phase I of the acid rain regulations have
generating capacities greater than 4 million megawatt hours, EPA
believes that no small businesses are affected by today's final rule.
(The EPA's initial estimates are that the burden on small utilities
under Phase II is minimal.)
Pursuant to the provisions of 5 U.S.C. 605(b), I hereby certify
that this rule, if promulgated, will not have a significant adverse
impact on a substantial number of small entities.

E. Miscellaneous

In accordance with section 117 of the Act, publication of this rule
was preceded by consultation with appropriate advisory committees,
independent experts, and Federal departments and agencies.

List of Subjects in 40 CFR Part 76

Environmental protection, Acid rain program, Air pollution control,
Nitrogen oxide, Incorporation by reference, Reporting and recordkeeping
requirements.

Dated: February 28, 1994.
Carol M. Browner,
Administrator.
Title 40, chapter I, of the Code of Federal Regulations is amended
as follows:

PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT

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

Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003,
2005, 2006, 2601-2671, 7601; 21 U.S.C. 331j, 346a, 348; 31 U.S.C.
9701; 33 U.S.C. 1251 et seq., 1311, 1313d, 1314, 1321, 1326, 1330,
1344, 1345(d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR, 1971-
1975 Comp., p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g, 300g-
1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2, 300j-3,
300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q, 7542, 9601-
9657, 11023, 11048.

2. Section 9.1 is amended by adding a new heading to the table
after ``Continuous Emission Monitoring'' and an entry under the new
heading to read as follows:

Sec. 9.1 OMB approvals under the Paperwork Reduction Act.

* * * * *

------------------------------------------------------------------------
OMB control
40 CFR citation No.
------------------------------------------------------------------------

*****
Nitrogen Oxides Emission Reduction Program................. 76.8-76.15

*****
------------------------------------------------------------------------

3. Part 76 is added to read as follows:

PART 76--ACID RAIN NITROGEN OXIDES EMISSION REDUCTION PROGRAM

Sec.

76.1 Applicability.
76.2 Definitions.
76.3 General Acid Rain Program provisions.
76.4 Incorporation by reference.
76.5 NOX emission limitations for Group 1 boilers.
76.6 NOX emission limitations for Group 2 boilers. [Reserved]
76.7 Revised NOX emission limitations for Group 1, Phase II
boilers. [Reserved]
76.8 Early election for Group 1, Phase II boilers.
76.9 Permit application and compliance plans.
76.10 Alternative emission limitations.
76.11 Emissions averaging.
76.12 Phase I NOX compliance extensions.
76.13 Compliance and excess emissions.
76.14 Monitoring, recordkeeping, and reporting.
76.15 Test methods and procedures.
76.16 [Reserved].

Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units With
Group 1 or Cell Burner Boilers

Appendix B to Part 76--Procedures and Methods for Estimating Costs of
Nitrogen Oxides Controls Applied to Group 1, Phase I Boilers

Authority: 42 U.S.C. 7601 and 7651 et seq.

Sec. 76.1 Applicability.

(a) Except as provided in paragraphs (b) through (d) of this
section, the provisions apply to each coal-fired utility unit that is
subject to an Acid Rain emissions limitation or reduction requirement
for SO2 under Phase I or Phase II pursuant to sections 404, 405,
or 409 of the Act.
(b) The emission limitations for NOX under this part apply to
each affected coal-fired utility unit subject to section 404(d) or
409(b) of the Act on the date the unit is required to meet the Acid
Rain emissions reduction requirement for SO2.
(c) The provisions of this part apply to each coal-fired
substitution unit or compensating unit, designated and approved as a
Phase I unit pursuant to Secs. 72.41 or 72.43 of this chapter as
follows:
(1) A coal-fired substitution unit that is designated in a
substitution plan that is approved and active as of January 1, 1995
shall be treated as a Phase I coal-fired utility unit for purposes of
this part. In the event the designation of such unit as a substitution
unit is terminated after December 31, 1995, pursuant to Sec. 72.41 of
this chapter and the unit is no longer required to meet Phase I
SO2 emissions limitations, the provisions of this part (including
those applicable in Phase I) will continue to apply.
(2) A coal-fired substitution unit that is designated in a
substitution plan that is not approved or not active as of January 1,
1995, or a coal-fired compensating unit, shall be treated as a Phase II
coal-fired utility unit for purposes of this part.
(d) The provisions of this part for Phase I units apply to each
coal-fired transfer unit governed by a Phase I extension plan, approved
pursuant to Sec. 72.42 of this chapter, on January 1, 1997.
Notwithstanding the preceding sentence, a coal-fired transfer unit
shall be subject to the Acid Rain emissions limitations for nitrogen
oxides beginning on January 1 of any year for which a transfer unit is
allocated fewer Phase I extension reserve allowances than the maximum
amount that the designated representative could have requested in
accordance with Sec. 72.42(c)(5) of this chapter (as adjusted under
Sec. 72.42(d) of this chapter) unless the transfer unit is the last
unit allocated Phase I extension reserve allowances under the plan.

Sec. 76.2 Definitions.

All terms used in this part shall have the meaning set forth in the
Act, in Sec. 72.2 of this chapter, and in this section as follows:
Alternative contemporaneous annual emission limitation means the
maximum allowable NOX emission rate (on a lb/mmBtu, annual average
basis) assigned to an individual unit in a NOX emissions averaging
plan pursuant to Sec. 76.11.
Alternative technology means a control technology for reducing
NOX emissions that is outside the scope of the definition of low
NOX burner technology.
Approved clean coal technology demonstration project means a
project using funds appropriated under the Department of Energy's
``Clean Coal Technology Demonstration Program,'' up to a total amount
of $2,500,000,000 for commercial demonstration of clean coal
technology, or similar projects funded through appropriations for the
Environmental Protection Agency. The Federal contribution for a
qualifying project shall be at least 20 percent of the total cost of
the demonstration project.
Cell burner boiler means a wall-fired boiler that utilizes two or
three circular burners combined into a single vertically oriented
assembly that results in a compact, intense flame. Any low NOX
retrofit of a cell burner boiler that reuses the existing cell burner,
close-coupled wall opening configuration would not change the
designation of the unit as a cell burner boiler.
Coal-fired utility unit means a utility unit in which the
combustion of coal (or any coal-derived fuel) on a Btu basis exceeds
50.0 percent of its annual heat input, for Phase I units in calendar
year 1990 and, for Phase II units in the calendar year 1995. For the
purposes of this part, this definition shall apply notwithstanding the
definition at Sec. 72.2 of this chapter.
Combustion air staging means a combustion control that reduces
NOX formation by redistributing combustion air within and above
the combustion zone.
Cyclone boiler means a boiler with one or more water-cooled
horizontal cylindrical chambers in which coal combustion takes place.
The horizontal cylindrical chamber(s) is (are) attached to the bottom
of the furnace. One or more cylindrical chambers are arranged either on
one furnace wall or on two opposed furnace walls. Gaseous combustion
products exiting from the chamber(s) turn 90 degrees to go up through
the boiler while coal ash exits the bottom of the boiler as a molten
slag.
Demonstration period means a period of time not less than 15
months, approved under Sec. 76.10, for demonstrating that the affected
unit cannot meet the applicable emission limitation under Secs. 76.5,
76.6, or 76.7 and establishing the minimum NOX emission rate that
the unit can achieve during long-term load dispatch operation.
Dry bottom means the boiler has a furnace bottom temperature below
the ash melting point and the bottom ash is removed as a solid.
Economizer means the lowest temperature heat exchange section of a
utility boiler where boiler feed water is heated by the flue gas.
Flue gas means the combustion products arising from the combustion
of fossil fuel in a utility boiler.
Group 1 boiler means a tangentially fired boiler or a dry bottom
wall-fired boiler (other than a unit applying cell burner technology).
Group 2 boiler means a wet bottom wall-fired boiler, a cyclone
boiler, a boiler applying cell burner technology, a vertically fired
boiler, an arch-fired boiler, or any other type of utility boiler (such
as a fluidized bed or stoker boiler) that is not a Group 1 boiler.
Low NOX burners and low NOX burner technology means
commercially available combustion modification NOX controls that
minimize NOX formation by introducing coal and its associated
combustion air into a boiler such that initial combustion occurs in a
manner that promotes rapid coal devolatilization in a fuel-rich (i.e.,
oxygen deficient) environment and introduces additional air to achieve
a final fuel-lean (i.e., oxygen rich) environment at points downstream
of the initial flame to complete the combustion process, with such
staged combination of coal and air to include any combination of coal
and air nozzles or ports located consistent with accepted combustion
system design practices and not restricted to location within the
boiler, including aspects of low NOX combustion modifications
commonly referred to as NOX ports, tertiary air ports, overfire
air ports, or staged combustion ports, and excluding low NOX
combustion modifications commonly referred to as reburning.
Low NOX coal and air nozzles means coal and air nozzles for
tangentially fired boilers designed to inhibit the formation of
NOX. The air nozzles are horizontally and vertically adjustable
and control the mixing of fuel and air to achieve combustion air
staging within and above the bulk flame. The coal nozzles have tips
designed to accelerate coal devolatilization near the tip.
Operating period means a period of time of not less than three
consecutive months and that occurs not more than one month prior to
applying for an alternative emission limitation demonstration period
under Sec. 76.10, during which the owner or operator of an affected
unit that cannot meet the applicable emission limitation:
(1) Operates the installed NOX emission controls in accordance
with primary vendor specifications and procedures, with the unit
operating under normal conditions; and
(2) Records and reports quality-assured continuous emission
monitoring (CEM) and unit operating data according to the methods and
procedures in part 75 of this chapter.
Primary vendor means the vendor of the NOX emission control
system who has primary responsibility for providing the equipment,
service, and technical expertise necessary for detailed design,
installation, and operation of the controls, including process data,
mechanical drawings, operating manuals, or any combination thereof.
Reburning means reducing the coal and combustion air to the main
burners and injecting a reburn fuel (such as gas or oil) to create a
fuel-rich secondary combustion zone above the main burner zone and
final combustion air to create a fuel-lean burnout zone. The formation
of NOX is inhibited in the main burner zone due to the reduced
combustion intensity, and NOX is destroyed in the fuel-rich
secondary combustion zone by conversion to molecular nitrogen.
Selective catalytic reduction means a noncombustion control
technology that destroys NOX by injecting a reducing agent (e.g.,
ammonia) into the flue gas that, in the presence of a catalyst (e.g.,
vanadium, titanium, or zeolite), converts NOX into molecular
nitrogen and water.
Selective noncatalytic reduction means a noncombustion control
technology that destroys NOX by injecting a reducing agent (e.g.,
ammonia, urea, or cyanuric acid) into the flue gas, downstream of the
combustion zone that converts NOX to molecular nitrogen, water,
and when urea or cyanuric acid are used, to carbon dioxide (CO2).
Stoker boiler means a boiler that burns solid fuel in a bed, on a
stationary or moving grate, that is located at the bottom of the
furnace.
Tangentially fired boiler means a boiler that has coal and air
nozzles mounted in each corner of the furnace where the vertical
furnace walls meet. Both pulverized coal and air are directed from the
furnace corners along a line tangential to a circle lying in a
horizontal plane of the furnace.
Turbo-fired boiler means a pulverized coal, wall-fired boiler with
burners arranged on walls so that the individual flames extend down
toward the furnace bottom and then turn back up through the center of
the furnace.
Wall-fired boiler means a boiler that has pulverized coal burners
arranged on the walls of the furnace. The burners have discrete,
individual flames that extend perpendicularly into the furnace area.
Wet bottom means the boiler has a furnace bottom temperature above
the ash melting point and the bottom ash is removed as a liquid.

