Acid Rain Program; Nitrogen Oxides Emission Reduction Program

[Federal Register: December 19, 1996 (Volume 61, Number 245)]
[Rules and Regulations]
[Page 67111-67164]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]

ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 76
[AD-FRL-5666-1]
RIN 2060-AF48

AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.

SUMMARY: This action promulgates standards for the second phase of the
Nitrogen Oxides Reduction Program under Title IV of the Clean Air Act
(``CAA'' or ``the Act'') by establishing nitrogen oxides (NO<INF>X)
emission limitations for certain coal-fired electric utility units and
revising NO<INF>X emission limitations for others as specified in
section 407(b)(2) of the Act. The emission limitations will reduce the
serious adverse effects of NO<INF>X emissions on human health,
visibility, ecosystems, and materials.

EFFECTIVE DATE: December 19, 1996.

ADDRESSES: Docket. Docket No. A-95-28, 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.
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 ``Phase II
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 S.W., Washington, DC 20460 (202-233-9620).

SUPPLEMENTARY INFORMATION:

Regulated Entities

Entities regulated by this action are electric service providers
that run or operate coal-fired electric utility boilers including dry
bottom wall-fired and tangentially fired boilers (Group 1) and certain
other boiler types including boilers applying cell-burner technology,
cyclone boilers, wet bottom boilers, and other types of coal-fired
boilers (Group 2). Regulated entities and boilers include:

Regulated Entities Regulated Boilers

Electric Service Providers................ Dry bottom wall-fired.
Tangentially fired.
Cell Burners.
Cyclones (larger than 155
MWe).
Vertically fired.
Wet bottoms (larger than 65
MWe).

This table is not intended to represent a definitive enumeration of
all existing and future entities regulated by this action. Rather, its
intent is to provide a general guide for readers and to list entities
that EPA is now aware will be regulated by this action. Other types of
entities not listed in the table could also be regulated. To determine
whether your (facility, company, business, organization, etc.) is
regulated by this action, you should carefully examine the
applicability criteria in Secs. 72.6 and 76.1 of title 40 of the Code
of Federal Regulations. If you have questions regarding the
applicability of this action to a particular entity, consult the person
named in the preceding ``For Further Information Contact'' section.
The information in this preamble is organized as follows:

I. Rule Background

A. Purpose of Acid Rain NO<INF>X Emission Reduction Program
B. Summary of Final Rule

NO<INF>X Standards Promulgated by this Rule
Rationale for Revising Group 1 NO<INF>X Emission Limits and
Environmental Impact of Group 2 NO<INF>X Emission Limits
II. Public Participation

III. Summary of Major Comments and Responses
A. Phase II, Group 1 Boiler NO<INF>X Emission Limits
Boiler Population Used to Assess NO<INF>X Emission Limits
Time Period/Averaging Basis Used to Evaluate Performance of
Low NO<INF>X Burner Technology

Analysis Method Used to Establish Reasonably Achievable
Emission Limitations for Phase II, Group 1 Boilers
Percentile Used to Define Achievability
B. Group 2 Boiler NO<INF>X Emission Limits
Cost Comparability and Its Basis

Cost Comparison Methodology

Retrofit Nature of Group 2 Controls
Group 2 Boiler Size Exemption

Cyclone Boiler NO<INF>X Controls
Wet Bottom Boiler NO<INF>X Controls
Vertically Fired Boiler NO<INF>X Controls
Cell Burner Boiler NO<INF>X Controls
Revision of Proposed Group 2 Boiler NO<INF>X Emission Limits
C. Compliance Issues

D. Title IV NO<INF>X Program's Relationship to Title I and
NO<INF>X Trading Issues

IV. Administrative Requirements

A. Docket

B. Executive Order 12866

C. Unfunded Mandates Act

D. Paperwork Reduction Act

E. Regulatory Flexibility Act

F. Submission to Congress and the General Accounting Office
G. Miscellaneous

I. Rule Background

A. Purpose of Acid Rain NO<INF>X Emission Reduction Program

The primary purpose of the Acid Rain NO<INF>X Emission Reduction
Program is to reduce the multiple adverse effects of the oxides of
nitrogen, a family of highly reactive gaseous compounds that contribute
to air and water pollution, by substantially reducing annual emissions
from coal-fired power plants. Since the 1970 passage of the Clean Air
Act, NO<INF>X has increased about 7%; it is the only conventional air
pollutant to show an increase nationwide.
Electric utilities are a major contributor to NO<INF>X emissions
nationwide: in 1980, they accounted for 30 percent of total NO<INF>X
emissions and, from 1980 to 1990, their contribution rose to 32 percent
of total NO<INF>X emissions. In 1994, electric utility emissions
represented about 33 percent of the total annual NO<INF>X emissions.
Approximately 90 percent of estimated electric utility NO<INF>X
emissions were attributed to coal combustion (see docket item IV-A-8
(USEPA, National Air Pollution Emission Trends, 1900-1994 (EPA-454/R-
95-011) at 2-2, October 1995)).

The NO<INF>X emissions discharged into the atmosphere from the
burning of fossil fuels consists primarily of nitric oxide (NO). Much
of the NO, however, reacts with organic radicals in the air to form
nitrogen dioxide (NO<INF>2) and, over longer periods of time, reacts
with and forms other pollutants, including ozone (O<INF>3), nitric acid
(HNO<INF>3) and fine particles. These pollutants are harmful to public
health and the environment.

NO<INF>2 and airborne nitrate also degrade visibility, and when
they return to the earth through rain, snow, or fog (``wet
deposition'') or as gases (``dry deposition''), they contribute to
acidification of lakes and streams and to excessive nitrogen loadings
to estuaries and coastal water systems such as in the Chesapeake Bay
(``eutrophication'').

NO<INF>2 has been documented to cause eye irritation, either by
itself or when oxidized photochemically into peroxyacetyl nitrate
(PAN). Ozone, the most abundant of the photochemical oxidants, is a
highly reactive chemical compound which can have serious adverse
effects on human health, plants, animals, and materials. Fine particles
at current ambient levels contribute adversely to morbidity and
mortality.

[[Page 67113]]

B. Summary of Final Rule

NO<INF>X Standards Promulgated by This Rule
EPA today is promulgating new emission limitations to be
implemented for nitrogen oxides (NO<INF>X) emissions for wall-fired and
tangentially fired boilers (Group 1 boilers) and establishing emission
limitations for certain other boilers (Group 2 boilers). The final rule
implements section 407 (b)(2) of the Act, which applies to NO<INF>X
emission limitations for Group 1 and Group 2 boilers during Phase II of
the Acid Rain Program (January 1, 2000 and beyond). Under section
407(b)(2) the Administrator ``may revise'' the applicable NO<INF>X
emission limitations for Group 1 boilers in Phase II if the
Administrator determines that ``more effective low NO<INF>X burner
technology is available,'' i.e., that data on the effectiveness of low
NO<INF>X burner technology (LNB) installed after passage of the Clean
Air Act Amendments of 1990 supports emission limitations more stringent
than the limitations established for Group 1 boilers during Phase I of
the Acid Rain Program pursuant to section 407(b)(1) of the Act. 42
U.S.C. 7651f(b)(2). Also under section 407(b)(2) of the Act, the
Administrator must establish NO<INF>X emission limitations (on a lb/
mmBtu annual average basis) for Group 2 boilers, which include wet
bottom boilers, cyclone boilers, cell burner boilers, and all other
types of utility boilers not classified as dry bottom wall-fired and
tangentially fired boilers, and must meet certain requirements in
establishing these limitations. In setting the final emission
limitations for Group 1 and Group 2 boilers, as summarized below, the
Administrator has met the requirements in section 407(b)(2) of the Act.

i. Revision of NO<INF>X Emission Limits for Phase II, Group 1 Boilers

The Agency has developed a computerized database containing
detailed information on the characteristics and emission rates of all
coal-fired units with Group 1 boilers on which low NO<INF>X burners
(LNBs) have been installed without any other NO<INF>X controls, and for
which EPA has both quality assured long-term post-retrofit hourly
NO<INF>X emission rate data, measured by continuous emission monitoring
systems (CEMS), certified pursuant to 40 CFR part 75 (Acid Rain
Continuous Emission Monitoring Rule), and quality assured short-term
CEM or test data measurements of uncontrolled emission rates. This
database, called the ``LNB Application Database,'' consists of 39 dry
bottom wall-fired boilers and 14 tangentially fired boilers and forms
the technical basis for EPA's evaluation of the effectiveness (percent
NO<INF>X removal) of LNBs applied to Group 1 boilers.
For the final rule, EPA has adopted a methodology that employs
``load-weighted annual average NO<INF>X emission rates'' over the full
``post-optimization period'' for evaluating the effectiveness of LNBs.
The post-optimization period includes all available data beginning with
the first hour of the low NO<INF>X period,1 when the LNBs were
operating under optimized NO<INF>X removal conditions, and extending to
the end of the entire data set, i.e., through June 30, 1996, the end of
the latest available reporting period from the Acid Rain Emissions
Tracking System (ETS). The post-optimization period contains quality
assured CEM data spanning at least 4 calendar months for every boiler
and at least 11 calendar months for most boilers (83%). In addition,
EPA applied a NO<INF>X/load weighting scheme, using hourly load data
reported for 1995, to develop ``load-weighted'' annual average NO<INF>X
emission rates from the data set (see discussion in section III.A.2.iii
of this preamble). Two advantages of using load-weighted annual average
NO<INF>X emission rates over the post-optimization period are that the
criteria used to define the ``post-optimization period'' take into
account the site-specific nature of the LNB equipment optimization and
operator training processes while the use of ``load weighting''
accounts for any potential impact of annual load dispatch patterns on
NO<INF>X emissions.

\1\ The ``low NO<INF>X period'' EPA used for assessing
performance of LNBs applied to Group 1 boilers was defined by
identifying the lowest average NO<INF>X emission rate each boiler
has sustained for at least 52 days, i.e., over a period of 1,248
hours when the boiler was operating and valid CEM data, measured by
CEMS certified pursuant to 40 CFR part 75, were available. (Data for
30 calendar days following estimated date boiler began operating
after shutdown for LNB retrofit are not used when making this
determination. See Table 1, DQO #4D).

Following the identification of appropriate LNB applications and
time period for analysis, EPA developed a two-part model to estimate:
(1) Annual average emission rates that can be sustained by LNBs
installed on Phase II units with Group 1 boilers and (2) percentile
distributions of Phase II units that can comply with various
performance standards. The first part of the model calculates the
percent reduction achievable by LNBs as a function of uncontrolled
emission rate, and the second part applies the estimated percent
reduction to boiler-specific uncontrolled emission rates for the
population of units that will be subject to any revised NO<INF>X
emission limitations in Phase II. EPA used the percentile distributions
to select reasonably achievable emission limits for the two types of
Group 1 boilers, where ``reasonably achievable'' is defined as the
controlled emission rate 85 to 90 percent of the affected population of
units can meet or exceed on an annual average basis.

EPA concludes that more effective low NO<INF>X burner technology
is available for dry bottom wall-fired and tangentially fired
boilers. Further, EPA concludes that for dry bottom wall-fired
boilers, 0.46 lb/mmBtu is a reasonable emission limitation that is
achievable using such technology. EPA estimates that 85 to 90% of
the Phase II dry bottom wall-fired boilers can achieve this emission
rate. The implementation of this standard, will result in an
additional NO<INF>X emissions reduction of approximately 90,000 tons
per year, beginning in 2000, below the emission levels anticipated
under the Phase I Acid Rain NO<INF>X Emission Reduction Rule (60 FR
18751, April 13, 1995).

Finally, EPA concludes that for tangentially fired boilers, 0.40
lb/mmBtu is a reasonable emission limitation that is achievable
using such technology. EPA estimates that 85 to 90% of the Phase II
tangentially fired boilers can achieve this emission rate. The
implementation of this standard will result in an additional
NO<INF>X emissions reduction of approximately 30,000 tons per year,
beginning in 2000, below the emission levels anticipated under the
Phase I Acid Rain NO<INF>X Emission Reduction Rule. As discussed
below, EPA exercises its discretion under section 407(b)(1) to adopt
these revised Group 1 NO<INF>X emission limitations because the
resulting additional reductions are a reasonable step toward
achieving necessary, significant NO<INF>X reductions and are
consistent with the guideline in section 401(b) concerning the level
of NO<INF>X reductions to be achieved.

ii. Establishment of Group 2 Emission Limitations

In order to meet the requirements of section 407(b)(2), EPA is
using the following methodology for establishing Group 2 emission
limitations:

First, EPA determines what NO<INF>X control technologies are the
best systems of continuous emission reduction available for each
category of Group 2 boilers. Further, EPA considers only technologies
for which there is reliable cost information on which to base a
determination of whether they are of comparable cost to LNBs, applied
to Group 1 boilers.

Second, EPA evaluates each such NO<INF>X control technology and
estimates the dollar cost per ton of NO<INF>X removed using the control
technology on each boiler in the Group 2 population that is in the
appropriate Group 2 boiler category. EPA then compares the dollar cost
per ton of NO<INF>X removed for each

[[Page 67114]]

NO<INF>X control technology applied to the Group 2 boiler category to
the dollar cost per ton of NO<INF>X removed for low NO<INF>X burners
applied to dry bottom wall-fired and tangentially fired boilers. Based
on this comparison, EPA determines whether the NO<INF>X control
technology applied to the Group 2 boiler category has a costeffectiveness
comparable to that of LNBs applied to Group 1 boilers.
Third, EPA estimates the percent change in electricity rates for
consumers resulting from costs (in mills per kilowatt-hour) associated
with the application of emission limitations on Group 2 boilers. This
value is then compared to the percent change in nationwide electricity
rates due to the establishment of emission limitations for LNBs on
Group 1 boilers. EPA also estimates the emission reductions that are
likely to be achieved and considers any other environmental impacts
likely to result from application of each NO<INF>X control technology.
Fourth, EPA assesses the performance (percent NO<INF>X reduction)
of each cost-comparable Group 2 control technology and applies that
reduction percentage to data on the uncontrolled emissions of each
boiler that is in the particular category of Group 2 boilers and that
will be subject to the Group 2 emission limitation. The emission
limitation that will be achievable by 85 to 90% of the boiler
population is generally selected, after taking account of energy and
environmental impacts, as the emission limitation for that category of
Group 2 boiler.

EPA concludes that for cell-burner fired boilers, 0.68 lb/mmBtu is
a reasonable emission limitation that meets the requirements of section
407(b)(2). For cell burner boilers, plug-in retrofits and non-plug in
retrofits are the best continuous control systems that are available
and meet the cost comparability requirement. EPA bases the emission
limitation on the use of these control technologies and estimates that
80% of the cell burner population can achieve the limitation. The
energy impact, i.e., impact of mills/kWh cost on electricity consumers,
of using these technologies to meet the emission limitation is small
and similar in magnitude to the energy impact of using LNBs on Group 1
boilers. The emission limitation will result in a total NO<INF>X
emissions reduction of approximately 420,000 tons per year, beginning
in 2000, without significant increases in other air pollutants or solid
waste. As discussed below, the resulting NO<INF>X reductions are a
reasonable step toward achieving necessary, significant NO<INF>X
reductions and are consistent with section 401(b).
EPA concludes that for cyclone fired boilers larger than 155 MWe,
0.86 lb/mmBtu is a reasonable emission limitation that meets the
requirements of section 407(b)(2). For cyclone fired boilers, gas
reburning, and SCR are the best continuous control systems that are
available and meet the cost comparability criteria. The energy impact,
i.e., impact of mills/kWh cost on electricity consumers, of using these
technologies to meet the emission limitation is small and similar in
magnitude to the energy impact of using LNBs on Group 1 boilers. EPA
bases the emission limitation on the use of these technologies and
estimates that 85 to 90% of the cyclone fired boiler population can
achieve the emission limitation. The emission limit will result in a
total NO<INF>X emissions reduction of approximately 225,000 tons per
year, beginning in 2000, without significant increases in other air
pollutants or solid waste. As discussed below, the resulting NO<INF>X
reductions are a reasonable step toward achieving necessary,
significant NO<INF>X reductions and are consistent with section 401(b).
EPA has decided not to set a NO<INF>X emission limitation for cyclone
boilers of 155 MWe or less.

EPA concludes that for wet bottom boilers larger than 65 MWe, 0.84
lb/mmBtu is a reasonable emission limitation that meets the
requirements of section 407(b)(2). For wet bottom boilers, gas
reburning, and SCR are the best continuous control systems that are
available and meet the cost comparability requirement. EPA bases the
emission limitation on the use of these technologies and estimates that
85 to 90% of the wet bottom boiler population can achieve the emission
limitation. The energy impact, i.e., impact of mills/kWh cost on
electricity consumers, of using these technologies to meet the emission
limitation is small and similar in magnitude to the energy impact of
using LNBs on Group 1 boilers. The emission limitation will result in a
total NO<INF>X emissions reduction of approximately 80,000 tons per
year, beginning in 2000, without significant increases in other air
pollutants or solid waste. As discussed below, the resulting NO<INF>X
reductions are a reasonable step toward achieving necessary,
significant NO<INF>X reductions and are consistent with section 401(b).
EPA has decided not to set a NO<INF>X emission limitation for wet
bottom boilers of 65 MWe or less.

EPA concludes that for vertically fired boilers 0.80 lb/mmBtu is a
reasonable emission limitation that meets the requirements of section
407(b)(2). For vertically fired boilers, combustion controls are the
best continuous control system available and meet the cost
comparability requirement. EPA bases the emission limitation on the use
of these technologies and estimates that 85 to 90% of the vertically
fired boiler population can achieve this emission limitation. The
energy impact, i.e., impact of mills/kWh cost on electricity consumers,
of using these technologies to meet the emission limitation is small
and similar in magnitude to the energy impact of using LNBs on Group 1
boilers. The emission limitation will result in a total NO<INF>X
emissions reduction of approximately 45,000 tons per year, beginning in
2000, without significant increases in other air pollutants or solid
waste. As discussed below, the resulting NO<INF>X reductions are a
reasonable step toward achieving necessary, significant NO<INF>X
reductions and are consistent with section 401(b). EPA has decided not
to set a NO<INF>X emission limitation for arch-fired boilers, a subset
of the vertically fired boiler category.
Finally, EPA has decided not to set a NO<INF>X emission limitation
for FBC boilers. Because these units are already low NO<INF>X emitters
by design, the NO<INF>X emissions reduction achieved by installing any
additional control technology, would not meet the cost-comparability
requirement of section 407(b)(2). Moreover, setting an emission
limitation that can be achieved by every existing FBC boiler without
installing any additional control technology would have an adverse
environmental impact. Some existing boilers emit at rates considerably
below the highest annual rate observed among FBC boilers and these
boilers could offset the emission reductions otherwise required of
other affected boilers through emissions averaging under Sec. 76.10.
EPA has also decided not to set a NO<INF>X emission limitation for
stoker boilers. EPA has not found any continuous control technology for
stoker boilers that meets the cost-comparability requirement.
2. Rationale for Revising Group 1 NO<INF>X Emission Limits and
Environmental Impact of Group 2 NO<INF>X Emission Limits
EPA is exercising its discretion to revise the Phase II, Group 1
NO<INF>X emission limitations because: (1) NO<INF>X emissions have
significant adverse effects on human health and the environment; (2)
significant, additional regional NO<INF>X reductions from current
levels are likely to be necessary; (3) without additional actions
NO<INF>X emissions are projected to increase

[[Page 67115]]

nationwide starting in 2002; (4) the revision of Phase II, Group 1
emission limitations is one of the most cost-effective means of
achieving additional NO<INF>X reductions; and (5) the additional
reductions from the revision represent a reasonable step toward
achieving necessary NO<INF>X reductions. In addition, the resulting
NO<INF>X reductions are consistent with section 401(b). The adverse
health and environmental effects of NO<INF>X emissions are discussed in
the proposed rule on Phase II NO<INF>X emission limitations. 61 FR
1442, 1453-55, January 19, 1996. EPA reaffirms that discussion, which
summarizes the adverse impact of NO<INF>X emissions through: The
formation of ozone, particulate matter, and nitrogen oxides; and
atmospheric deposition resulting in eutrophication of water bodies and
acidification of lakes and streams. For the same reasons, EPA also
concludes that the adoption of the Group 2 emission limitations set
forth in today's rule is supported by the environmental impact of the
emission reductions that will result.