Sec. 76.3 General Acid Rain Program provisions.

The following provisions of part 72 of this chapter shall apply to
this part:
(a) Sec. 72.2 (Definitions);
(b) Sec. 72.3 (Measurements, abbreviations, and acronyms);
(c) Sec. 72.4 (Federal authority);
(d) Sec. 72.5 (State authority);
(e) Sec. 72.6 (Applicability);
(f) Sec. 72.7 (New unit exemption);
(g) Sec. 72.8 (Retired units exemption);
(h) Sec. 72.9 (Standard requirements);
(i) Sec. 72.10 (Availability of information); and
(j) Sec. 72.11 (Computation of time).
In addition, the procedures for appeals of decisions of the
Administrator under this part are contained in part 78 of this chapter.

Sec. 76.4 Incorporation by reference.

(a) The materials listed in this section are incorporated by
reference in the sections noted. These incorporations by reference
(IBR's) were approved by the Director of the Federal Register in
accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are
incorporated as they existed on the date of approval, and notice of any
change in these materials will be published in the Federal Register.
The materials are available for purchase at the corresponding address
noted below and are available for inspection at the Office of the
Federal Register, 800 North Capitol Street, NW., 7th Floor, suite 700,
Washington, DC, at the Public Information Reference Unit, U.S. EPA, 401
M Street, SW., Washington, DC, and at the Library (MD-35), U.S. EPA,
Research Triangle Park, North Carolina.
(b) The following materials are available for purchase from at
least one of the following addresses: American Society for Testing and
Materials (ASTM), 1916 Race Street, Philadelphia, Pennsylvania 19103;
or the University Microfilms International, 300 North Zeeb Road, Ann
Arbor, Michigan 48106.
(1) ASTM D 3176-89, Standard Practice for Ultimate Analysis of Coal
and Coke, IBR approved March 22, 1994 for Sec. 76.15.
(2) ASTM D 3172-89, Standard Practice for Proximate Analysis of
Coal and Coke, IBR approved March 22, 1994 for Sec. 76.15.
(c) The following material is available for purchase from the
American Society of Mechanical Engineers (ASME), 22 Law Drive, Box
2350, Fairfield, NJ 07007-2350.
(1) ASME Performance Test Code 4.2 (1991), Test Code for Coal
Pulverizers, IBR approved March 22, 1994 for Sec. 76.15.
(2) [Reserved]
(d) The following material is available for purchase from the
American National Standards Institute, 11 West 42nd Street, New York,
NY 10036 or from the International Organization for Standardization
(ISO), Case Postale 56, CH-1211 Geneve 20, Switzerland.
(1) ISO 9931 (December 1991) ``Coal--Sampling of Pulverized Coal
Conveyed by Gases in Direct Fired Coal Systems,'' IBR approved March
22, 1994 for Sec. 76.15.
(2) [Reserved]

Sec. 76.5 NOX emission limitations for Group 1 boilers.

(a) Beginning January 1, 1995, or for a unit subject to section
404(d) of the Act, the date on which the unit is required to meet Acid
Rain emission reduction requirements for SO2, the owner or
operator of a Phase I coal-fired utility unit with a tangentially fired
boiler or a dry bottom wall-fired boiler (other than units applying
cell burner technology) shall not discharge, or allow to be discharged,
emissions of NOX to the atmosphere in excess of the following
limits, except as provided in paragraphs (c) or (e) of this section or
in Secs. 76.10, 76.11, or 76.12:
(1) 0.45 lb/mmBtu of heat input on an annual average basis for
tangentially fired boilers.
(2) 0.50 lb/mmBtu of heat input on an annual average basis for dry
bottom wall-fired boilers (other than units applying cell burner
technology).
(b) The owner or operator shall determine the annual average
NOX emission rate, in lb/mmBtu, using the methods and procedures
specified in part 75 of this chapter.
(c) Unless the unit meets the early election requirement of
Sec. 76.8, the owner or operator of a coal-fired substitution unit with
a tangentially fired boiler or a dry bottom wall-fired boiler (other
than units applying cell burner technology) that satisfies the
requirements of Sec. 76.1(c)(2), shall comply with the NOX
emission limitations that apply to Group 1, Phase II boilers.
(d) The owner or operator of a Phase I unit with a cell burner
boiler that converts to a conventional wall fired boiler on or before
January 1, 1995 or, for a unit subject to section 404(d) of the Act,
the date the unit is required to meet Acid Rain emissions reduction
requirements for SO2 shall comply, by such respective date with
the NOX emissions limitation for dry bottom wall-fired boilers
specified in paragraph (a)(2) of this section.
(e) The owner or operator of a Phase I unit with a Group 1 boiler
that converts to a fluidized bed or other type of utility boiler not
included in Group 1 boilers on or before January 1, 1995 or, for a unit
subject to section 404(d) of the Act, the date the unit is required to
meet Acid Rain emissions reduction requirements for SO2 is exempt
from the NOX emissions limitations specified in paragraph (a) of
this section, but shall comply with the NOX emission limitations
for Group 2 boilers under Sec. 76.6.
(f) Except as provided in Sec. 76.8 and in paragraph (c) of this
section, each unit subject to the requirements of this section is not
subject to the requirements of Sec. 76.7.
(g) Beginning January 1, 2000, the owner or operator of a Group 1,
Phase II coal-fired utility unit with a tangentially fired boiler or a
wall-fired boiler shall be subject to the emission limitations in
paragraph (a) of this section, except that if the emission limitations
are revised for Group 1 boilers pursuant to section 407(b)(2) of the
Act, the owner or operator shall be subject to the revised emission
limitations beginning January 1, 2000.

Sec. 76.6 NOX emission limitations for Group 2 boilers.
[Reserved]

Sec. 76.7 Revised NOX emission limitations for Group 1, Phase II
boilers. [Reserved]

Sec. 76.8 Early election for Group 1, Phase II boilers.

(a) General provisions. (1) The owner or operator of a Phase II
coal-fired utility unit with a Group 1 boiler may elect to have the
unit become subject to the applicable emissions limitation for NOX
under Sec. 76.5, starting no later than January 1, 1997.
(2) The owner or operator of a Phase II coal-fired utility unit
with a Group 1 boiler that elects to become subject to the applicable
emission limitation under Sec. 76.5 shall not be subject to any revised
NOX emissions limitation for Group 1 boilers that the
Administrator may issue pursuant to section 407(b)(2) of the Act until
January 1, 2008, provided the designated representative demonstrates
that the unit is in compliance with the limitation under Sec. 76.5,
using the methods and procedures specified in part 75 of this chapter,
for the period beginning January 1 of the year in which the early
election takes effect (but not later than January 1, 1997) and ending
December 31, 2007.
(3) The owner or operator of any Phase II unit with a cell burner
boiler that converts to conventional burner technology may elect to
become subject to the applicable emissions limitation under Sec. 76.5
for dry bottom wall-fired boilers, provided the owner or operator
complies with the provisions in paragraph (a)(2) of this section.
(4) The owner or operator of a Phase II unit approved for early
election shall not submit an application for an alternative emissions
limitation demonstration period under Sec. 76.10 until the earlier of:
(i) January 1, 2008; or
(ii) Early election is terminated pursuant to paragraph (e)(3) of
this section.
(5) The owner or operator of a Phase II unit approved for early
election may not incorporate the unit into an averaging plan prior to
January 1, 2000. On or after January 1, 2000, for purposes of the
averaging plan, the early election unit will be treated as subject to
the applicable emissions limitation for NOX for Phase II units
with Group 1 boilers under Secs. 76.5(g) and if revised emission
limitations are issued for Group 1 boilers pursuant to section
407(b)(2) of the Act, Sec. 76.7.
(b) Submission requirements. In order to obtain early election
status, the designated representative of a Phase II unit with a Group 1
boiler shall submit an early election plan to the Administrator by
January 1 of the year the early election is to take effect, but not
later than January 1, 1997. Notwithstanding Sec. 72.40 of this chapter,
and unless the unit is a substitution unit under Sec. 72.41 of this
chapter or a compensating unit under Sec. 72.43 of this chapter, a
complete compliance plan covering the unit shall not include the
provisions for SO2 emissions under Sec. 72.40(a)(1) of this
chapter.
(c) Contents of an early election plan. A complete early election
plan shall include the following elements in a format prescribed by the
Administrator:
(1) A request for early election;
(2) The first year for which early election is to take effect, but
not later than 1997; and
(3) The special provisions under paragraph (e) of this section.
(d)(1) Permitting authority's action. To the extent the
Administrator determines that an early election plan complies with the
requirements of this section, the Administrator will approve the plan
and:
(i) If a Phase I Acid Rain permit governing the source at which
the unit is located has been issued, will revise the permit in
accordance with the permit modification procedures in Sec. 72.81 of
this chapter to include the early election plan; or
(ii) If a Phase I Acid Rain permit governing the source at which
the unit is located has not been issued, will issue a Phase I Acid Rain
permit effective from January 1, 1995 through December 31, 1999, that
will include the early election plan and a complete compliance plan
under Sec. 72.40(a) of this chapter and paragraph (b) of this section.
If the early election plan is not effective until after January 1,
1995, the permit will not contain any NOX emissions limitations
until the effective date of the plan.
(2) Beginning January 1, 2000, the permitting authority will
approve any early election plan previously approved by the
Administrator during Phase I, unless the plan is terminated pursuant to
paragraph (e)(3) of this section.
(e) Special provisions
(1) Emissions limitations.
(i) Sulfur dioxide. Notwithstanding Sec. 72.9 of this chapter, a
unit that is governed by an approved early election plan and that is
not a substitution unit under Sec. 72.41 of this chapter or a
compensating unit under Sec. 72.43 of this chapter shall not be subject
to the following standard requirements under Sec. 72.9 of this chapter
for Phase I:
(A) The permit requirements under Secs. 72.9(a)(1) (i) and (ii) of
this chapter;
(B) The sulfur dioxide requirements under Sec. 72.9(c) of this
chapter; and
(C) The excess emissions requirements under Sec. 72.9(e)(1) of this
chapter.
(ii) Nitrogen oxides. A unit that is governed by an approved early
election plan shall be subject to an emissions limitation for NOX
as provided under paragraph (a)(2) of this section except as provided
under paragraph (e)(3)(iii) of this section.
(2) Liability. The owners and operators of an unit governed by an
approved early election plan shall be liable for any violation of the
plan or this section at that unit. The owners and operators shall be
liable, beginning January 1, 2000, for fulfilling the obligations
specified in part 77 of this chapter.
(3) Termination. An approved early election plan shall be in effect
only until the earlier of January 1, 2008 or January 1 of the calendar
year for which a termination of the plan takes effect.
(i) If the designated representative of the unit under an approved
early election plan fails to demonstrate compliance with the applicable
emissions limitation under Sec. 76.5 for any year during the period
beginning January 1 of the first year the early election takes effect
and ending December 31, 2007, the permitting authority will terminate
the plan. The termination will take effect beginning January 1 of the
year after the year for which there is a failure to demonstrate
compliance, and the designated representative may not submit a new
early election plan.
(ii) The designated representative of the unit under an approved
early election plan may terminate the plan any year prior to 2008 but
may not submit a new early election plan. In order to terminate the
plan, the designated representative must submit a notice under
Sec. 72.40(d) of this chapter by January 1 of the year for which the
termination is to take effect.
(iii)(A) If an early election plan is terminated any year prior to
2000, the unit shall meet, beginning January 1, 2000, the applicable
emissions limitation for NOX for Phase II units with Group 1
boilers under Sec. 76.5(g) and, if revised emission limitations are
issued pursuant to section 407(b)(2) of the Act, Sec. 76.7.
(B) If an early election plan is terminated on or after 2000, the
unit shall meet, beginning on the effective date of the termination,
the applicable emissions limitation for NOX for Phase II units
with Group 1 boilers under Sec. 76.5(g) and, if revised emission
limitations are issued pursuant to section 407(b)(2) of the Act,
Sec. 76.7.