The contribution of nitrogen oxides to the formation of ozone, acid
deposition and eutrophication of water bodies is substantial.
Consequently, in order to address these problems, significant NO<INF>X
emission reductions are likely to be needed on a regional scale,
particularly in the eastern half of the U.S. This is the portion of the
nation in which most of the boilers subject to NO<INF>X emission
limitations under the Acid Rain Program are located; 87% of Phase II,
Group 1 boilers and 89% of Group 2 boilers covered by today's final
rule are in the eastern U.S.

i. Ozone

With regard to ozone, additional regional NO<INF>X reductions of at
least 50% from current levels are likely to be needed over large
portions of the nation to attain and maintain the national ambient air
quality standard for ozone. Modeling results using EPA's Regional
Oxidant Model (ROM) estimated that NO<INF>X reductions of about 75%
will be needed over large portions of the nation to reduce ozone
concentrations to levels at or below the NAAQS (see docket item IV-J-8
(EXISTMOD.TXT, OTAG Modeling and Assessment Subgroup Files on EPA's TTN
Bulletin Board, February 7, 1996)). The ROM modeling results were among
the reasons for the formation of the Ozone Transport Assessment Group
(OTAG), comprised of the 37 eastern-most States and tasked with
developing a consensus approach for reducing regional NO<INF>X
emissions. OTAG recently completed atmospheric modeling simulations
using SAI's Urban Airshed Model (UAM-V) (see docket item IV-J-21 (OTAG
Air Quality Analysis Workgroup, 1996)). The results indicate that:
broad NO<INF>X emission reductions will decrease regional ozone, high
ozone, and ozone in non-attainment areas; and NO<INF>X emission
reductions in each OTAG sub-region will be needed to both lower ozone
in that same sub-region, as well as other sub-regions.
Further, necessary NO<INF>X reductions to achieve or maintain the
ozone standard have been estimated for several other areas of the
country: 50-75% from 1990 levels throughout the Northeast Ozone
Transport Region (OTR) (60 FR 4712, 4722, January 24, 1995); up to 90%
reductions in the Southeast (see docket item II-I-98 (State of the
Southern Oxidants Study, 1995)); and a combination of 75% reductions
for NO<INF>X and 25% for VOCs regionally, combined with 25% for
NO<INF>X and 75% for VOCs locally in the New York region (60 FR 4721);
and significant NO<INF>X reductions in the Lake Michigan area, not yet
quantified. The results of a study analyzing ozone non-attainment in
the eastern U.S. found that nationwide NO<INF>X emission reductions of
about 50% from 1990 levels will be needed to approach achievement of
the necessary ozone standards (see docket item IV-J-9 (Rao, S.T.,
et.al., Dealing with the Ozone Non-Attainment Problem in the Eastern
United States, AWMA journal, January 1996)).

ii. Acid Deposition

Similarly, additional, regional NO<INF>X reductions of at least 40%
are likely to be necessary in order to mitigate the effects of acid
deposition. In particular, it is estimated that between 40-50%
reductions of NO<INF>X in the Eastern U.S. beyond those already
required in the Clean Air Act may be necessary simply to keep the
number of acidified lakes in the Adirondacks in New York at 1984
levels. (See docket item IV-A-6 (Acid Deposition Standard Feasibility
Study (EPA 430-R-95-001a) at xvi).) Without additional reductions, the
number of acidic lakes in the Adirondacks are projected to increase by
almost 40% by 2040. Id. at 47. Significant, additional reductions may
also be necessary with regard to the Mid-Appalachian region (see docket
item IV-A-6 (Acid Deposition Standard Feasibility Study at xvi)).

iii. Eutrophication

NO<INF>X emissions also contribute significantly to eutrophication,
i.e., an overabundance of nitrogen to water bodies that leads to
problems of nutrient enrichment. Regional NO<INF>X emission reductions
of up to 40% are likely to be needed. The signatories to the Chesapeake
Bay Agreement, (Maryland, Pennsylvania, Virginia, the District of
Columbia, the Chesapeake Bay Commission, and the federal government)
have agreed on a goal of a 40% reduction in nitrogen loadings to the
Bay by 2000 (relative to a 1985 baseline), representing a reduction of
34 million kilograms of nitrogen (see docket item IV-J-11 (Hicks et
al., 1995:6)). In addition, they agreed to maintain, after 2000, a cap
on nitrogen loadings at 60% of baseline loadings. Present estimates are
that approximately 27% of total nitrogen loading to the Bay system
comes from atmospheric sources in the form of NO<INF>X emissions (see
docket items IV-J-26 (Linker et al., 1993) and IV-J-19 (Valigura et
al., 1995)). Since reducing nitrogen loading through the control of
NO<INF>X emissions can be as cost-effective as controlling nonatmospheric
sources of nitrogen loading (e.g., point sources such as
waste water treatment and non-point sources such as farms), up to a 40%
reduction of the contribution in NO<INF>X emissions to the Bay in areas
contributing to the eutrophication of the Bay is likely to be
necessary.

Although the watershed of the Chesapeake Bay encompasses
approximately 64,000 square miles, the Chesapeake Bay ``airshed,''
which is the contiguous area providing 70% of the atmospheric
deposition loads to the watershed (see docket item IV-J-18 (Dennis,
1996)), covers up to 600,000 square miles in area (see docket item IVJ
-3 (Valigura et al., 1996:23)). The airshed extends upwind of, as well
as bordering the water body itself: south to South Carolina, north to
Ontario, Canada, and westward up to 500 miles (see docket item IV-J-11
(Hicks et al., 1995:6)). NO<INF>X emissions from outside this area not
only contribute to eutrophication in the Bay but also to the entire
coastline, such as from the Carolinas to New York (see docket item IVJ
-3 (Valigura et al., 1996:23)).

iv. Utility Contribution to Atmospheric NO<INF>X Emissions

Electric utilities contributed approximately 33% of total
atmospheric NO<INF>X emissions in 1994, thus substantially contributing
to ozone formation, acid deposition, and eutrophication.
Table 1 summarizes the reductions in atmospheric NO<INF>X emissions
likely needed and the additional reductions provided by today's final
rule. Although the additional reductions from coal-fired utility
boilers under the final rule are substantial, they represent only

[[Page 67116]]

about 5% of all atmospheric NO<INF>X emissions from all sources of
NO<INF>X emissions. The additional reductions under the final rule
represent about a 15% reduction in total utility emissions. Since
utilities presently contribute about 33% of total NO<INF>X emissions,
the final rule provides reductions of about 5% of total NO<INF>X
emissions. This reduction level is significantly less than the
reduction level likely to be needed to mitigate ozone, acid deposition,
and eutrophication (see docket item IV-A-8 (EPA, ``National Air
Pollution Emission Trends, 1900-1994'' at 2-2, October, 1995, EPA-454/
R-95-011)).

Table 1.--Estimated Regional Reductions Necessary to Mitigate Various Environmental Effects

Environmental effect

Ozone Acid deposition Eutrophication

Regional NO<INF>X Reductions Necessary.... More than 50%.......... More than 40%.......... Up to 40%
NO<INF>X Reductions Achieved from the 5%..................... 5%..................... 5%
Final Rule as Percentage of Total
NO<INF>X Emissions.

v. NO<INF>X Reductions Not Sustained

Although national NO<INF>X emissions are expected to decrease up to
the year 2000, (see docket item IV-A-8 (EPA, ``National Air Pollution
Emission Trends, 1900-1994'' at 5-5, October, 1995, EPA-454/R-95-011)),
emissions are projected to begin increasing after 2000 (id. at 5-2 and
6-8 2). The existing NO<INF>X control programs under the Clean Air
Act (including the Mobile Source Program under title II and the Acid
Rain NO<INF>X Program under title IV) limit NO<INF>X emission rates
(e.g., the pounds of NO<INF>X emissions per amount of fuel consumed
(under title IV)) for emission sources. The programs do not cap the
total tonnage of nationwide emissions. As the number of emission
sources and the use of emission sources increases, reductions due to
emission rate limitations are offset to an increasing extent. For this
reason, after 2002, when implementation of these NO<INF>X control
programs is largely completed and growth in sources and source use
continues, NO<INF>X emissions will gradually increase for the
foreseeable future (id. at 5-5). Section 401(b) of the Act suggested,
as a guideline, that NO<INF>X emissions should be reduced nationwide by
2 million tons from the 1980 level. By about 2006, total NO<INF>X
emissions will surpass that guideline unless additional efforts are
made (e.g., under title IV) to reduce NO<INF>X emissions (See figure 1,
below). The projected increase in total NO<INF>X emissions is well
within the time frame considered by Congress in title IV. EPA notes
that the nationwide annual cap for SO<INF>2 emissions, also established
under section 402, begins to apply in the year 2010. Until 2010, total
annual allocated SO<INF>2 allowances will exceed the cap, because of
additional allowances allocated under section 409 for repowered units
and bonus allowances under section 405. Additional NO<INF>X reductions,
such as these under today's final rule, are necessary both in light of
the likely need to reduce NO<INF>X to address ozone, acid deposition,
and eutrophication, and in light of the NO<INF>X reduction guideline in
section 401(b) of the Act. In short, new initiatives are needed to
reduce NO<INF>X emissions on a regional scale in order to improve
environmental quality and health beyond 2000.

\2\ Report's projections take into account requirements for
Reasonably Available Control Technologies (RACT) under title I,
enhanced programs for inspection and maintenance of mobile sources
under title I, and title IV Group 1 emission limits promulgated
April 13, 1995 (id. at 6-8, (assuming, for analytical purposes, that
title IV emission limits are set at RACT)).

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[[Page 67117]]

[GRAPHIC] [TIFF OMITTED] TR19DE96.000

BILLING CODE 6560-50-C

vi. Cost-Effectiveness

The revision of Phase II, Group 1 emission limitations and
establishment of Group 2 emission limitations is a cost-effective means
of achieving the likely necessary, additional regional NO<INF>X
reductions. The control technologies on which the revised Group 1
limits and the Group 2 limits are based are more cost-effective (i.e.,
have a lower cost per ton of NO<INF>X removed) when applied to the
respective Group 1 and Group 2 boiler types than most other control
technologies applied to these boiler types or to non-utility sources.
As shown below, the dollar cost per ton of NO<INF>X removed for
reductions under the final rule is less than, or at the lower end of,
the range of dollar cost per ton of NO<INF>X removed for most
alternative reductions. In short, the NO<INF>X reductions achievable
under this final rule are among the less expensive that can be made.

[[Page 67118]]

Utility Sources: For coal-fired utility boilers using higher level
control technologies, (e.g., SCR with higher NO<INF>X reduction
capability) than the technologies on which the title IV limits are
based, the average cost-effectiveness for typical wall-fired boilers
ranges from $1,226/ton to $1,670/ton with percent reductions ranging
from 60-90%. For typical tangentially fired boilers, the costeffectiveness
ranges from $1,439/ton to $1,935/ton with percent
reductions ranging from 60-90%. For typical cyclone boilers, the costeffectiveness
ranges from $440/ton to $880/ton with percent reductions
ranging from 60-90%. For typical cell-burner boilers, the costeffectiveness
ranges from $624/ton to $801/ton with percent reductions
ranging from 60-80%. For typical wet bottom boilers, the costeffectiveness
ranges from $572/ton to $733/ton with percent reductions
ranging from 60-90%. For typical roof-fired (vertically-fired) boilers,
the cost-effectiveness ranges from $750/ton to $907/ton with percent
reductions ranging from 60 to 90%. For typical oil and gas utility
boilers, the average cost-effectiveness for wall-fired dual-fired
boilers under various NO<INF>X reduction technologies ranges from $748/
ton to $2,263/ton with percent reductions ranging from 40-90%. For
typical tangentially fired dual-fired boilers, the cost-effectiveness
ranges from $507/ton to $1,573/ton with percent reductions ranging from
30-90% (see docket item IV-J-4 (Ozone Transport Assessment Group,
Control Technologies and Options Workgroup, Final Report, April 11,
1996)).

As compared to the cost-effectiveness ranges for higher level
control technologies applied to typical utility boilers, the average
cost-effectiveness for meeting the Group 1 and Group 2 emission limits
under today's final rule, using the control technologies on which the
limits are based, is approximately $229/ton of NO<INF>X removed.
Non-Utility Point Sources: Non-utility point sources NO<INF>X
reductions are less cost effective, on average, than NO<INF>X
reductions under today's final rule. For example, the average costeffectiveness
for process heaters ranges from $290-50,000/ton at an
average reduction of 5-90%. For cement manufacturing, the average costeffectiveness
ranges from $470-4,870/ton at an average reduction of 20-
90%. For wood manufacturing, the average cost-effectiveness ranges from
$1,000 to over $10,000/ton at an average reduction of 0-60% (see docket
item IV-J-4 (Ozone Transport Assessment Group, Control Technologies and
Options Workgroup, Final Report, April 11, 1996)).
Mobile Sources: For mobile sources, the cost-effectiveness under
various NO<INF>X control options is also high, on average, as compared
to reductions under today's final rule. For example, the average costeffectiveness
for light-duty on highway vehicles ranges from $1,100-
$260,000/ton, with percent reductions ranging from 0.2-21%. For heavyduty
on highway vehicles, the average cost-effectiveness ranges from
$1,000/ton to $40,000/ton, with percent reductions ranging from 0.02-
5.6%. For non-road sources, the average cost-effectiveness ranges from
$119/ton to $23,000/ton, with percent reductions ranging from 0.4-3.4%
(see docket item IV-J-6 (Mobile Sources Assessment: NO<INF>X and VOC
Reduction Technologies for Application by the Ozone Transport
Assessment Group, Final Report, March 4, 1996)).
Table 2 summarizes the cost-effectiveness ranges of NO<INF>X
controls for the three major NO<INF>X emitting sources, as compared to
the cost-effectiveness of reductions under the revised Group 1 limits
and Group 2 limits.

Other: The reductions from applying control technologies to coalfired
power plants under today's final rule can be as cost-effective to
achieve as reductions from other point sources (e.g., wastewater
plants) and area sources (e.g., farms, animal pastures). Studies
concerning eutrophication in the Chesapeake Bay estimate the following
average cost-effectiveness of control technologies applied to nonutility
sources: chemical addition or biological removal of nitrogen
from wastewater processing, $4,000 to over $20,000/ton of nitrogen
removed; and management practices to reduce nitrogen from fertilizers,
animal waste, and other non-point sources, $1,000 to over $100,000/ton
of nitrogen removed (see docket items IV-J-25 (Camacho, 1993:97-98) and
IV-J-27 (Shulyer, 1995:6)).

Table 2.--Average Cost-Effective of NO<INF>X Controls by Source
[Utility, other point source, mobile]

Range in typical
cost- Percent
effectiveness ($/ reduction
ton)

Utility sources (Coal w/advanced NO<INF>X
controls):

Wall-fired........................... $1,226-1,670 60-90
Tangentially-fired................... 1,439-1,935 60-90
Cyclones............................. 440-880 60-90
Cell burners......................... 624-801 60-80
Wet bottoms.......................... 572-733 60-90
Roof (vertically-fired).............. 750-907 60-90
Utility sources (Oil and Gas):

Wall dual-fired...................... 748-2,263 40-90
Tangential dual-fired................ 507-1,573 30-90

Source: Ozone Transport Assessment Group, Control Technologies and
Options Workgroup, Final Report, April 11, 1996.

Average cost-
effectiveness Percent

Title IV phase II NO<INF>X rule of Sec. reduction
407(b)(2) ($/ under Sec.
ton) 407(b)(2)

Group 1 and group 2..................... $229 20

See section IV.B (Table 17) of this preamble.

[[Page 67119]]

Range in typical
cost- Percent

Non-utility point sources effectiveness ($/ reduction
ton)

Non-utility boilers...................... $490-19,600 5-90
Process heaters.......................... 290-50,000 20-90
I.C. engines............................. 180-13,400 5-98
Gas turbines............................. 130-2,760 60-90
Residential fuel combustion.............. 1,600-62,500 50-100
Cement manufacturing..................... 470-4,870 20-90
Metals processing........................ 120-11,600 12-96
Wood manufacturing....................... 1,000-10,000+ 0-60
Agriculture chemical manufacturing....... 76-715 44-99
Incineration.................. 800-10,000 10-77
Source: Ozone Transport Assessment Group, Control Technologies and
Options Workgroup, Final Report, April 11, 1996.

Range in typical
cost- Percent

Mobile sources effectiveness ($/ reduction
ton)

Light-duty (on highway).................. $1,100-260,000 0.2-21
Heavy-duty (on highway).................. 1,000-40,000 0.02-5.6
Non-road................................. 119-23,000 0.4-3.4
Source: Mobile Sources Assessment: NO<INF>X and VOC Reduction Technologies
for Application by the Ozone Transport Assessment Group, Final Report,
March 4, 1996.

Average cost-
effectiveness Percent

Title IV phase II NO<INF>X rule of Sec. reduction
407(b)(2) ($/ under Sec.
ton) 407(b)(2)

Group 1 and Group 2..................... $229 20

vii. Need to Revise Group 1 Limits and Establish Group 2 Limits

As discussed above, in order to mitigate adverse effects on health
and the environment due to NO<INF>X emissions, significant, additional
reductions in regional atmospheric NO<INF>X emissions from current
levels are likely to be necessary. Further, the contribution of the
final rule toward the overall NO<INF>X reduction goal is approximately
5%. The NO<INF>X reductions under the rule represent only a portion of
the much larger NO<INF>X reductions likely to be needed and are among
the most cost-effective reductions available. EPA concludes that the
reductions under the final rule represent a reasonable step toward
achieving necessary NO<INF>X reductions.
Some commenters suggested that, because the authority to revise the
Phase II, Group 1 emission limitations and to issue Group 2 emission
limitations arises under title IV of the Clean Air Act, EPA must
consider only the acidification impacts of NO<INF>X emissions in
deciding whether to revise or issue limitations. Allegedly, all other
impacts must be addressed only under other provisions of the Act. EPA
rejects this crabbed view of its authority under section 407(b)(2) as
having no basis in statutory language or logic. In granting EPA the
authority to decide to revise the Phase II, Group 1 emission
limitations, section 407(b)(2) only requires a determination of the
availability of more effective LNB technology and does not bar
consideration of non-acidic deposition impacts. Similarly, in requiring
EPA to issue Group 2 emission limitations, section 407(b)(2) sets forth
several criteria for setting the limitations but none of the criteria
bars consideration of non-acidic deposition impacts. On the contrary,
section 407(b)(2) has a general requirement that EPA take account of
``environmental impacts'' in setting Group 2 emission limitations. 42
U.S.C. 7651f(b)(2).

In the absence of a statutory bar on considering all environmental
impacts of NO<INF>X emissions and in light of the general purpose of
the Clean Air Act to, inter alia, ``protect and enhance the quality of
the Nation's air resources so as to promote the public health and
welfare and the productive capacity of its population'', it would be
illogical for EPA to focus exclusively on acid deposition.3 42
U.S.C. 7401(b)(1). The latter approach would require EPA to regulate on
a piecemeal basis and to blindly ignore a major part of the harmful
effects of NO<INF>X emissions when setting nationwide NO<INF>X emission
limits under title IV. In any event, EPA maintains that, even if the
Agency were confined to considering only the acidic deposition effects,
referred to above, of NO<INF>X emissions, it would still conclude that
additional NO<INF>X reductions are necessary and that the emission
limitations set forth in today's rule should be adopted.

\3\ Although, as discussed below, section 401(b) states that the
general purpose of title IV is ``to reduce the adverse effects of
acid deposition'', this provision should not be interpreted as
barring consideration of other environmental impacts for purposes of
setting emission limitations under section 407. 42 U.S.C. 7651(b).
EPA's interpretation--which harmonizes sections 101(b)(1) (stating
the general purposes of the Clean Air Act) and 401(b) (stating the
general purposes of title IV)--is that, while the primary focus in
promulgating regulations under title IV is reduction of acidic
deposition, other environmental impacts may also be considered.

Some commenters also noted that section 401(b) states that the
purpose of title IV is to reduce acidic deposition through reduction of
annual SO<INF>2 emissions of ten million tons from 1980 levels ``and,
in combination with other provisions of this Act, of nitrogen oxides
emissions of approximately two million tons from 1980 emission levels,
in the forty-eight contiguous States and the District of Columbia.'' 42
U.S.C. 7651(b). According to such commenters, because this goal is
already met by the existing Phase II, Group 1 emission limitations (as
well as by regulations under other parts of the Clean Air Act), there
is no basis for revising the limitations. However, section 401(b)
provides only general guidance concerning implementation of title IV
and, in light of the imprecision of its language, does not--and was not
intended to--impose an absolute limit on the amount of NO<INF>X
reductions that can be required under emission limitations promulgated
under section 407.