Sec. 76.9 Permit application and compliance plans.

(a) Duty to apply. (1) The designated representative of any source
with an affected unit subject to this part shall submit, by the
applicable deadline under paragraph (b) of this section, a complete
Acid Rain permit application (or, if the unit is covered by an Acid
Rain permit, a complete permit revision) that includes a complete
compliance plan for NOX emissions covering the unit.
(2) The original and three copies of the permit application and
compliance plan for NOX emissions for Phase I shall be submitted
to the EPA Regional office for the region where the applicable source
is located. The original and three copies of the permit application and
compliance plan for NOX emissions for Phase II shall be submitted
to the permitting authority.
(b) Deadlines. (1) For a Phase I unit with a Group 1 boiler, the
designated representative shall submit a complete permit application
and compliance plan for NOX covering the unit during Phase I to
the applicable permitting authority not later than May 6, 1994.
(2) For a Phase I or Phase II unit with a Group 2 boiler or a Phase
II unit with a Group 1 boiler, the designated representative shall
submit a complete permit application and compliance plan for NOX
emissions covering the unit in Phase II to the Administrator not later
than January 1, 1998, except that early election units shall also
submit an application not later than January 1, 1997.
(c) Information requirements for NOX compliance plans. In
accordance with Sec. 72.40(a)(2) of this chapter, a complete compliance
plan for NOX shall, for each affected unit included in the permit
application and subject to this part, either certify that the unit will
comply with the applicable emissions limitation under Secs. 76.5, 76.6,
or 76.7 or specify one or more other Acid Rain compliance options for
NOX in accordance with the requirements of this part. A complete
compliance plan for NOX for a source shall include the following
elements in a format prescribed by the Administrator:
(1) Identification of the source;
(2) Identification of each affected unit that is at the source and
is subject to this part;
(3) Identification of the boiler type of each unit;
(4) Identification of the compliance option proposed for each unit
(i.e., meeting the applicable emissions limitation under Secs. 76.5,
76.6, or 76.7, Sec. 76.8 (early election), Sec. 76.10 (alternative
emission limitation), Sec. 76.11 (NOX emissions averaging), or
Sec. 76.12 (Phase I NOX compliance extension)) and any additional
information required for the appropriate option in accordance with this
part;
(5) Reference to the standard requirements in Sec. 72.9 of this
chapter (consistent with Sec. 76.8(e)(1)(i)); and
(6) The requirements of Secs. 72.21 (a) and (b) of this chapter.
(d) Duty to reapply. The designated representative of any source
with an affected unit subject to this part shall submit a complete Acid
Rain permit application, including a complete compliance plan for
NOX emissions covering the unit, in accordance with the deadlines
in Sec. 72.30(c) of this chapter.
(e) Each ton of excess emissions of NOX shall constitute a
separate violation of the Act.

Sec. 76.10 Alternative emission limitations.