In contrast to the SO<INF>2 provisions of title IV, which set a
nationwide cap on total tonnage of SO<INF>2 emissions (i.e., 8.95
million tons starting in 2010), the NO<INF>X provisions of title IV
provide only for limits on the NO<INF>X emitted per mmBtu of fuel
burned. Even if the NO<INF>X emission limitations are met, increased
use of existing coal-fired and other

[[Page 67120]]

utility boilers in the future in response to growth in demand for
electricity can result in increased tonnage of NO<INF>X emissions. The
NO<INF>X emissions reductions projected to be achieved through adoption
of any given set of NO<INF>X emission limitations under title IV are
therefore not permanent. For this reason, when EPA estimates NO<INF>X
reductions resulting from title IV emission limitations, the estimates
are tied to a specific year, in this case the year 2000. Regulatory
Impact Analysis of NO<INF>X Regulations at 1-7 and 1-8, December 8,
1995. Moreover, as discussed above, total NO<INF>X emissions are
projected to decline through 2000, increase thereafter, and exceed the
two million guideline by around 2006. In short, the commenters' claim
that a two-million-ton emission reduction ``goal'' is ``satisfied'' by
the existing Group 1 emission limitations is inaccurate because a twomillion
-ton level of reductions from 1980 achieved for a given year
(e.g., for 2000) through these limitations is unlikely to be
maintained, in the near future without further reductions.
Although EPA maintains that the 2 million ton guideline in Section
401(b) aims at total NO<INF>X emissions of 2 million tons below the
1980 levels, EPA notes that the final rule will result in total Group 1
and Group 2 boiler NO<INF>X emissions around 2 million tons less than
what they otherwise would have been in 2000. The annual NO<INF>X
reductions anticipated from the existing Group 1 emission limitations
under the April 13, 1995 rule and additional annual reductions
anticipated from the Phase II, Group 1 and Group 2 emission limitations
under today's final rule are about 1,170,000 tons and 890,000 tons
respectively for the year 2000, for a total of about 2,060,000 tons.
EPA's current estimate of reductions from the April 13, 1995 rule is
lower than the reductions originally estimated (i.e., about 1,890,000
tons for the year 2000) for that rule. 59 FR 13538, 13562-63 (March 22,
1994); see also 59 FR 18760 (adopting for April 13, 1995 rule the
Regulatory Impact Analysis originally promulgated for the March 22,
1994 rule).

In making the original estimates of reductions, EPA used emissions
factors (i.e., estimated uncontrolled emission rates based on coal type
and boiler type) to determine the uncontrolled emissions of boilers to
which the existing Group 1 emission limitations were to be applied. In
response to comment in today's rulemaking concerning the inaccuracy of
emission factors, EPA has minimized its use of emission factors and
instead relied almost exclusively on actual, short-term, uncontrolled
emissions data from continuous emissions monitoring obtained during
annual monitor certification testing (i.e., CREV data) or submissions
of CEM, EPA reference method, or other test data by utilities. This
data was not generally available to EPA when the April 13, 1995 rule
was published.4 As a result of using more accurate uncontrolled
emissions data, EPA's estimates of anticipated reductions under the
existing Group 1 emission limitations are now more accurate and are
lower. Even if section 401(b) were viewed as imposing a ``ceiling'' of
``approximately two million tons'' of NO<INF>X reductions under section
407, the reductions anticipated under the emission limitations adopted
in the April 13, 1995 rule and today's final rule are consistent with
that ``ceiling.''

\4\ For the January 19, 1996 proposal in the instant rulemaking,
EPA replaced many, but not all, of the emissions factors with actual
data, which resulted in estimated annual reductions under the
current Group 1 emission limitations of about 1,540,000 million
tons. See Regulatory Impact Analysis for the proposed rule (docket
item II-F-2).

For the reasons discussed above, EPA concludes that it should
exercise its discretion under section 407(b)(2) to revise the Phase II,
Group 1 emission limitations. The revised Group 1 limits represent a
reasonable step toward achieving the significant NO<INF>X reductions
that are likely to be necessary, and are consistent with the 2 million
ton guideline for NO<INF>X reductions. The revision of the Group 1
emission limitations will result in about 120,000 tons of additional
annual NO<INF>X reductions. Actions to achieve NO<INF>X reductions
beyond those realized under title IV are being considered, or will be
considered in the future, under other titles of the Clean Air Act.
Unlike the Group 1 limitation revisions, which are discretionary
under section 407(b)(2), the issuance of Group 2 emission limitations
is mandatory under that section so long as the requirements of the
section (e.g., cost comparability) are met. However, as noted above,
EPA is required, when setting Group 2 emission limitations under
section 407(b)(2), to consider environmental impacts. EPA's application
of the section 407(b)(2) requirements for setting Group 2 emission
limitations--including the consideration of environmental impacts--is
set forth in detail below in section III.B of this preamble. EPA
concludes that, like the Group 1 revisions, the Group 2 emission
limitations supported and adopted in that section of the preamble
represent a reasonable step toward achievement of necessary,
significant NO<INF>X reductions and are consistent with the 2 million
ton guideline for NO<INF>X reductions.

II. Public Participation

Regulations were proposed in the Federal Register on January 19,
1996 (61 FR 1442). The notice invited public comments and copies of the
proposed rule were made available to interested parties.
EPA held a public hearing to provide interested parties the
opportunity for oral presentation of data, views, or arguments
concerning the proposed regulations. The hearing was held on February
8, 1996 in Washington, DC. Four persons testified at the hearing
concerning issues related to the proposed regulations. The hearing was
open to the public, and each attendee was given an opportunity to
comment on the proposed regulations. (See docket items IV-F-1, IV-F-2
and IV-F-3.) The initial public comment period (January 19, 1996 to
March 4, 1996) was extended by two weeks to March 19, 1996 to allow
additional time for inspection of interagency review materials which
EPA added to the docket on January 26, 1996. (See docket item III-A-2.)

III. Summary of Major Comments and Responses

EPA received approximately 100 comment letters regarding the
proposed regulations, presenting more than 200 issues. Commenters
included public and municipal utilities, utility associations, state/
local agencies and Attorneys General, environmental organizations,
vendors, general industry, research/trade groups, and private citizens.
A copy of each comment letter received is included in the rulemaking
docket. A list of commenters, their affiliations, and the EPA docket
item number assigned to their correspondence is included in the
background information document.

All of the comments have been carefully considered, and where
determined to be appropriate by the Administrator, changes have been
made in the final regulations. The background information document
includes a summary of all the comments and EPA's response on each of
the relevant issues. The following sections of the preamble provide a
summary of the major comments received and the Agency's response to
those major comments.

[[Page 67121]]

A. Phase II, Group 1 Boiler NO<INF>X Emission Limits

Boiler Population Used To Assess NO<INF>X Emission Limits
Background. For the proposed rule, EPA developed a computerized
boiler database containing detailed information on the characteristics
and pre-retrofit and post-retrofit emission rates of coal-fired units
with Group 1 boilers on which low NO<INF>X burners (LNBs) had been
installed without any other NO<INF>X controls (``the LNB Application
Database''). This database contained all known applications of LNBs to
Group 1 boilers that were installed subsequent to 11/15/90 (the date of
enactment of the 1990 amendments to the CAA) and for which EPA had at
least 52 days of quality assured post-retrofit data measured by
continuous emission monitors (CEMs) certified according to 40 CFR part
The 24 wall-fired boilers and 9 tangentially fired boilers in this
database formed the empirical basis for EPA's assessment of the
effectiveness of low NO<INF>X burner technology and the revised annual
NO<INF>X emission limitations provisions for Group 1 boilers in the
proposed rule.

Comment/Analyses: EPA received approximately 25 comment letters
(from 19 utilities, 3 utility associations, 2 states, and an
environmental organization) on the appropriateness of including or
excluding certain boilers and the selection criteria used to define
eligibility for the LNB Application Database.
Several commenters suggested that EPA include specific boilers to
increase the size and improve the representativeness of the
tangentially fired subset in the LNB Application Database: Riverbend 7
and 8, Allen 1 and 3, J.H. Campbell 3, Gallatin 4, and Lansing Smith 2
(see, for example, docket items IV-D-22, p. 1; IV-D-21, pp. 2-3; IV-D-
20, pp. 7-9, and IV-D-65, p. 22). The commenters acknowledged that many
of these retrofit cases did not satisfy the quality assurance criteria
that EPA had established for inclusion in the LNB Application Database.
They believed, however, that the general benefits of broadening the
experiential basis for tangentially fired boilers outweighed specific
data quality concerns. As one commenter said, ``Although not [based on]
CEM data, Gallatin Unit 4's performance test result of 0.47 lb/10
6 Btu is reliable, relevant evidence * * * and should be
considered by EPA.'' (See docket item IV-D-20, p. 9.)
Commenters also suggested that EPA include specific boilers to
improve the representativeness of the wall-fired subset in the LNB
Application Database, particularly with respect to boilers with high
uncontrolled emission rates: Hammond 4, Watson 4 and 5, Valley 1 and 2
(see, for example, docket items IV-D-65, p.22). Several commenters
cited additional wall-fired retrofit cases within the context of the
related issue of the dependence of NO<INF>X emissions on boiler load:
Conesville 3, Picway 9, Amos 1 and 2, Big Sandy 2, Glen Lyn 6, Colbert
5, Valley 1-4; Presque Isle 5 and 6 (see docket items IV-D-73, p.1; IVD
-20, p.5; IV-D-26, p.2).

On the other hand, several commenters fully endorsed the quality
assurance criteria EPA has used to determine eligibility for the LNB
Application Database (see, for example, docket items IV-D-063, p.12;
IV-D-046, p.3-4). They said that EPA properly excluded older LNB
installations (such as Gallatin 4, Lansing Smith 2, and Hammond 4) for
which quality assured long-term post-retrofit CEM data did not exist.
(EPA notes that this criterion generally excludes experimental or
otherwise short-lived LNB installations such as those used for
technology demonstrations, and the Allen units.5) These commenters
also recommended that EPA should attach greater significance to (or
rely exclusively on) LNB applications in the 13-state Northeast Ozone
Transport Region (OTR) for the evaluation of LNB technology
effectiveness because these applications have been required to meet a
NO<INF>X emission limit beginning May 31, 1995, whereas most other
applications have not had to comply with a recently established
NO<INF>X standard.

\5\ The Allen plant is located in Gaston County, NC, which,
until July 1995, was considered in non-attainment for ozone. The
utility installed LNBs on two Allen boilers, the vendor is reported
to have optimized in mid 1995. In July 1995, Gaston County was
redesignated to ozone attainment and low NO<INF>X operation was
discontinued on Allen 1 and 3 on September 1, 1995 (see docket item
IV-D-22, p. 1). As a result, Allen units 1 and 3 each have less than
52 days of emissions data after optimization of their respective
LNBs.

Some commenters correctly noted that one wall-fired boiler in the
LNB Application Database used for the proposed rule analysis, North
Valmy 1, should be excluded because this boiler had pre-existing
NO<INF>X controls (i.e., Babcock and Wilcox (B&W) DRB version LNBs) so
its baseline measurement does not represent an uncontrolled emission
rate. EPA notes that this NSPS boiler, when retrofitted with modern
LNBs (i.e., B&W XCL version), has sustained an average post-retrofit
controlled emission rate of 0.264 for calendar year 1995 (see docket
item II-A-9). ``NSPS boilers'' are new coal-fired utility units on
which construction commenced after August 17, 1971, which are subject
to New Source Performance Standards (NSPS) (40 CFR part 60, subparts D
or Da). Some NSPS boilers had early versions of LNBs and/or some other
type of NO<INF>X combustion control installed as original equipment.
EPA has excluded these ``controlled NSPS boilers'' from the LNB
Application Database and regression models because their measured
baseline emission rates do not generally represent uncontrolled
emissions. EPA has included all NSPS boilers, both controlled and those
without built-in NO<INF>X combustion control equipment, in the Phase
II, Group 1 boiler set to which the models are applied since NSPS
boilers represent approximately one third of the units affected by this
rulemaking.

One commenter recommended that EPA exclude two boilers, Coleman C1
and Pulliam 7, because, according to this commenter, these boilers have
low NO<INF>X combustion controls beyond the LNB definition in 40 CFR
76.2. EPA disagrees with this commenter's opinion that these two
retrofits include auxiliary combustion air outside the waterwall hole
which are `` `staging' combustion on active burners analogous to
overfire air'' (see docket item IV-D-51, p. 9). EPA also notes that
another commenter, who represents 67 utilities, included both units in
their regression analyses on the performance of LNBs applied to wallfired
Group 1 boilers (see docket item IV-D-65, p. 58 and Enclosure 8,
Table 4-1). DOE included Coleman C1 in its regression analyses, but
excluded Pulliam 8 (probably because, as EPA learned after the rule
proposal, the utility switched to Powder River Basin coal for both
Pulliam 7 and 8) (see docket item II-D-62).
Some commenters recommended that EPA include Group 1 boilers that
installed both LNB and overfire air (OFA) in the LNB Application
Database, primarily because they believe units with high uncontrolled
emission rates were under-represented in the proposed rule analysis
(see, for example, docket item IV-D-58, p. 4). These commenters
provided supporting data for certain boilers, including: Eastlake 1, 3,
and 4; and Ashtabula 7 (see docket item IV-D-23, p. 5). As discussed
later in this section of the preamble, EPA disagrees with this
recommendation. First, OFA cannot be considered in determining whether
to revise the Group 1 limits and the assessment of the achievable
performance of LNBs alone is problematic when LNBs are used in
combination with other technologies. Further, the addition of 20 units
to the LNB Application Database has

[[Page 67122]]

significantly improved the robustness of EPA's regression models for
units with high uncontrolled emission rates.
Several commenters agreed with EPA's decision to exclude boilers
using Powder River Basin or other subbituminous coal from the LNB
Application Database (see, for example, docket items IV-D-15, p. 3; IVD
-65, p. 20). For such boilers, measured post-retrofit NO<INF>X
emission reductions reflect the combined effects of switching to a coal
with inherently lower NO<INF>X emissions plus the application of LNBs.
Response: In light of the comments requesting the inclusion and/or
exclusion of specific boilers from the LNB Application Database, EPA
has formalized and expanded the data quality assurance criteria used in
the rule proposal into Data Quality Objectives (DQOs). The DQOs are
rigorous and precisely defined rule tables which were used to screen
all candidate boiler retrofit cases and hourly CEM data observations.
The DQOs are designed to ensure that the LNB Application Database
satisfies objective and consistent data quality assurance standards.
Table 3 presents EPA's DQOs for evaluating candidate boiler retrofit
cases (DQOs Applied to Boilers) and for quality assuring hourly postretrofit
CEM data (DQOs Applied to Data).

Table 3.--Data Quality Objectives Applied to Boilers and Data to Screen Boilers for Inclusion in the LNB
Application Database

DQO# DQOs applied to boilers Rationale

1B Only dry bottom wall-fired and tangentially NO<INF>X emission rates for Group 1 boilers affect
fired boilers will be included in the dry bottom wall-fired and tangentially fired
database. boilers only.

2B Boilers must have an installed LNB control Consistent with Alabama Power v. EPA, 40 F.3d
technology only. Boilers with LNB plus 450 (D.C. Cir. 1994), EPA cannot consider
overfire air (OFA) or other controls will LNB+OFA installations when setting Group 1
not be included in the database. This limits.
determination is made by either (1)
information in EPA's Program Tracking System
Database or (2) direct contact with
individual utilities.

3B Any boiler with an LNB installation date Revised Group 1 limits are to be based on
prior to November 15, 1990 will not be improved performance of LNBs installed after
included in the database. LNB installation passage of 1990 Clean Air Act Amendments
dates are determined from (1) EPA's Program (CAAA).
Tracking System Database, (2) estimation of
the dates from visual interpretation of
hourly emissions plots, or (3) direct
contact with the utilities.

4B Only boilers with at least 52 days of post- 52 days is generally accepted as the minimum
retrofit data, following an equipment time period for assessing long-term
``break-in'' period of 30 calendar days, performance of NO<INF>X combustion control
will be included in the database. technology (see preamble section
III.A.2.ii). Vendors and utilities
acknowledge existence of ``break-in''
period, lasting about 30 calendar days,
during which boiler operations are often
highly irregular.

5B Boilers for which LNB design, installation Boilers with serious and persistent LNB
and/or operations are known to be seriously design, installation, and operational flaws
flawed will be excluded from the database. do not reflect the true NO<INF>X emission
This determination will be made on the basis reduction associated with LNB retrofit.
of published utility papers or information (This DQO is a logical extension of a
submitted to EPA for a rulemaking docket. pertinent statutory concept. Section 407(d)
(This DQO, however, was never used as the requires selection of appropriate control
sole basis for rejecting any candidate equipment ``designed to meet the applicable
boiler retrofit cases from current emission rate'' as well as proper
database.). installation and operation of such equipment
for determining eligibility, and an
appropriate emission rate, for an
alternative emission limitation).

6B Boilers must have a pre-retrofit uncontrolled Quality assured short-term uncontrolled
emission rate based on quality assured short- emission rate data are needed to perform
term CEM or test data that is verifiable in consistent analysis and projections using
the CREV database, the Acid Rain Cost Form first and second parts of model (see
for NO<INF>X Control Costs, or another source preamble, section III.A.3.ii.).
available to EPA.

7B Quarterly report submissions for boilers must Quarterly report submissions that do not
pass the quality assurance (QA) criteria in satisfy the CEM and other QA criteria in 40
40 CFR part 75. CFR part 75 contain insufficient information
to verify the accuracy of reported NO<INF>X
emission rate data.

8B NSPS boilers are excluded from the database.. Pre-NSPS boilers differ from NSPS boilers
with regard to furnace volume and heat
release rates and, as a result, NSPS units
can more easily meet a NO<INF>X reduction target
by retrofitting LNBs. This makes NSPS units
unrepresentative for establishing overall
LNB NO<INF>X reduction efficiency.

9B Only boilers not using Powder River Basin Powder River Basin coal has been identified
coal will be included in the database. by utilities as a subbituminous coal which
produces very low NO<INF>X emission rates. Its
performance cannot necessarily be reproduced
by any other type of coal for LNB
applications.

DQO# DQOs applied to data Rationale

1D Data generated using EPA's missing data The missing data routines include a penalty
substitution procedures will not be used (40 for not properly maintaining CEM equipment.
CFR part 75). In order to assess actual LNB performance,
only measured NO<INF>X emission rate data will be
used.

2D Hourly emission rate data will be adjusted Using bias adjusted NO<INF>X emission rates will
using the appropriate bias adjustment factor ensure compatibility of CEM NO<INF>X emission
for the boiler. rate measurements obtained from different
monitors.

[[Page 67123]]

3D NO<INF>X emission rates greater than 10 lb/mmBtu Such reported data values are clearly
and less than or equal to 0 lb/mmBtu will be erroneous (i.e., physically impossible) and,
discarded. thus, should not be included when estimating
achievable emission rates.

4D Hourly emission rate data for ``break-in'' Vendors and utilities acknowledge existence
period, defined as the 30 calendar days of ``break-in'' period, lasting about 30
following estimated date the boiler began calendar days, during which boiler
operating after shutdown for LNB retrofit operations are atypical due to vendor
(denoted on tables as ``LNB retrofit performance guarantee testing. Discarding
date''), will be discarded. hourly emissions data for ``break-in''
period also allows for any uncertainty
associated with exact date of beginning of
post-retrofit period.

EPA applied these DQOs to candidate boilers: those used in the
Phase II proposed rule analysis (Tables 2 and 3, 61 FR 1442, 1446-1447,
January 19, 1996); those that commenters requested EPA to consider
(many of which are named above); and additional LNB boiler applications
which EPA identified using 1995 and first and second quarter, 1996 CEM
data submitted pursuant to 40 CFR part 75 and other program
information. A detailed presentation of the results of EPA's
comprehensive data evaluation appears in docket item IV-A-6. The
resulting LNB Application Database, presented in Tables 4 and 5,
consists of 39 wall-fired boilers and 14 tangentially fired boilers and
contains over 477,800 hours of quality assured post-retrofit CEM data
on LNB performance.

Table 4.--Wall-fired Boilers in the LNB Application Database

Load weighted
Uncontrolled post-

Obs. No. ORISPL Unit name/unit ID Phase No<INF>X rate (ln/ optimization Percent No<INF>X
mmBtu) No<INF>X rate (ln/ removal
mmBtu)

26 Gaston unit 1..... 1 0.900 0.384 57.3
26 Gaston unit 2..... 1 0.780 0.384 50.8
26 Gaston unit 3..... 1 0.800 0.413 48.4
26 Gaston unit 4..... 1 0.800 0.413 48.4
47 Colbert unit 1.... 1 0.800 0.421 47.4
47 Colbert unit 2.... 1 0.670 0.421 37.2
47 Colbert unit 3.... 1 0.830 0.421 49.3
47 Colbert unit 4.... 1 0.860 0.421 51.0
47 Colbert unit 5.... 1 0.780 0.434 44.4
641 Crist unit 6...... 1 1.040 0.492 52.7
641 Crist unit 7...... 1 1.160 0.517 55.4
856 Edwards unit 2.... 2 1.000 0.514 48.6
1043 Ratts unit 1SG1... 1 1.080 0.508 53.0
1043 Ratts unit 2SG1... 1 1.090 0.468 57.1
1295 Quindaro unit 2... 1 0.635 0.405 36.2
1355 Brown unit 1...... 1 1.000 0.495 50.5
1357 Green River unit 5 1 0.836 0.400 52.2
1381 Coleman unit 1.... 1 1.410 0.489 65.3
1381 Coleman unit 2.... 1 1.290 0.466 63.9
1384 Cooper unit 1..... 1 0.900 0.419 53.4
1384 Cooper unit 2..... 1 0.900 0.419 53.4
2049 Watson unit 4..... 1 1.100 0.413 62.5
2049 Watson unit 5..... 1 1.220 0.431 64.7
2629 Lovett unit 4..... 2 0.570 0.349 38.8
2629 Lovett unit 5..... 2 0.585 0.329 43.8
2840 Conesville unit 3. 1 0.852 0.412 51.6
2843 Picway unit 9..... 1 0.866 0.415 52.1
3131 Shawville unit 1.. 1 0.990 0.486 50.9
3131 Shawville unit 2.. 1 1.020 0.483 52.6
3159 Cromby unit 1..... 2 0.600 0.378 37.0
3178 Armstrong unit 2.. 1 1.042 0.420 59.7
3948 Mitchell unit 1... 1 0.999 0.500 50.0
3948 Mitchell unit 2... 1 0.999 0.500 50.0
4042 Valley unit 1..... 1 1.100 0.477 56.6
4042 Valley unit 2..... 1 1.100 0.477 56.6
4042 Valley unit 3..... 1 1.050 0.473 55.0
4042 Valley unit 4..... 1 0.925 0.473 48.9
6041 Spurlock unit 1... 1 0.900 0.414 54.0
6085 RM Schahfer unit 2 0.420 0.228 45.7
15.