(a) General provisions. (1) The designated representative of an
affected unit that is not an early election unit pursuant to Sec. 76.8
and cannot meet the applicable emission limitation in Secs. 76.5, 76.6,
or 76.7 using, for Group 1 boilers, low NOX burner technology
(including separated overfire air as described in this paragraph) or,
using an alternative technology in accordance with paragraph (e)(11) of
this section, or, for Group 2 boilers, the technology on which the
applicable emission limitation is based, may petition the permitting
authority for an alternative emission limitation less stringent than
the applicable emission limitation.
(2) In order for the unit to qualify for an alternative emission
limitation, the designated representative shall demonstrate that the
affected unit cannot meet the applicable emission limitation in
Secs. 76.5, 76.6, or 76.7 based on a showing, to the satisfaction of
the Administrator, that:
(i) Except as provided in paragraph (a)(3) of this section,
(A) For a tangentially fired boiler, the owner or operator has
properly installed low NOX burner technology incorporating both
close-coupled and separated overfire air;
(B) For a dry bottom wall-fired boiler (other than a unit applying
cell burner technology), the owner or operator has properly installed
low NOX burner technology incorporating combustion air staging
above the top burner level in an extended or separate windbox;
(C) For a Group 1 boiler, the owner or operator has properly
installed an alternative technology (including but not limited to
reburning, selective noncatalytic reduction, or selective catalytic
reduction) that achieves NOX emission reductions demonstrated in
accordance with paragraph (e)(11) of this section; or
(D) For a Group 2 boiler, the owner or operator has properly
installed the appropriate NOX emission control technology on which
the applicable emission limitation in Sec. 76.6 is based;
(ii) The installed NOX emission control system has been
designed to meet the applicable emission limitation in Secs. 76.5,
76.6, or 76.7; and
(iii) For a demonstration period of at least 15 months or other
period of time, as provided in paragraph (f)(1) of this section:
(A) The NOX emission control system has been properly
installed and properly operated according to specifications and
procedures designed to minimize the emissions of NOX to the
atmosphere;
(B) Unit operating data as specified in this section show that the
unit and NOX emission control system were operated in accordance
with the bid and design specifications on which the design of the
NOX emission control system was based; and
(C) Unit operating data as specified in this section, continuous
emission monitoring data obtained pursuant to part 75 of this chapter,
and the test data specific to the NOX emission control system show
that the unit could not meet the applicable emission limitation in
Secs. 76.5, 76.6, or 76.7.
(3)(i) An affected unit with a tangentially fired boiler may be
eligible for an alternative emission limitation when it is technically
infeasible (e.g., would require the removal or modification of major
supports that would compromise the plant's structural integrity) as
demonstrated by the information and data submitted in accordance with
paragraph (d)(4) of this section to install separated overfire air.
(ii) An affected unit with a dry bottom wall-fired boiler that has
installed low NOX burners without combustion air staging above the
top burner level may be eligible for an alternative emission limitation
when the installation of combustion air staging above the top burner
level is technically infeasible (e.g., would require the removal or
modification of major supports that would compromise the plant's or
boiler's structural integrity) as demonstrated by the information and
data submitted in accordance with paragraph (d)(4) of this section.
(b) Petitioning process. The petitioning process for an alternative
emission limitation shall consist of the following steps:
(1) Operation during a period of at least 3 months, following the
installation of the NOX emission control system, that shows that
the specific unit and the NOX emission control system was unable
to meet the applicable emissions limitation under Secs. 76.5, 76.6, or
76.7 and was operated in accordance with the operating conditions upon
which the design of the NOX emission control system was based and
with vendor specifications and procedures;
(2) Submission of a petition for an alternative emission limitation
demonstration period as specified in paragraph (d) of this section;
(3) Operation during a demonstration period of at least 15 months,
or other period of time as provided in paragraph (f)(1) of this
section, that demonstrates the inability of the specific unit to meet
the applicable emissions limitation under Secs. 76.5, 76.6, or 76.7 and
the minimum NOX emissions rate that the specific unit can achieve
during long-term load dispatch operation; and
(4) Submission of a petition for a final alternative emission
limitation as specified in paragraph (e) of this section.
(c) Deadlines.
(1) Petition for an alternative emission limitation demonstration
period. The designated representative of the unit shall submit a
petition for an alternative emission limitation demonstration period to
the permitting authority after the unit has been operated for at least
3 months after installation of the NOX emission control system
required under paragraph (a)(2) of this section and by the following
deadline:
(i) For units that seek to have an alternative emission limitation
demonstration period apply during all or part of calendar year 1995, or
any previous calendar year by the later of:
(A) 120 days after startup of the NOX emission control system,
or
(B) May 1, 1995.
(ii) For units that seek an alternative emission limitation
demonstration period beginning in a calendar year after 1995, not later
than:
(A) 120 days after January 1 of that calendar year, or
(B) 120 days after startup of the NOX emission control system
if the unit is not operating at the beginning of that calendar year.
(2) Petition for a final alternative emission limitation. Not later
than 90 days after the end of an approved alternative emission
limitation demonstration period for the unit, the designated
representative of the unit may submit a petition for an alternative
emission limitation to the permitting authority.
(3) Renewal of an alternative emission limitation. In order to
request continuation of an alternative emission limitation, the
designated representative must submit a petition to renew the
alternative emission limitation on the date that the application for
renewal of the sources Acid Rain permit containing the alternative
emission limitation is due.
(d) Contents of petition for an alternative emission limitation
demonstration period. The designated representative of an affected unit
that has met the minimum criteria under paragraph (a) of this section
and that has been operated for a period of at least 3 months following
the installation of the required NOX emission control system may
submit to the permitting authority a petition for an alternative
emission limitation demonstration period. In the petition, the
designated representative shall provide the following information in a
format prescribed by the Administrator:
(1) Identification of the unit;
(2) The type of NOX control technology installed (e.g., low
NOX burner technology, selective noncatalytic reduction, selective
catalytic reduction, reburning);
(3) If an alternative technology is installed, the time period (not
less than 6 consecutive months) prior to installation of the technology
to be used for the demonstration required in paragraph (e)(11) of this
section.
(4) If low NOX burner technology incorporating separated
overfire air or combustion air staging above the top burner level is
technically infeasible, a justification including a technical analysis
and evaluative report from the primary vendor of the system or from an
independent architectural and engineering firm explaining why.
(5) Documentation as set forth in Sec. 76.14(a)(1) showing that the
installed NOX emission control system has been designed to meet
the applicable emission limitation in Secs. 76.5, 76.6, or 76.7 and
that the system has been properly installed according to procedures and
specifications designed to minimize the emissions of NOX to the
atmosphere;
(6) The date the unit commenced operation following the
installation of the NOX emission control system or the date the
specific unit became subject to the emission limitations of Secs. 76.5,
76.6, or 76.7, whichever is later;
(7) The dates of the operating period (which must be at least 3
months long);
(8) Certification by the designated representative that the
owner(s) or operator operated the unit and the NOX emission
control system during the operating period in accordance with
specifications and procedures designed to achieve the maximum NOX
reduction possible with the installed low NOX burner technology
(or an alternative technology) or the applicable emission limitation in
Secs. 76.5, 76.6, or 76.7 with the operating conditions upon which the
design of the NOX emission control system was based, and with
vendor specifications and procedures;
(9) A brief statement describing the reason or reasons why the unit
cannot achieve the applicable emission limitation in Secs. 76.5, 76.6,
or 76.7;
(10) A demonstration period plan, as set forth in Sec. 76.14(a)(2);
(11) Unit operating data and quality-assured continuous emission
monitoring data (including the specific data items listed in
Sec. 76.14(a)(3) collected in accordance with part 75 of this chapter
during the operating period) and demonstrating the inability of the
specific unit to meet the applicable emission limitation in Secs. 76.5,
76.6, or 76.7 on an annual average basis while operating as certified
under paragraph (d)(8) of this section;
(12) An interim alternative emission limitation, in lb/mmBtu, that
the unit can achieve during a demonstration period of at least 15
months. The interim alternative emission limitation shall be derived
from the data specified in paragraph (d)(11) of this section using
methods and procedures satisfactory to the Administrator;
(13) The proposed dates of the demonstration period (which must be
at least 15 months long);
(14) A report which outlines the testing and procedures to be taken
during the demonstration period in order to determine the maximum
NOX emission reduction obtainable with the installed system. The
report shall include the reasons for the NOX emission control
system's failure to meet the applicable emission limitation, and the
tests and procedures that will be followed to optimize the NOX
emission control system's performance. Such tests and procedures may
include those identified in Sec. 76.15 as appropriate.
(15) The special provisions at paragraph (g)(1) of this section.
(e) Contents of petition for a final alternative emission
limitation. After the approved demonstration period, the designated
representative of the unit may petition the permitting authority for an
alternative emission limitation. The petition shall include the
following elements in a format prescribed by the Administrator:
(1) Identification of the unit;
(2) Certification that the owner(s) or operator operated the
affected unit and the NOX emission control system during the
demonstration period in accordance with: specifications and procedures
designed to achieve the maximum NOX reduction possible with low
NOX burner technology or an alternative technology or the
applicable emissions limitation, the operating conditions (including
load dispatch conditions) upon which the design of the NOX
emission control system was based; and vendor specifications and
procedures.
(3) Certification that the owner(s) or operator have installed in
the affected unit all NOX emission control systems, made any
operational modifications, and completed any planned upgrades and/or
maintenance to equipment specified in the approved demonstration period
plan for optimizing NOX emission reduction performance, consistent
with the demonstration period plan and the proper operation of the low
NOX burner technology or alternative technology. Such
certification shall explain any differences between the installed
NOX emission control system and the equipment configuration
described in the approved demonstration period plan.
(4) A clear description of each step or modification taken during
the demonstration period to improve or optimize the performance of, for
Group 1 boilers, the low NOX burner technology or alternative
technology, or, for Group 2 boilers, the technology on which the
applicable emission limitation is based.
(5) Engineering design calculations and drawings that show the
technical specifications for installation of any additional operational
or emission control modifications installed during the demonstration
period.
(6) Unit operating and quality-assured continuous emission
monitoring data (including the specific data listed in Sec. 76.14(b))
collected in accordance with part 75 of this chapter during the
demonstration period and demonstrating the inability of the specific
unit to meet the applicable emission limitation in Secs. 76.5, 76.6, or
76.7 on an annual average basis while operating in accordance with the
certification under paragraph (e)(2) of this section.
(7) A report (based on the parametric test requirements set forth
in the approved demonstration period plan as identified in paragraph
(d)(14) of this section), that demonstrates the unit was operated in
accordance with the operating conditions upon which the design of the
NOX emission control system was based and describes the reason or
reasons for the failure of the installed NOX emission control
system to meet the applicable emission limitation in Secs. 76.5, 76.6,
or 76.7 on an annual average basis.
(8) The minimum NOX emission rate, in lb/mmBtu, that the
affected unit can achieve on an annual average basis with the installed
NOX emission control system. This value, which shall be the
requested alternative emission limitation, shall be derived from the
data specified in this section using methods and procedures
satisfactory to the Administrator; and shall be the lowest annual
emission rate the unit can achieve with the installed NOX emission
control system;
(9) All supporting data and calculations documenting the
determination of the requested alternative emission limitation and its
conformance with the methods and procedures satisfactory to the
Administrator;
(10) The special provisions in paragraph (g)(2) of this section.
(11) In addition to the other requirements of this section, the
owner or operator of an affected unit with a Group 1 boiler that has
installed an alternative technology (including but not limited to,
reburning, selective noncatalytic reduction, or selective catalytic
reduction) in addition to or in lieu of low NOX burner technology
and cannot meet the applicable emission limitation in Sec. 76.5 shall
demonstrate, to the satisfaction of the Administrator, that the actual
percentage reduction in NOX emissions (lbs/mmBtu), on an annual
average basis is greater than 65 percent of the average annual NOX
emissions prior to the installation of the NOX emission control
system. The percentage reduction in NOX emissions shall be
determined using continuous emissions monitoring data for NOX
taken during the time period (under paragraph (d)(3) of this section)
prior to the installation of the NOX emission control system and
during long-term load dispatch operation of the specific boiler.
(f) Permitting authority's action.
(1) Alternative emission limitation demonstration period.
(i) The permitting authority may approve an alternative emission
limitation demonstration period and demonstration period plan, provided
that the requirements of this section are met to the satisfaction of
the permitting authority. The permitting authority shall disapprove a
demonstration period if the requirements of paragraph (a) of this
section were not met during the operating period.
(ii) If the demonstration period is approved, the permitting
authority will include, as part of the demonstration period, the 4
month period prior to submission of the application in the
demonstration period.
(iii) The alternative emission limitation demonstration period will
authorize the unit to emit at a rate not greater than the interim
alternative emission limitation during the demonstration period after
January 1, 1995 for Phase I units and January 1, 2000 for Phase II
units, and until the date that the Administrator approves or denies a
final alternative emission limitation.
(iv) After an alternative emission limitation demonstration period
is approved, if the designated representative requests an extension of
the demonstration period in accordance with paragraph (g)(1)(i)(B) of
this section, the permitting authority may extend the demonstration
period by administrative amendment (under Sec. 72.83 of this chapter)
to the Acid Rain permit.
(v) The permitting authority shall deny the demonstration period if
the designated representative cannot demonstrate that the unit met the
requirements of paragraph (a)(2) of this section. In such cases, the
permitting authority shall require that the owner or operator operate
the unit in compliance with the applicable emission limitation in
Secs. 76.5, 76.6, or 76.7 for the period preceding the submission of
the application for an alternative emission limitation demonstration
period, including the operating period, if such periods are after the
date on which the unit is subject to the standard limit under
Secs. 76.5, 76.6, or 76.7.
(2) Alternative emission limitation.
(i) If the permitting authority determines that the requirements in
this section are met, the permitting authority will approve an
alternative emission limitation and issue or revise an Acid Rain permit
to apply the approved limitation, in accordance with subparts F and G
of part 72 of this chapter. The permit will authorize the unit to emit
at a rate not greater than the approved alternative emission
limitation, starting the date the permitting authority revises an Acid
Rain permit to approve an alternative emission limitation.
(ii) If a permitting authority disapproves an alternative emission
limitation under paragraph (a)(2)(i) of this section, the owner or
operator shall operate the affected unit in compliance with the
applicable emission limitation in Secs. 76.5, 76.6, or 76.7 (unless the
unit is participating in an approved averaging plan under Sec. 76.11)
beginning on the date the permitting authority revises an Acid Rain
permit to disapprove an alternative emission limitation.
(3) Alternative emission limitation renewal.
(i) If, upon review of a petition to renew an approved alternative
emission limitation, the permitting authority determines that no
changes have been made to the control technology, its operation, the
operating conditions on which the alternative emission limitation was
based, or the actual NOX emission rate, the alternative emission
limitation will be renewed.
(ii) If the permitting authority determines that changes have been
made to the control technology, its operation, the fuel quality, or the
operating conditions on which the alternative emission limitation was
based, the designated representative shall submit, in order to renew
the alternative emission limitation or to obtain a new alternative
emission limitation, a petition for an alternative emission limitation
demonstration period that meets the requirements of paragraph (d) of
this section using a new demonstration period.
(g) Special provisions.
(1) Alternative emission limitation demonstration period.
(i) Emission limitations.
(A) Each unit with an approved alternative emission limitation
demonstration period shall comply with the interim emission limitation
specified in the unit's permit beginning on the effective date of the
demonstration period specified in the permit and, if a timely petition
for a final alternative emission limitation is submitted, extending
until the date on which the permitting authority issues or revises an
Acid Rain permit to approve or disapprove an alternative emission
limitation. If a timely petition is not submitted, then the unit shall
comply with the standard emission limit under Secs. 76.5, 76.6, or 76.7
beginning on the date the petition was required to be submitted under
paragraph (c)(2) of this section.
(B) When the owner or operator identifies, during the demonstration
period, boiler operating or NOX emission control system
modifications or upgrades that would produce further NOX emission
reductions, enabling the affected unit to comply with or bring its
emission rate closer to the applicable emissions limitation under
Secs. 76.5, 76.6, or 76.7, the designated representative may submit a
request and the permitting authority may grant, by administrative
amendment under Sec. 72.83 of this chapter, an extension of the
demonstration period for such period of time (not to exceed 12 months)
as may be necessary to implement such modifications.
(C) If the approved interim alternative emission limitation applies
to a unit for part, but not all, of a calendar year, the unit shall
determine compliance for the calendar year in accordance with the
procedures in Sec. 76.13(b).
(ii) Operating requirements.
(A) A unit with an approved alternative emission limitation
demonstration period shall be operated under load dispatch conditions
consistent with the operating conditions upon which the design of the
NOX emission control system and performance guarantee were based,
and in accordance with the demonstration period plan.
(B) A unit with an approved alternative emission limitation
demonstration period shall install all NOX emission control
systems, make any operational modifications, and complete any upgrades
and maintenance to equipment specified in the approved demonstration
period plan for optimizing NOX emission reduction performance.
(C) When the owner or operator identifies boiler operating or
NOX emission control system modifications or upgrades that would
produce higher NOX emission reductions, enabling the affected unit
to comply with, or bring its emission rate closer to, the applicable
emission limitation, the designated representative shall submit an
administrative amendment under Sec. 72.83 of this chapter to revise the
unit's Acid Rain permit and demonstration period plan to include such
modifications or upgrades.
(iii) Testing requirements. A unit with an approved alternative
emission limitation demonstration period shall monitor in accordance
with part 75 of this chapter and shall conduct all tests required under
the approved demonstration period plan.
(2) Final alternative emission limitation.
(i) Emission limitations.
(A) Each unit with an approved alternative emission limitation
shall comply with the alternative emission limitation specified in the
unit's permit beginning on the date specified in the permit as issued
or revised by the permitting authority to apply the final alternative
emission limitation.
(B) If the approved interim or final alternative emission
limitation applies to a unit for part, but not all, of a calendar year,
the unit shall determine compliance for the calendar year in accordance
with the procedures in Sec. 76.13(a).

Sec. 76.11 Emissions averaging.

(a) General provisions. In lieu of complying with the applicable
emission limitation in Secs. 76.5, 76.6, or 76.7, any affected units
subject to such emission limitation, under control of the same owner or
operator, and having the same designated representative may average
their NOX emissions under an averaging plan approved under this
section.
(1) Each affected unit included in an averaging plan for Phase I
shall be a Group 1 boiler subject to an emission limitation in
Sec. 76.5 during all years for which the unit is included in the plan.
(i) If a unit with an approved NOX compliance extension is
included in an averaging plan for 1996, the unit shall be treated, for
the purposes of applying Equation 1 in paragraph (a)(6) of this section
and Equation 2 in paragraph (d)(1)(ii)(A) of this section, as subject
to the applicable emissions limitation under Sec. 76.5 for the entire
year 1996.
(ii) A Phase II unit approved for early election under Sec. 76.8
shall not be included in an averaging plan for Phase I.
(2) Each affected unit included in an averaging plan for Phase II
shall be a boiler subject to an emission limitation in Secs. 76.5,
76.6, or 76.7 for all years for which the unit is included in the plan.
(3) Each unit included in an averaging plan shall have an
alternative contemporaneous annual emission limitation (lb/mmBtu) and
can only be included in one averaging plan.
(4) Each unit included in an averaging plan shall have a minimum
allowable annual heat input value (mmBtu), if it has an alternative
contemporaneous annual emission limitation more stringent than that
unit's applicable emission limitation under Secs. 76.5, 76.6, or 76.7,
and a maximum allowable annual heat input value, if it has an
alternative contemporaneous annual emission limitation less stringent
than that unit's applicable emission limitation under Secs. 76.5, 76.6,
or 76.7.
(5) The Btu-weighted annual average emission rate for the units in
an averaging plan shall be less than or equal to the Btu-weighted
annual average emission rate for the same units had they each been
operated, during the same period of time, in compliance with the
applicable emission limitations in Secs. 76.5, 76.6, or 76.7.
(6) In order to demonstrate that the proposed plan is consistent
with paragraph (a)(5) of this section, the alternative contemporaneous
annual emission limitations and annual heat input values assigned to
the units in the proposed averaging plan shall meet the following
requirement:

TR22MR94.004

where,

RLi=Alternative contemporaneous annual emission limitation for
unit i, lb/mmBtu, as specified in the averaging plan;
Rli=Applicable emission limitation for unit i, lb/mmBtu, as
specified in Secs. 76.5, 76.6, or 76.7 except as provided in paragraph
(a)(7) of this section, on and after January 1, 2000;
HIi=Annual heat input for unit i, mmBtu, as specified in the
averaging plan;
n=Number of units in the averaging plan.