[[Page 67124]]

Table 5.--Tangentially Fired Boilers in the LNB Application Database

Uncontrolled Load weighted
NO<INF>X rate post-
---------------- optimization Percent NO<INF>X
Obs. No. ORISPL Unit name/unit ID Phase NO<INF>X rate removal
(ln/mmBtu) ----------------
(ln/mmBtu)

710 McDonough unit 1......................... 1 0.657 0.388 40.9
710 McDonough unit 2......................... 1 0.600 0.388 35.3
728 Yates unit Y4BR.......................... 1 0.561 0.421 25.0
728 Yates unit Y5BR.......................... 1 0.650 0.421 35.2
1374 Elmer Smith unit 2....................... 1 0.859 0.419 51.2
1710 Campbell unit 1.......................... 1 0.690 0.456 33.9
2554 Dunkirk unit 1........................... 2 0.478 0.343 28.2
2554 Dunkirk unit 2........................... 2 0.478 0.331 30.8
2642 Rochester 7 unit 4....................... 2 0.587 0.365 37.8
2732 Riverbend unit 7......................... 2 0.580 0.421 27.4
2732 Riverbend unit 8......................... 2 0.640 0.383 40.2
2732 Riverbend unit 10........................ 2 0.772 0.357 53.8
4041 S. Oak Creek unit 7...................... 1 0.661 0.377 43.0
4041 S. Oak Creek unit 8...................... 1 0.665 0.377 43.3

The Agency believes that the addition of 20 units to the LNB
Application Database increases the overall representativeness of the
database for use in analyzing the achievable emission rates for Group 1
boilers and addresses commenters'' concerns that the original database
may not adequately represent units with high uncontrolled emission
rates. The current database contains 22 units with uncontrolled
emission rates above the rates classified by one utility commenter as
``high'' (i.e., for wall-fired boilers, above 0.90 lb/mmBtu and for
tangentially fired boilers, above 0.68 lb/mmBtu, see docket item IV-G-
16, p. 7). For several reasons, the Agency believes these additions to
the database are more appropriate than adding boilers with LNB and
overfire air (OFA) as suggested by some commenters. First, under the
ruling in Alabama Power v. EPA, 40 F.3d 450 (D.C. Cir. 1994), EPA
cannot consider LNB with OFA installations in the LNB Application
Database for setting Group 1 limits. Second, isolating the true
NO<INF>X reduction performance of the LNB portion of LNB+OFA systems is
problematic because the controls are designed to reduce NO<INF>X as an
integrated system and site-specific factors influence the relative
contribution that each component (LNB vs. OFA) is designed to achieve.
Further, there is no basis for assuming that the performance of the LNB
portion, even if this could be measured accurately, is representative
of the performance that could be achieved by LNBs without the addition
of OFA.

2. Time Period/Averaging Basis Used To Evaluate Performance of Low
NO<INF>X Burner Technology

i. Background

Because the Acid Rain Phase I NO<INF>X Emission Reduction Program
did not go into effect until January 1, 1996, EPA did not have, at the
time the proposed rule was issued, CEM data on the performance of LNBs
applied to Group 1 boilers during a period when affected boilers were
required to meet the annual Phase I NO<INF>X emission limitations.
Further, for the reasons discussed below, it could not be assumed that
all the CEM data available, some of which had been recorded as early as
January 1, 1994, reflected LNB performance during optimized NO<INF>X
removal conditions.

As discussed in the Regulatory Impact Analysis (RIA) for the
proposed rule (see docket item II-F-2), plants incur both fixed and
variable operation and maintenance (O & M) costs when operating LNBs to
reduce NO<INF>X emissions to the lowest practicable level consistent
with prudent boiler operations to comply with regulatory emission
limitations. Therefore, even though LNB controls are installed,
utilities have a financial incentive not to operate units throughout an
extended period of pre-compliance to sustain the emission reductions
the controls were designed to achieve, since this would increase O & M
costs when the NO<INF>X emission reductions are not yet required. Thus,
the average NO<INF>X emission rate measured over an extended precompliance
period may not be a good predictor of LNB performance under
actual compliance conditions. On the other hand, it is reasonable to
expect that utilities operated their newly installed NO<INF>X controls
for some period of time following optimization of the equipment to
simulate compliance conditions, perhaps as a dry run or for training
purposes.

EPA's objective, then, was to identify the time period in the
stream of post-retrofit hourly CEM data that corresponds to operation
under optimized NO<INF>X removal conditions. EPA believed this time
period should contain 52 days of valid CEM data since, in publications
and in past rulemakings, the Department of Energy (DOE) and the utility
industry have stated that acceptable results of long-term performance
require data sets of at least 51 days with each day containing at least
18 valid hourly averages (see docket items II-I-99, Advanced
Tangentially-Fired Combustion Techniques for the Reduction of Nitrogen
Oxide (NO<INF>X) Emissions from Coal-Fired Boilers, and II-I-100,
Demonstration of Advanced Wall-Fired Combustion Modifications for the
Reduction of Nitrogen Oxide (NO<INF>X) Emissions from Coal-Fired
Boilers). EPA defined a 52-day ``low NO<INF>X period'' for the purposes
of assessing performance of LNBs applied to Group 1 boilers in the
proposed rule. The ``low NO<INF>X period'' was determined by
identifying the lowest average NO<INF>X emission rate each boiler has
sustained for at least 52 days, i.e., over a period of 1,248 hours when
the boiler was operating and valid CEM data (measured by CEMS certified
pursuant to 40 CFR part 75) were available. The low NO<INF>X period for
most boilers is considerably longer than 52 calendar days since hours
during which the boiler did not operate or hours for which valid CEM
data were not recorded are ignored and do not count

[[Page 67125]]

towards the required total of 1,248 hours.
Even prior to the proposed rule, utility commenters and DOE had
expressed the concern that by not using essentially all the recorded by
post-retrofit CEM data, EPA was not accurately assessing the long-term
performance capabilities of LNBs (61 FR 1442).\6\ Further, these
commenters believed that using a fixed-length shakedown period of 30 to
90 days, applied universally to all installations, to allow for
optimizing LNBs and operator training was more objective than using the
variable-length and site-specific shakedown periods implicit in EPA's
low NO<INF>X period methodology. Accordingly, for the proposed rule,
EPA also developed estimates of post-retrofit average NO<INF>X emission
rates for another time period beginning 30 calendar days after the
estimated date the boiler began operating after shutdown for LNB
installation and continuing to the end of the CEM data set. This period
is referred to as the ``overall post-retrofit period'' in the proposed
rule (61 FR 1447 (Tables 4 and 5); also see docket item II-A-9, Table 2
) and as the ``post-retrofit minus 30 days period'' (abbreviated as
``30-day post-retrofit period'' in tabular column headings) in the
technical support document for the final rule (see docket item IV-A-6).

\6\ EPA notes that the tangentially fired boilers in the LNB
Application Database used for the proposed rule had little more than
the requisite 52 days of quality assured post-retrofit CEM data.
Only CEM data reported through June 30, 1995, the end of the second
quarter reporting period, were available for analysis and the LNB
retrofit dates for tangentially fired boilers occurred in late 1994
or early 1995.

For the proposed rule, EPA developed estimates of post-retrofit
average NO<INF>X emission rates for a third period which, like the
overall post-retrofit period, uses most of the recorded post-retrofit
CEM data and, like the low NO<INF>X period, allows for a variablelength
shakedown period to accommodate the site-specific nature of LNB
equipment optimization and operator training processes. This time
period begins with the first hour of the low NO<INF>X period and
continues to the end of the CEM data set. It is referred to as the
``post-optimization period'' in both the proposed rule and final rule
analyses. As mentioned previously in section B of this preamble, the
post-optimization period forms the basis for EPA's final assessment of
the effectiveness of LNBs applied to Group 1 boilers.
Another concern, which was raised prior to the proposed rule by
utility commenters and DOE, is that limited time periods such as the
low NO<INF>X period may not adequately capture annual dispatch patterns
and seasonal variations in demand for electrical power generation.
Accordingly, for the proposed rule, EPA also investigated the
representativeness of load dispatch during the low NO<INF>X period by
comparing it to the load dispatch during calendar year 1994 for each
boiler or common stack in the LNB Application Database. EPA developed
two histograms using ``load bins'' for the horizontal axis: (1) Average
hourly NO<INF>X emission rate as a function of load during the low
NO<INF>X period; and (2) frequency of various boiler operating loads
throughout 1994 (for which EPA had actual performance data from the CEM
data set ). Then, EPA used these histograms to estimate ``load-weighted
annual average NO<INF>X emission rates'' based on weighted averages of
the average emission rate during the low NO<INF>X period for each load
bin times the number of hours the boiler operated in that load bin
during 1994 (61 FR 1448 (Tables 6 and 7)). To test the
representativeness of boiler operations during the low NO<INF>X period,
EPA also created bar charts comparing the percentage of time a boiler
operated in each load bin during the low NO<INF>X period to the
percentage of time it operated in that load bin during calendar year
1994 (see docket item II-A-9, Appendix B). Using these graphical
analyses, EPA concluded that most boilers in the LNB Application
Database had a load dispatch pattern during their low NO<INF>X period
similar to their annual dispatch pattern in 1994.
When analyzing long-term post-retrofit CEM data for the proposed
rule, EPA found no strong correlation between boiler operating loads
and hourly average NO<INF>X emission rates for either wall-fired
boilers or tangentially fired boilers in the LNB Application Database.
While earlier technical analyses performed for EPA in support of other
utility NO<INF>X emission rulemakings had generally adopted the
industry accepted presumption of a NO<INF>X vs. boiler load
relationship for many uncontrolled Group 1 boilers, they also showed
the direction, magnitude, and form of this correlation to be both
highly boiler-specific and difficult to predict (see, for example,
docket item IV-J-20).