(7) For units with an alternative emission limitation, Rli
shall equal the applicable emissions limitation under Secs. 76.5, 76.6,
or 76.7, not the alternative emissions limitation. Phase II averaging
plans shall be based on the Phase II allowable emissions limitation for
each category of boiler. For early election units and Phase II units,
Rlishall equal the Phase II Group 1 emission limitation.
(8) No unit may be included in more than one averaging plan.
(b)(1) Submission requirements. The designated representative of a
unit meeting the requirements of paragraphs (a)(1), (a)(2), and (a)(8)
of this section may submit an averaging plan (or a revision to an
approved averaging plan) to the permitting authority(ies) at any time
up to and including January 1 (or July 1, if the plan is restricted to
units located within a single permitting authority's jurisdiction) of
the calendar year for which the averaging plan is to become effective.
(2) The designated representative shall submit a copy of the same
averaging plan (or the same revision to an approved averaging plan) to
each permitting authority with jurisdiction over a unit in the plan.
(3) When an averaging plan (or a revision to an approved averaging
plan) is not approved, the owner or operator of each unit in the plan
shall operate the unit in compliance with the emission limitation that
would apply in the absence of the averaging plan (or revision to a
plan).
(c) Contents of NOX averaging plan. A complete NOX
averaging plan shall include the following elements in a format
prescribed by the Administrator:
(1) Identification of each unit in the plan;
(2) Each unit's applicable emission limitation in Sec. 76.5, 76.6,
or 76.7;
(3) The alternative contemporaneous annual emission limitation for
each unit (in lb/mmBtu). If any of the units identified in the NOX
averaging plan utilize a common stack pursuant to
Sec. 75.17(a)(2)(i)(B) of this chapter, the same alternative
contemporaneous emission limitation shall be assigned to each such unit
and different heat input limits may be assigned;
(4) The annual heat input limit for each unit (in mmBtu);
(5) The calculation for Equation 1 in paragraph (a)(6) of this
section;
(6) The calendar years for which the plan will be in effect; and
(7) The special provisions in paragraph (d)(1) of this section.
(d) Special provisions.
(1) Emission limitations. Each affected unit in an approved
averaging plan is in compliance with the Acid Rain emission limitation
for NOX under the plan only if the following requirements are met:
(i) For all units, the unit's actual annual average emission rate
for the calendar year, in lb/mmBtu, is less than or equal to its
alternative contemporaneous annual emission limitation in the averaging
plan and
(A) For units with alternative contemporaneous emission limitations
less stringent than the applicable emission limitations in Secs. 76.5,
76.6, or 76.7, the actual annual heat input for the calendar year does
not exceed the annual heat input limit in the averaging plan;

(B) For units with alternative contemporaneous annual emission
limitations more stringent than the applicable emission limitations in
Secs. 76.5, 76.6, or 76.7, the actual annual heat input for the
calendar year is not less than the annual heat input limit in the
averaging plan; and
(ii) If one or more of the units does not meet the requirements
under paragraph (d)(1)(i) of this section, the designated
representative shall demonstrate, in accordance with paragraph
(d)(1)(ii)(A) of this section (Equation 2) that the actual Btu-weighted
annual average emission rate for the units in the plan is less than or
equal to the Btu-weighted annual average rate for the same units had
they each been operated, during the same period of time, in compliance
with the applicable emission limitations in Secs. 76.5, 76.6, or 76.7.
(A) A group showing of compliance shall be made based on the
following equation:

TR22MR94.005

where,

Rai=Actual annual average emission rate for unit i, lb/mmBtu, as
determined using the procedures in part 75 of this chapter. For units
in an averaging plan utilizing a common stack pursuant to
Sec. 75.17(a)(2)(i)(B) of this chapter, use the same NOX emission
rate value for each unit utilizing the common stack, and calculate this
value in accordance with appendix F to part 75 of this chapter;
Rli=Applicable annual emission limitation for unit i lb/mmBtu, as
specified in Secs. 76.5, 76.6, or 76.7, except as provided in paragraph
(d)(1)(ii)(B) of this section, on and after January 1, 2000;
HIai=Actual annual heat input for unit i, mmBtu, as determined
using the procedures in part 75 of this chapter;
n=Number of units in the averaging plan.

(B) For units with an alternative emission limitation, Rli
shall equal the applicable emission limitation under Secs. 76.5, 76.6,
or 76.7, not the alternative emission limitation. Phase II averaging
plans shall be based on the Phase II allowable emission rates for each
category of boiler. For early election units and Phase II affected
units, Rli shall equal the Phase II Group 1 emission limitation.
(2) Liability. (i) Except as provided in paragraph (d)(2)(ii) of
this section, the owners and operators of a unit governed by an
approved averaging plan shall be liable for any violation of the plan
or this section at that unit or any other unit in the plan, including
liability for fulfilling the obligations specified in part 77 of this
chapter and sections 113 and 411 of the Act.
(ii) Where there is a successful group showing of compliance,
neither the group nor any unit in the plan shall be subject to the
excess emissions penalty under part 77 of this chapter with regard to
the period covered by the group showing of compliance.
(3) Withdrawal or termination. The designated representative may
submit a notification to terminate an approved averaging plan in
accordance with Sec. 72.40(d) of this chapter, no later than October 1
of the calendar year for which the plan is to be withdrawn or
terminated.

Sec. 76.12 Phase I NOX compliance extensions.

(a) General provisions. (1) The designated representative of a
Phase I unit with a Group 1 boiler may apply for and receive a 15-month
extension of the deadline for meeting the applicable emissions
limitation under Sec. 76.5 where it is demonstrated, to the
satisfaction of the Administrator, that:
(i) The low NOX burner technology designed to meet the
applicable emission limitation is not in adequate supply to enable
installation and operation at the unit, consistent with system
reliability, by January 1, 1995 and the reliability problems are due
substantially to NOX emission control system installation and
availability; or
(ii) For tangentially fired boilers, low NOX coal and air
nozzles without either close-coupled or separated overfire air that:
(A) Were designed and guaranteed to meet the applicable limitation;
(B) Failed to meet such limitation; and
(C) The delivery and installation of additional equipment,
including but not limited to the addition of separated overfire air to
close-coupled overfire air or vice versa is contracted for installation
on or before January 1, 1996; or
(iii) For dry bottom wall-fired boilers, low NOX burners
without overfire air that:
(A) Were designed and guaranteed to meet the applicable emission
limitation;
(B) Failed to meet such limitation; and
(C) The delivery and installation of additional equipment,
including but not limited to overfire enhancement of the system is
contracted for installation on or before January 1, 1996; or
(iv) The unit is participating in an approved clean coal technology
demonstration project.
(2) In order to obtain a Phase I NOX compliance extension, the
designated representative shall submit a Phase I NOX compliance
extension plan by October 1994.
(b) Contents of Phase I NOX compliance extension plan. A
complete Phase I NOX compliance extension plan shall include the
following elements in a format prescribed by the Administrator:
(1) Identification of the unit.
(2) For units applying pursuant to paragraph (a)(1)(i) of this
section:
(i) A list of the company names, addresses, and telephone numbers
of vendors who are qualified to provide the services and low NOX
burner technology designed to meet the applicable emission limitation
under Sec. 76.5 and have been contacted to obtain the required services
and technology. The list shall include the dates of contact, and a copy
of each request for bids shall be submitted, along with any other
information necessary to show a good-faith effort to obtain the
required services and technology necessary to meet the requirements of
this part on or before January 1, 1995.
(ii) A copy of those portions of a legally binding contract with a
qualified vendor that demonstrate that services and low NOX burner
technology designed to meet the applicable emission limitation under
Sec. 76.5, with a completion date not later than December 31, 1995 have
been contracted for.
(iii) Scheduling information, including justification and test
schedules.
(iv) To demonstrate, if applicable, that the supply of the low
NOX burner technology designed to meet the applicable emission
limitation under Sec. 76.5 is inadequate to enable its installation and
operation at the unit, consistent with system reliability, in time for
the unit to comply with the applicable emission limitation on or before
January 1, 1995, either:
(A) Certification from the selected vendor(s) (by a certifying
official) listed in paragraph (b)(2)(i) of this section stating that
they cannot provide the necessary services and install the low NOX
burner technology on or before January 1, 1995 and explaining the
reasons why the services cannot be provided and why the equipment
cannot be installed in a timely manner; or
(B) The following information:
(1) Standard load forecasts, based on standard forecasting models
available throughout the utility industry and applied to the period,
January 1, 1993, through December 31, 1994.
(2) Specific reasons why an outage cannot be scheduled to enable
the unit to install and operate the low NOX burner technology by
January 1, 1995, including reasons why no other units can be used to
replace this unit's generation during such outage.
(3) Fuel and energy balance summaries and power and other
consumption requirements (including those for air, steam, and cooling
water).
(3) For units applying pursuant to paragraphs (a)(1) (ii) or (iii)
of this section;
(i) A copy of the vendor's performance guarantee demonstrating that
the low NOX burner technology installed at the unit was designed
to meet the applicable emission limitation;
(ii) Continuous emissions monitoring data collected in accordance
with part 75 of this chapter demonstrating that the unit's emissions
exceed the applicable emission limitation; and
(iii) A copy of those portions of a legally binding contract with
qualified vendor that demonstrate that the additional equipment
specified in paragraphs (a)(1) (ii)(C) or (iii)(C) of this section
designed to meet the applicable emissions limitation under Sec. 76.5,
with a completion date not later than December 31, 1995 has been
contracted for.
(4) To demonstrate, if applicable, participation in an approved
clean coal technology demonstration project, a description of the
project, including all sources of federal, State, and other outside
funding, amount and date for approval of federal funding, the duration
of the project, and the anticipated completion date of the project.
(5) The special provisions in paragraph (d) of this section.
(c)(1) Administrator's action. To the extent the Administrator
determines that a Phase I NOX compliance extension plan complies
with the requirements of this section, the Administrator will approve
the plan and revise the Acid Rain permit governing the unit in the plan
in order to incorporate the plan by administrative amendment under
Sec. 72.83 of this chapter, except that the Administrator shall have 90
days from receipt of the compliance extension plan to take final
action.
(2) The Administrator will approve or disapprove a proposed
NOX compliance extension plan within 3 months of receipt.
(d) Special provisions.
(1) Emission limitations. The unit shall comply with the applicable
emission limitation under Sec. 76.5 beginning April 1, 1996. Compliance
shall be determined as specified in part 75 of this chapter using
measured values of NOX emissions and heat input only for the
portion of the year that the emission limit is in effect.
(2) If a unit with an approved NOX compliance extension is
included in an averaging plan under Sec. 76.11 for year 1996, the unit
shall be treated, for purposes of applying Equation 1 in
Sec. 76.11(a)(6) and Equation 2 in Sec. 76.11(d)(1)(ii)(A) as subject
to the applicable emission limitation under Sec. 76.5 for the entire
year 1996.

Sec. 76.13 Compliance and excess emissions.

Excess emissions of nitrogen oxides under Sec. 77.6 of this chapter
shall be calculated as follows:
(a) For a unit that is not in an approved averaging plan:
(1) Calculate EEi for each portion of the calendar year that
the unit is subject to a different NOX emission limitation:

TR22MR94.001

where,

EEi=Excess emissions for NOX for the portion of the calendar
year (in tons);
Rai=Actual average emission rate for the unit (in lb/mmBtu),
determined according to part 75 of this chapter for the portion of the
calendar year for which the applicable emission limitation R1 is
in effect;
Rli=Applicable emission limitation for the unit (in lb/mmBtu), as
specified in Secs. 76.5, 76.6, or 76.7 or as determined under
Sec. 76.10;
HIi=Actual heat input for the unit (in mmBtu), determined
according to part 75 of this chapter for the portion of the calendar
year for which the applicable emission limitation, R1, is in
effect.

(2) If EEi is a negative number for any portion of the
calendar year, the EE value for that portion of the calendar year shall
be equal to zero (e.g., if EEi=-100, then EEi=0).
(3) Sum all EEi values for the calendar year:

TR22MR94.002

where,

EE=Excess emissions for NOX for the year (in tons);
n=The number of time periods during which a unit is subject to
different emission limitations; and

(b) For units participating in an approved averaging plan, when all
the requirements under Sec. 76.11(d)(1) are not met,

TR22MR94.003

where,

EE=Excess emissions for NOX for the year (in tons);
Rai=Actual annual average emission rate for NOX for unit i
(in lb/mmBtu), determined according to part 75 of this chapter;
Rli=Applicable emission limitation for unit i (in lb/mmBtu), as
specified in Secs. 76.5, 76.6, or 76.7;
HIi=Actual annual heat input for unit i, mmBtu, determined
according to part 75 of this chapter;
n=Number of units in the averaging plan.

Sec. 76.14 Monitoring, recordkeeping, and reporting.

(a) A petition for an alternative emission limitation demonstration
period under Sec. 76.10(d) shall include the following information:
(1) In accordance with Sec. 76.10(d)(5), the following information:
(i) Documentation that the owner or operator solicited bids for a
NOX emission control system designed for application to the
specific boiler and designed to achieve the applicable emission
limitation in Secs. 76.5, 76.6, or 76.7 on an annual average basis.
This documentation must include a copy of all bid specifications.
(ii) A copy of the performance guarantee submitted by the vendor of
the installed NOX emission control system to the owner or operator
showing that such system was designed to meet the applicable emission
limitation in Secs. 76.5, 76.6, or 76.7 on an annual average basis.
(iii) Documentation describing the operational and combustion
conditions that are the basis of the performance guarantee.
(iv) Certification by the primary vendor of the NOX emission
control system that such equipment and associated auxiliary equipment
was properly installed according to the modifications and procedures
specified by the vendor.
(v) Certification by the designated representative that the
owner(s) or operator installed technology that meets the requirements
of Sec. 76.10(a)(2).
(2) In accordance with Sec. 76.10(d)(10), the following
information:
(i) The operating conditions of the NOX emission control
system including load range, O2 range, coal volatile matter range,
and percent of combustion air introduced through the overfire air
ports;
(ii) Certification by the designated representative that the
owner(s) or operator have achieved and are following the operating
conditions, boiler modifications, and upgrades that formed the basis
for the system design and performance guarantee:
(iii) Any planned equipment modifications and upgrades for the
purpose of achieving the maximum NOX reduction performance of the
NOX emission control system that were not included in the design
specifications and performance guarantee, but that were achieved prior
to submission of this application and are being followed;
(iv) A list of any modifications or replacements of equipment that
are to be done prior to the completion of the demonstration period for
the purpose of reducing emissions of NOX; and
(v) The parametric testing that will be conducted to determine the
reason or reasons for the failure of the unit to achieve the applicable
emission limitation and to verify the proper operation of the installed
NOX emission control system during the demonstration period. The
tests shall include tests in Sec. 76.15, which may be modified as
follows:
(A) The owner or operator of the unit may add tests to those
listed in Sec. 76.15, if such additions provide data relevant to the
failure of the installed NOX emission control system to meet the
applicable emissions limitation in Secs. 76.5, 76.6, or 76.7; or
(B) The owner or operator of the unit may remove tests listed in
Sec. 76.15 that are shown, to the satisfaction of the permitting
authority, not to be relevant to NOX emissions from the affected
unit; and
(C) In the event the performance guarantee or the NOX emission
control system specifications require additional tests not listed in
Sec. 76.15, or specify operating conditions not verified by tests
listed in Sec. 76.15, the owner or operator of the unit shall include
such additional tests.
(3) In accordance with Sec. 76.10(d)(11), the following information
for the operating period:
(i) The average NOX emission rate (in lb/mmBtu) of the
specific unit;
(ii) The highest hourly NOX emission rate (in lb/mmBtu) of the
specific unit;
(iii) Hourly NOX emission rate (in lb/mmBtu), calculated in
accordance with part 75 of this chapter;
(iv) Total heat input (in mmBtu) for the unit for each hour of
operation, calculated in accordance with the requirements of part 75 of
this chapter; and
(v) Total integrated hourly gross unit load (in MWge).
(b) A petition for an alternative emission limitation shall include
the following information in accordance with Sec. 76.10(e)(6).
(1) Total heat input (in mmBtu) for the unit for each hour of
operation, calculated in accordance with the requirements of part 75 of
this chapter;
(2) Hourly NOX emission rate (in lb/mmBtu), calculated in
accordance with the requirements of part 75 of this chapter; and
(3) Total integrated hourly gross unit load (MWge).
(c) Reporting of the costs of low NOX burner technology
applied to Group 1, Phase I boilers. (1) Except as provided in
paragraph (c)(2) of this section, the designated representative of a
Phase I unit with a Group 1 boiler that has installed or is installing
any form of low NOX burner technology shall submit to the
Administrator a report containing the capital cost, operating cost, and
baseline and post-retrofit emission data specified in appendix B to
this part. If any of the required equipment, cost, and schedule
information are not available (e.g., the retrofit project is still
underway), the designated representative shall include in the report
detailed cost estimates and other projected or estimated data in lieu
of the information that is not available.
(2) The report under paragraph (c)(1) of this section is not
required with regard to the following types of Group 1, Phase I units:
(i) Units employing no new NOX emission control system after
November 15, 1990, and
(ii) Units employing modifications to boiler operating parameters
(e.g., burners out of service or fuel switching) without low NOX
burners or other emission reduction equipment for reducing NOX
emissions.
(3) The report under paragraph (c)(1) of this section shall be
submitted to the Administrator not later than the earlier of the
following dates:
(i) 120 days after completion of the low NOX burner technology
retrofit project;
(ii) March 31, 1995; or
(iii) July 20, 1994 for units completing the retrofit project
before April 1, 1994.

Sec. 76.15 Test methods and procedures.

(a) The owner or operator shall use the following tests as a basis
for the report required by Sec. 76.10(e)(7):
(1) Conduct an ultimate analysis of coal using ASTM D 3176-89
(incorporated by reference as specified in Sec. 76.4);
(2) Conduct a proximate analysis of coal using ASTM D 3172-89
(incorporated by reference as specified in Sec. 76.4); and
(3) Measure the coal mass flow rate to each individual burner using
ASME Power Test Code 4.2 (1991), ``Test Code for Coal Pulverizers'' or
ISO 9931 (1991), ``Coal--Sampling of Pulverized Coal Conveyed by Gases
in Direct Fired Coal Systems'' (incorporated by reference as specified
in Sec. 76.4).
(b) The owner or operator shall measure and record the actual
NOX emission rate in accordance with the requirements of this part
while varying the following parameters where possible to determine
their effects on the emissions of NOX from the affected boiler:
(1) Excess air levels;
(2) Settings of burners or coal and air nozzles, including tilt and
yaw, or swirl;
(3) Air flow levels to combustion air staging ports as a percentage
of total combustion air;
(4) Coal mass flow rates to each individual burner;
(5) Coal-to-primary air ratio (based on pound per hour) for each
burner, the average coal-to-primary air ratio for all burners, and the
deviations of individual burners' coal-to-primary air ratios from the
average value; and
(6) Proximate and ultimate analyses of the as-fired coal.
(c) In performing the tests specified in paragraph (a) of this
section, the owner or operator shall begin the tests using the
equipment settings for which the low NOX burner technology
equipment was designed to meet the NOX emission rate guaranteed by
the primary NOX emission control system vendor. These results
constitute the ``baseline controlled'' condition.
(d) After establishing the baseline controlled condition under
paragraph (c) of this section, the owner or operator shall:
(1) Change excess air levels 5 percent from the
baseline controlled condition to determine the effects on emissions of
NOX, by providing a minimum of three readings (e.g., with a
baseline reading of 20 percent excess air, excess air levels will be
changed to 19 percent and 21 percent);
(2) Change air flow levels to the combustion air staging ports
10 percent from the baseline controlled condition to
determine the effects on NOX emissions by providing a minimum of
three readings (e.g., with a baseline controlled value of 25 percent
staging air, combustion staging air will be changed to 22.5 percent and
27.5 percent of total combustion air); and
(3) The owner or operator shall ensure that the burners are
balanced, allowing no more than a 10 percent difference in the fuel and
air flows to any two burners.

Sec. 76.16 [Reserved]
Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units
With Group 1 or Cell Burner Boilers

Table 1.--Phase I Tangentially Fired Units
----------------------------------------------------------------------------------------------------------------
State Plant Unit Operator
----------------------------------------------------------------------------------------------------------------
Alabama......................... EC Gaston...................... 5 Alabama Power Co.
Georgia......................... Bowen.......................... 1Blr Georgia Power Co.
Georgia......................... Bowen.......................... 2Blr Georgia Power Co.
Georgia......................... Bowen.......................... 3Blr Georgia Power Co.
Georgia......................... Bowen.......................... 4Blr Georgia Power Co.
Georgia......................... Jack McDonough................. MB1 Georgia Power Co.
Georgia......................... Jack McDonough................. MB2 Georgia Power Co.
Georgia......................... Wansley........................ 1 Georgia Power Co.
Georgia......................... Wansley........................ 2 Georgia Power Co.
Georgia......................... Yates.......................... Y1Br Georgia Power Co.
Georgia......................... Yates.......................... Y2Br Georgia Power Co.
Georgia......................... Yates.......................... Y3Br Georgia Power Co.
Georgia......................... Yates.......................... Y4Br Georgia Power Co.
Georgia......................... Yates.......................... Y5Br Georgia Power Co.
Georgia......................... Yates.......................... Y6Br Georgia Power Co.
Georgia......................... Yates.......................... Y7Br Georgia Power Co.
Illinois........................ Baldwin........................ 3 Illinois Power Co.
Illinois........................ Hennepin....................... 2 Illinois Power Co.
Illinois........................ Joppa.......................... 1 Electric Energy Inc.
Illinois........................ Joppa.......................... 2 Electric Energy Inc.
Illinois........................ Joppa.......................... 3 Electric Energy Inc.
Illinois........................ Joppa.......................... 4 Electric Energy Inc.
Illinois........................ Joppa.......................... 5 Electric Energy Inc.
Illinois........................ Joppa.......................... 6 Electric Energy Inc.
Illinois........................ Meredosia...................... 5 Cen Illinois Pub Ser.
Illinois........................ Vermilion...................... 2 Illinois Power Co.
Indiana......................... Cayuga......................... 1 PSI Energy Inc.
Indiana......................... Cayuga......................... 2 PSI Energy Inc.
Indiana......................... EW Stout....................... 50 Indianapolis Pwr & Lt
Indiana......................... EW Stout....................... 60 Indianapolis Pwr & Lt.
Indiana......................... EW Stout....................... 70 Indianapolis Prw & Lt.
Indiana......................... HT Pritchard................... 6 Indianapolis Pwr & Lt.
Indiana......................... Petersburg..................... 1 Indianapolis Pwr & Lt.
Indiana......................... Petersburg..................... 2 Indianapolis Pwr & Lt.
Indiana......................... Wabash River................... 6 PSI Energy Inc.
Iowa............................ Burlington..................... 1 Iowa Southern Utl.
Iowa............................ ML Kapp........................ 2 Interstate Power Co.
Iowa............................ Riverside...................... 9 Iowa-Ill Gas & Elec.
Kentucky........................ Elmer Smith.................... 2 Owensboro Mun Util.
Kentucky........................ EW Brown....................... 2 Kentucky Utl Co.
Kentucky........................ EW Brown....................... 3 Kentucky Utl Co.
Kentucky........................ Ghent.......................... 1 Kentucky Utl Co.
Maryland........................ Morgantown..................... 1 Potomac Elec Pwr Co.
Maryland........................ Morgantown..................... 2 Potomac Elec Pwr Co.
Michigan........................ JH Campbell.................... 1 Consumers Power Co.
Missouri........................ Labadie........................ 1 Union Electric Co.
Missouri........................ Labadie........................ 2 Union Electric Co.
Missouri........................ Labadie........................ 3 Union Electric Co.
Missouri........................ Labadie........................ 4 Union Electric Co.
Missouri........................ Montrose....................... 1 Kansas City Pwr & Lt.
Missouri........................ Montrose....................... 2 Kansas City Pwr & Lt.
Missouri........................ Montrose....................... 3 Kansas City Pwr & Lt.
New York........................ Dunkirk........................ 3 Niagara Mohawk Pwr.
New York........................ Dunkirk........................ 4 Niagara Mohawk Pwr.
New York........................ Greenidge...................... 6 NY State Elec & Gas.
New York........................ Milliken....................... 1 NY State Elec & Gas.
New York........................ Milliken....................... 2 NY State Elec & Gas.
Ohio............................ Ashtabula...................... 7 Cleveland Elec Illum.
Ohio............................ Avon Lake...................... 11 Cleveland Elec Illum.
Ohio............................ Conesville..................... 4 Columbus Sthern Pwr.
Ohio............................ Eastlake....................... 1 Cleveland Elec Illum.
Ohio............................ Eastlake....................... 2 Cleveland Elec Illum.
Ohio............................ Eastlake....................... 3 Cleveland Elec Illum.
Ohio............................ Eastlake....................... 4 Cleveland Elec Illum.
Ohio............................ Miami Fort..................... 6 Cincinnati Gas & Elec.
Ohio............................ WC Beckjord.................... 5 Cincinnati Gas & Elec.
Ohio............................ WC Beckjord.................... 6 Cincinnati Gas & Elc.
Pennsylvania.................... Brunner Island................. 1 Pennsylvania Pwr & Lt.
Pennsylvania.................... Brunner Island................. 2 Pennsylvania Pwr & Lt.
Pennsylvania.................... Brunner Island................. 3 Pennsylvania Pwr & Lt.
Pennsylvania.................... Cheswick....................... 1 Duquesne Light Co.
Pennsylvania.................... Conemaugh...................... 1 Pennsylvania Elec Co.
Pennsylvania.................... Conemaugh...................... 2 Pennsylvania Elec Co.
Pennsylvania.................... Portland....................... 1 Metropolitan Edison.
Pennsylvania.................... Portland....................... 2 Metropolitan Edison.
Pennsylvania.................... Shawville...................... 3 Pennsylvania Elec Co.
Pennsylvania.................... Shawville...................... 4 Pennsylvania Elec Co.
Tennessee....................... Gallatin....................... 1 Tennessee Val Auth.
Tennessee....................... Gallatin....................... 2 Tennessee Val Auth.
Tennessee....................... Gallatin....................... 3 Tennessee Val Auth.
Tennessee....................... Gallatin....................... 4 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 1 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 2 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 3 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 4 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 5 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 6 Tennessee Val Auth.
West Virginia................... Albright....................... 3 Monongahela Power Co.
West Virginia................... Fort Martin.................... 1 Monongahela Power Co.
West Virginia................... Mount Storm.................... 1 Virginia Elec & Pwr.
West Virginia................... Mount Storm.................... 2 Virginia Elec & Pwr.
West Virginia................... Mount Storm.................... 3 Virginia Elec & Pwr.
Wisconsin....................... Genoa.......................... 1 Dairyland Power Coop.
Wisconsin....................... South Oak Creek................ 7 Wisconsin Elec Power.
Wisconsin....................... South Oak Creek................ 8 Wisconsin Elec Power.
----------------------------------------------------------------------------------------------------------------

Table 2.--Phase I Dry Bottom Wall-Fired Units
----------------------------------------------------------------------------------------------------------------
State Plant Unit Operator
----------------------------------------------------------------------------------------------------------------
Alabama......................... Colbert........................ 1 Tennessee Val Auth.
Alabama......................... Colbert........................ 2 Tennessee Val Auth.
Alabama......................... Colbert........................ 3 Tennessee Val Auth.
Alabama......................... Colbert........................ 4 Tennessee Val Auth.
Alabama......................... Colbert........................ 5 Tennessee Val Auth.
Alabama......................... Ec Gaston...................... 1 Alabama Power Co.
Alabama......................... Ec Gaston...................... 2 Alabama Power Co.
Alabama......................... Ec Gaston...................... 3 Alabama Power Co.
Alabama......................... Ec Gaston...................... 4 Alabama Power Co.
Florida......................... Crist.......................... 6 Gulf Power Co.
Florida......................... Crist.......................... 7 Gulf Power Co.
Georgia......................... Hammond........................ 1 Georgia Power Co.
Georgia......................... Hammond........................ 2 Georgia Power Co.
Georgia......................... Hammond........................ 3 Georgia Power Co.
Georgia......................... Hammond........................ 4 Georgia Power Co.
Illinois........................ Grand Tower.................... 9 Cen Illinois Pub Ser.
Indiana......................... Culley......................... 2 Sthern Ind Gas & El.
Indiana......................... Culley......................... 3 Sthern Ind Gas & El.
Indiana......................... Gibson......................... 1 PSI Energy Inc.
Indiana......................... Gibson......................... 2 PSI Energy Inc.
Indiana......................... Gibson......................... 3 PSI Energy Inc.
Indiana......................... Gibson......................... 4 PSI Energy Inc.
Indiana......................... RA Gallagher................... 1 PSI Energy Inc.
Indiana......................... RA Gallagher................... 2 PSI Energy Inc.
Indiana......................... RA Gallagher................... 3 PSI Energy Inc.
Indiana......................... RA Gallagher................... 4 PSI Energy Inc.
Indiana......................... Frank E Ratts.................. 1SG1 Hoosier Energy Rec.
Indiana......................... Frank E Ratts.................. 2SG1 Hoosier Energy Rec.
Indiana......................... Wabash River................... 1 PSI Energy Inc.
Indiana......................... Wabash River................... 2 PSI Energy Inc.
Indiana......................... Wabash River................... 3 PSI Energy Inc.
Indiana......................... Wabash River................... 5 PSI Energy Inc.
Iowa............................ Des Moines..................... 11 Iowa Pwr & Lt Co.
Iowa............................ Prairie Creek.................. 4 Iowa Elec Lt & Pwr.
Kansas.......................... Quindaro....................... 2 Ks City Bd Pub Util.
Kentucky........................ Coleman........................ C1 Big Rivers Elec Corp.
Kentucky........................ Coleman........................ C2 Big Rivers Elec Corp.
Kentucky........................ Coleman........................ C3 Big Rivers Elec Corp.
Kentucky........................ EW Brown....................... 1 Kentucky Utl Co.
Kentucky........................ Green River.................... 5 Kentucky Utl Co.
Kentucky........................ HMP&L Station 2................ H1 Big Rivers Elec Corp.
Kentucky........................ HMP&L Station 2................ H2 Big Rivers Elec Corp.
Kentucky........................ HL Spurlock.................... 1 East KY Pwr Coop.
Kentucky........................ JS Cooper...................... 1 East KY Pwr Coop.
Kentucky........................ JS Cooper...................... 2 East KY Pwr Coop.
Maryland........................ Chalk Point.................... 1 Potomac Elec Pwr Co.
Maryland........................ Chalk Point.................... 2 Potomac Elec Pwr Co.
Minnesota....................... High Bridge.................... 6 Northern States Pwr.
Mississippi..................... Jack Watson.................... 4 Mississippi Pwr Co.
Mississippi..................... Jack Watson.................... 5 Mississippi Pwr Co.
Missouri........................ James River.................... 5 Springfield Utl.
Ohio............................ Conesville..................... 3 Columbus Sthern Pwr.
Ohio............................ Edgewater...................... 13 Ohio Edison Co.
Ohio............................ Miami Fort\1\.................. 5-1 Cincinnati Gas&Elec.
Ohio............................ Miami Fort\1\.................. 5-2 Cincinnati Gas&Elec.
Ohio............................ Picway......................... 9 Columbus Sthern Pwr.
Ohio............................ Re Burger...................... 7 Ohio Edison Co.
Ohio............................ Re Burger...................... 8 Ohio Edison Co.
Ohio............................ WH Sammis...................... 5 Ohio Edison Co.
Ohio............................ WH Sammis...................... 6 Ohio Edison Co.
Pennsylvania.................... Armstrong...................... 1 West Penn Power Co.
Pennsylvania.................... Armstrong...................... 2 West Penn Power Co.
Pennsylvania.................... Martins Creek.................. 1 Pennsylvania Pwr&Lt.
Pennsylvania.................... Martins Creek.................. 2 Pennsylvania Pwr&Lt.
Pennsylvania.................... Shawville...................... 1 Pennsylvania Elec Co.
Pennsylvania.................... Shawville...................... 2 Pennsylvania Elec Co.
Pennsylvania.................... Sunbury........................ 3 Pennsylvania Pwr&Lt.
Pennsylvania.................... Sunbury........................ 4 Pennsylvania Pwr&Lt.
Tennessee....................... Johnsonville................... 7 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 8 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 9 Tennessee Val Auth.
Tennessee....................... Johnsonville................... 10 Tennessee Val Auth.
West Virginia................... Harrison....................... 1 Monongahela Power Co.
West Virginia................... Harrison....................... 2 Monongahela Power Co.
West Virginia................... Harrison....................... 3 Monongahela Power Co.
West Virginia................... Mitchell....................... 1 Ohio Power Co.
West Virginia................... Mitchell....................... 2 Ohio Power Co.
Wisconsin....................... JP Pulliam..................... 8 Wisconsin Pub Ser Co.
Wisconsin....................... North Oak Creek\2\............. 1 Wisconsin Elec Pwr.
Wisconsin....................... North Oak Creek\2\............. 2 Wisconsin Elec Pwr.
Wisconsin....................... North Oak Creek\2\............. 3 Wisconsin Elec Pwr.
Wisconsin....................... North Oak Creek\2\............. 4 Wisconsin Elec Pwr.
Wisconsin....................... South Oak Creek\2\............. 5 Wisconsin Elec Pwr.
Wisconsin....................... South Oak Creek\2\............. 6 Wisconsin Elec Pwr.
----------------------------------------------------------------------------------------------------------------
\1\Vertically fired boiler.
\2\Arch-fired boiler.

Table 3.--Phase I Cell Burner Technology Units
----------------------------------------------------------------------------------------------------------------
State Plant Unit Operator
----------------------------------------------------------------------------------------------------------------
Indiana......................... Warrick........................ 4 Sthern Ind Gas & El.
Michigan........................ JH Campbell.................... 2 Consumers Power Co.
Ohio............................ Avon Lake...................... 12 Cleveland Elec Illum.
Ohio............................ Cardinal....................... 1 Cardinal Operating.
Ohio............................ Cardinal....................... 2 Cardinal Operating.
Ohio............................ Eastlake....................... 5 Cleveland Elec Illum.
Ohio............................ Genrl Jm Gavin................. 1 Ohio Power Co.
Ohio............................ Genrl Jm Gavin................. 2 Ohio Power Co.
Ohio............................ Miami Fort..................... 7 Cincinnati Gas & El.
Ohio............................ Muskingum River................ 5 Ohio Power Co.
Ohio............................ WH Sammis...................... 7 Ohio Edison Co.
Pennsylvania.................... Hatfields Ferry................ 1 West Penn Power Co.
Pennsylvania.................... Hatfields Ferry................ 2 West Penn Power Co.
Pennsylvania.................... Hatfields Ferry................ 3 West Penn Power Co.
Tennessee....................... Cumberland..................... 1 Tennessee Val Auth.
Tennessee....................... Cumberland..................... 2 Tennessee Val Auth.
West Virginia................... Fort Martin.................... 2 Monongahela Power Co.
----------------------------------------------------------------------------------------------------------------

Appendix B to Part 76--Procedures and Methods for Estimating Costs of
Nitrogen Oxides Controls Applied to Group 1, Phase I Boilers

1. Purpose and Applicability

This technical appendix specifies the procedures, methods, and data
that the Administrator will use in establishing ``* * * the degree of
reduction achievable through this retrofit application of the best
system of continuous emission reduction, taking into account available
technology, costs, and energy and environmental impacts; and which is
comparable to the costs of nitrogen oxides controls set pursuant to
subsection (b)(1) (of section 407 of the Act).'' In developing the
allowable NOX emissions limitations for Group 2 boilers pursuant
to subsection (b)(2) of section 407 of the Act, the Administrator will
consider only those systems of continuous emission reduction that, when
applied on a retrofit basis, are comparable in cost to the average cost
in constant dollars of low NOX burner technology applied to Group
1, Phase I boilers, as determined in section 3 below.
The Administrator will evaluate the capital cost (in dollars per
kilowatt electrical ($/kW)), the operating and maintenance costs (in $/
year), and the cost-effectiveness (in annualized $/ton NOX
removed) of installed low NOX burner technology controls over a
range of boiler sizes (as measured by the gross electrical capacity of
the associated generator in megawatt electrical (MW)) and utilization
rates (in percent gross nameplate capacity on an annual basis) to
develop estimates of the average capital cost and cost-effectiveness
for Group 1, Phase I boilers. The following units will be excluded from
these determinations of the average capital cost and cost-effectiveness
of NOX controls set pursuant to subsection (b)(1) of section 407
of the Act:
(1) Units employing an alternative technology in lieu of low
NOX burner technology for reducing NOX emissions;
(2) Units employing no controls, only controls installed before
November 15, 1990, or only modifications to boiler operating parameters
(e.g., burners out of service or fuel switching) for reducing NOX
emissions; and
(3) Units that have not achieved the applicable emission
limitation.

2. Average Capital Cost for Low NOX Burner Technology Applied to
Group 1, Phase I Boilers

The Administrator will use the procedures, methods, and data
specified in this section to estimate the average capital cost (in $/
kW) of installed low NOX burner technology applied to Group 1,
Phase I boilers.
2.1 Using cost data submitted pursuant to the reporting
requirements in section 4 of this appendix, boiler-specific actual or
estimated actual capital costs will be determined for each unit in the
population specified in section 1 above for assessing the costs of
installed low NOX burner technology. The scope of installed low
NOX burner technology costs will include the following capital
costs for retrofit application:
(1) For the burner portion--burners or air and coal nozzles, burner
throat and waterwall modifications, and windbox modifications; and,
where applicable,
(2) For the combustion air staging portion--waterwall modifications
or panels, windbox modifications, and ductwork, and
(3) Scope adders or supplemental equipment such as replacement or
additional fans, dampers, or ignitors necessary for the proper
operation of the low NOX burner technology.

Capital costs associated with boiler restoration or refurbishment such
as replacement of air heaters, asbestos abatement, and recasing will
not be included in the cost basis for installed low NOX burner
technology. The scope of installed low NOX burner technology
retrofit capital costs will include materials, construction and
installation labor, engineering, and overhead costs.
2.2 Using gross nameplate capacity (in MW) for each unit as
reported in the National Allowance Data Base (NADB), boiler-specific
capital costs will be converted to a $/kW basis.
2.3 Capital cost curves ($/kW versus boiler size in MW) or
equations for installed low NOX burner technology retrofit costs
will be developed for:
(1) Dry bottom wall-fired boilers (excluding units applying cell
burner technology) and
(2) Tangentially fired boilers.
2.4 The capital cost curves or equations defined above will be
used to develop weighted average cost estimates of installed low
NOX burner technology applied to Group 1, Phase I boilers. The
weighting factor will be the unit gross nameplate generating capacity
(in MW) as reported in the NADB.

3. Average Cost-Effectiveness for Low NOX Burner Technology
Applied to Group 1, Phase I Boilers

The Administrator will use the procedures, methods, and data
specified in this section to estimate the average cost-effectiveness
(in annualized $/ton NOX removed) of installed low NOX burner
technology applied to Group 1, Phase I boilers.
3.1 Boiler-specific estimates of annual tons NOX removed by
the installed low NOX burner technology will be determined for
each unit in the population specified in section 1 above.
3.1.1 The baseline NOX emission rate (in lb/mmBtu, annual
average basis) will be estimated prior to retrofitting any low NOX
burner technology controls. For units that have installed and certified
continuous emission monitoring systems for measuring the NOX
emission rate pursuant to part 75 of this chapter at least 120 days
prior to the low NOX burner technology retrofit, an estimate of
the average annual uncontrolled NOX emission rate will be
developed using continuous emission monitoring data for the 120 days
immediately before the low NOX burner technology retrofit or
another continuous 120-day or longer period as approved by the
Administrator. (In cases where 120 days of certified and quality-
assured continuous emission monitoring data are not available prior to
the low NOX burner technology retrofit, the Administrator may use
continuous emission monitoring data over a shorter period or short-term
test data to estimate the uncontrolled NOX emission rate.)
Continuous emission monitoring data or other emission rate measurements
will be extrapolated to one year of unit operation.
3.1.2 The controlled NOX emission rate (in lb/mmBtu, annual
average basis) will be estimated after installation, shakedown, and/or
optimization of all low NOX burner technology controls have been
completed and while the unit is complying with the applicable emission
limitation (or alternative emission limitation). Continuous emission
monitoring data submitted pursuant to part 75 of this chapter will be
used for the 120 days immediately following installation and testing of
the final low NOX burner technology, provided the unit is
complying with the applicable emission limitation (or alternative
emission limitation), or another continuous 120-day or shorter period
as approved by the Administrator. Continuous emission monitoring data
will be extrapolated to one year of unit operation.
3.1.3 The NOX emission reduction (in lb/mmBtu, annual
average basis) achieved by the installed low NOX burner technology
will be estimated by subtracting the controlled NOX emission rate
defined in section 3.1.2 from the uncontrolled NOX emission rate
defined in section 3.1.1.
3.1.4 Annual estimates of the NOX emission reduction
achieved by the installed low NOX burner technology will be
converted to annual tons of NOX removed by multiplying it by the
annual heat input (in mmBtu). Unit heat input data submitted pursuant
to part 75 of this chapter for calendar year 1994 or for the year
immediately following installation and testing of the final low
NOX burner technology, will be used when such data are available
prior to October 30, 1995. Such data will be adjusted to an annual
basis whenever a nonrecurrent extended outage at the affected unit
during the period has taken place.
3.2 The boiler-specific capital costs of installed low NOX
burner technology developed in section 2.1 will be annualized by
multiplying them by a constant dollar capital recovery factor based on
a 20-year economic life (e.g., 0.115).
3.3 Using cost data submitted pursuant to the reporting
requirements in section 4, boiler-specific annual operating and
maintenance cost increases (or decreases) will be determined for each
unit in the population specified in section 1 above. The scope of the
operating and maintenance costs (or savings) attributable to the
installed low NOX burner technology may, but not necessarily will,
include incremental increases (or decreases) in: maintenance labor and
materials costs, operating labor costs, operating fuel costs, and
secondary air fan electricity costs.
3.4 The average annual cost-effectiveness of installed low
NOX burner technology applied to Group 1, Phase I boilers will be
estimated as follows:
(1) The annualized capital costs defined in section 3.2 and the
annual operating and maintenance cost increases (or decreases) defined
in section 3.3 will be summed for all units in the population specified
in section 1; and
(2) These annualized costs will be divided by the sum of the
NOX emission reductions (in tons/year) achieved by the units in
the population specified in section 1.

4. Reporting Requirements

4.1 The following information is to be submitted by each
designated representative of a Phase I affected unit subject to the
reporting requirements of Sec. 76.14(c):
4.1.1 Schedule and dates for baseline testing, installation, and
performance testing of low NOX burner technology.
4.1.2 Estimates of the annual average baseline NOX emission
rate, as specified in section 3.1.1, and the annual average controlled
NOX emission rate, as specified in section 3.1.2, including the
supporting continuous emission monitoring or other test data.
4.1.3 Copies of pre-retrofit and post-retrofit performance test
reports.
4.1.4 Detailed estimates of the capital costs based on actual
contract bids for each component of the installed low NOX burner
technology including the items listed in section 2.1. Indicate number
of bids solicited. Provide a copy of the actual agreement for the
installed technology.
4.1.5 Detailed estimates of the capital costs of system
replacements or upgrades such as coal pipe changes, fan replacements/
upgrades, or mill replacements/upgrades undertaken as part of the low
NOX burner technology retrofit project.
4.1.6 Detailed breakdown of the actual costs of the completed low
NOX burner technology retrofit project where low NOX burner
technology costs (section 4.1.4) are disaggregated, if feasible, from
system replacement or upgrade costs (section 4.1.5).
4.1.7 Description of the probable causes for significant
differences between actual and estimated low NOX burner technology
retrofit project costs.
4.1.8 Detailed breakdown of the burner and, if applicable,
combustion air staging system annual operating and maintenance costs
for the items listed in section 3.3 before and after the installation,
shakedown, and/or optimization of the installed low NOX burner
technology. Include estimates and a description of the probable causes
of the incremental annual operating and maintenance costs (or savings)
attributable to the installed low NOX burner technology.
4.2 All capital cost estimates are to be broken down into
materials costs, construction and installation labor costs, and
engineering and overhead costs. All operating and maintenance costs are
to be broken down into maintenance materials costs, maintenance labor
costs, operating labor costs, and fan electricity costs. All capital
and operating costs are to be reported in dollars with the year of
expenditure or estimate specified for each component.

[FR Doc. 94-5721 Filed 3-21-94; 8:45 am]
BILLING CODE 6560-50-P