Nevertheless, EPA recognized that a predictable systematic
correlation between hourly average NO<INF>X emission rates and boiler
load for all or some boilers could have significant ramifications for
proper application of a 52-day low NO<INF>X period methodology.
Accordingly, EPA developed the ``load-weighted annual average NO<INF>X
emission rates,'' defined above, to account for the potential existence
of a NO<INF>X vs. boiler load relationship. Because the load-weighted
annual average NO<INF>X emission rates were essentially the same as or
lower than the average NO<INF>X emission rates for the low NO<INF>X
period for these boilers (see 61 FR 1446 (Tables 5 and 6)) EPA selected
the simpler form, a straight average over the low NO<INF>X period, as
the basis for the proposed rule.

The Agency received many detailed comments and supporting data
about the appropriateness of using a limited low NO<INF>X period for
assessing LNB performance, the merits of site-specific variable-length
vs. universal fixed-length shakedown periods to reflect LNB equipment
optimization and operator training, the advantages and disadvantages of
the alternative time periods EPA had considered for the proposed rule
analysis, and the technical issue of the existence of a NO<INF>X vs.
load relationship and its relevance for assessing LNB performance
applied to Group 1 boilers. The first three issues are discussed in the
next section within the context of the low NO<INF>X period methodology
whereas the last issue, for which EPA received approximately 25 sitespecific
data submissions from utility boiler owners or operators, is
treated separately in the subsequent section.

ii. Use of 52-Day Low NO<INF>X Period

Comment/Analyses: EPA received approximately 29 comment letters
(from 22 utilities, 2 utility associations, 3 states, a gas industry
representative, and an environmental association) on the
appropriateness of using a 52-day low NO<INF>X period for assessing LNB
performance when, for some boilers, considerably more post-retrofit
data was available.

Some commenters fully endorsed EPA's 52-day methodology and
implicit assumption that utilities not under a compliance obligation
are unlikely to operate the controls for maximum emission reductions
following LNB optimization and a low NO<INF>X test period. They
believed EPA had demonstrated that the 52-day methodology and ``loadweighted
annual average NO<INF>X emission rates'' adequately addressed
annual dispatch and load patterns in most cases. A utility that owns
and operates coal-fired units which have become subject to statemandated
NO<INF>X Reasonably Available Control Technology (RACT)
requirements in 1995 said EPA should go even further and ``use NO<INF>X
data only from units that have had to comply with a recent NO<INF>X
standard (such as NO<INF>X RACT)'' for

[[Page 67126]]

evaluating the effectiveness of LNB technology (see docket item IV-G-
14, p. 1). EPA notes that 6 wall-fired boilers and 3 tangentially fired
boilers in the LNB Application Database are located in the Northeast
Ozone Transport Region and are subject to NO<INF>X RACT requirements.
The mean load-weighted annual average NO<INF>X emission rates over the
post-optimization period for these boilers are: 0.403 lb/mmBtu (wallfired)
and 0.344 lb/mmBtu (tangentially fired).
One commenter noted that utilities had an explicit disincentive for
operating their LNBs to achieve the maximum practicable emission
reductions during 1994 and 1995, since section 407(b)(2) allows EPA to
promulgate revisions to Group 1 emission standards if measured average
post-retrofit NO<INF>X emission rates during this time frame indicate
``more effective low NO<INF>X burner technology is available'' (see
docket item IV-D-63, p.14). Another commenter endorsed the conclusion
that observations during the 52-day low NO<INF>X period may understate
the actual reduction capability of LNBs (see docket items IV-D-047, p.
2 and IV-D-063, p. 12-14).

Other commenters disagreed with the assumption that utilities did
not have any incentive to operate the installed LNBs to achieve maximum
emission reductions consistent with prudent boiler operations. One
utility stated that plant personnel ``operated [their] NO<INF>X control
systems in a compliance mode even though its units were technically not
yet subject to the Phase I NO<INF>X standard. [The utility] established
performance goals based on operating NO<INF>X reductions systems to
meet the standard and management bonuses were geared to meeting these
goals'' (see docket item IV-D-020, p. 6). EPA notes that all of this
utility's wall-fired units sustained average NO<INF>X emission rates
below 0.44 lb/mmBtu throughout their ``post-optimization'' periods
(i.e., the post-retrofit period excluding a shakedown period based on
actual boiler experience). The post-optimization periods for these
units varied in length from 12 to 18 months. Another utility stated
that boilers were operated in a manner to optimize NO<INF>X emission
reduction; to do otherwise would be ``counterproductive to the design
of the burners and would defeat the training of the operating staff''
(see docket item lV-D-023, p. 4). EPA notes that the units owned and
operated by both of these utility commenters are located outside
designated ozone nonattainment areas and are not subject to NO<INF>X
RACT or any other state-mandated NO<INF>X control requirements. Their
decision to operate in a low-NO<INF>X mode, therefore, was voluntary
and not made on the basis of whether a compliance obligation existed.
Several commenters indicated that the best approach for estimating
annual average NO<INF>X emission rates is to use a full year of postretrofit
monitoring data (see, for example, docket item IV-D-38, p. 3).
Commenters reiterated the concern raised prior to the proposal rule,
that by not using essentially all the recorded post-retrofit CEM data,
EPA is not accurately assessing the long-term performance capabilities
of LNBs (see, for example, docket items IV-D-35, p. 3; IV-G-15, pp. 2-
3). They said EPA's 52-day low NO<INF>X period methodology fails to
take into account all of the operating variables that affect LNB
performance and biases the LNB performance assessment toward emission
reduction levels that may not be achievable over the long term.
Further, commenters who participated in DOE Clean Coal Technology
Demonstrations where the 52-day methodology was used, said the ``52-day
rule'' defines ``the minimum number of continuous days of data needed
before a data set can be considered `long-term' data. It is not a rule
that justifies selective editing of data, when more data are
available'' (see docket item II-D-65, p. 29).
Some of these commenters suggested using all CEM data recorded
after a fixed-length shakedown period whereas others believed a
variable-length shakedown period is more appropriate given the sitespecific
nature of the LNB equipment optimization and operator training
processes. EPA notes that one utility commenter reported that burner
optimization for each of their five tangentially fired retrofits was
completed within 120 days of startup (see docket item IV-D-23, p.4),
which is considerably longer than the fixed 30-day shakedown period
recommended by DOE and others. Another utility commenter reported that
one of their wall-fired boilers, E.D. Edwards 2, was still being
optimized more than a year after the retrofit date (see docket item IVD
-73, p. 3).

Several commenters indicated support for the post-optimization
period approach, which EPA had presented in the proposed rule together
with the 52-day low NO<INF>X period methodology and load-weighted
annual average NO<INF>X emission rates. As one utility said, `the postoptimization
period' emission results are the best data set
characterizing long-term low-NO<INF>X mode boiler operation. This
database maximizes the amount of low-NO<INF>X mode data (i.e., sample
size) collected following a period of demonstrated minimum NO<INF>X
operation.'' (See docket item IV-D-051, p. 8.)
Some commenters indicated a 52-day low NO<INF>X period methodology
would be credible for assessing the long-term performance of LNB
technology if NO<INF>X emission rates following LNB optimization do not
vary significantly with boiler load (see, for example, docket item IVD
-72, p. 4). While these commenters generally believe NO<INF>X emission
rates are a function of load for many boilers (see discussion below
under NO<INF>X vs. Boiler Load Relationship), they do endorse the
concept of using less than essentially all the recorded post-retrofit
CEM data for assessing LNB performance.
Response: EPA believes that the 52-day low NO<INF>X period
methodology is technically justified for evaluating the achievable
NO<INF>X reduction capability of LNBs. This time period is sufficiently
long, in most instances, to reflect long-term operation as evidenced by
the generally similar load dispatch patterns observed during the low
NO<INF>X period and for calendar year 1994 for most boilers in the LNB
Application Database. However, assuring proper selection of a low
NO<INF>X period that is representative of long-term boiler operating
conditions in all instances can be difficult. An example of this is
E.D. Edwards 2 where, according to the utility, the 52-day low NO<INF>X
period EPA had selected for the proposed rule analysis was atypical
because it represents ``a period of testing in a low NO<INF>X mode when
the boiler was not optimized.'' Shortly thereafter, the utility retuned
the boiler for improved efficiency, to reduce loss on ignition
(LOI), and to maintain full compliance with particulate and opacity
emissions standards. (See docket item IV-D-073, pp. 3-4.) Another
commenter suggested possible adverse plant impacts may have occurred
during the low NO<INF>X period for a few other boilers in the LNB
Application Database (see docket item IV-D-65, Enclosures 7 and 14);
EPA's analysis of the specific impacts and remedial actions cited
indicates that these possible issues are adequately addressed by
extending the low NO<INF>X period into the longer post-optimization
period. Therefore, to maximize the likelihood that the performance
evaluation period is representative and to assure observations over the
broadest possible range of boiler operating variables and electric
power generation demand scenarios, EPA is using the longer postoptimization
period as the basis for assessing the performance of LNBs
applied to Group 1 boilers for the final rule.

[[Page 67127]]

EPA's decision to use the post-optimization period is also based,
in part, on the comments utilities have submitted regarding their
actions to operate installed LNBs in a compliance mode during 1995,
prior to the effective date of the Acid Rain Phase I NO<INF>X Emission
Reduction Program. EPA believes that there were reasons for utilities
to operate installed LNBs as if the emission standards were in effect,
even though such operation could increase utility O & M costs. EPA has
rejected the concept of using a ``post-retrofit minus 30 (or 60 or 90)
days period'' approach because utilities submitted significant evidence
documenting that the time required for LNB optimization is highly
variable and can be much longer than any of the fixed shakedown periods
under consideration (see, for example, docket items IV-D-023, IV-D-073,
and IV-G-04). Nonetheless, for comparison purposes, EPA has computed
average NO<INF>X emission rates based on the post-retrofit minus 30
days period for boilers in the LNB Application Database (see docket
item IV-A-6, Table 3-1).

The addition of four more quarters of CEM data to the LNB
Application Database substantially lengthens the post-optimization
period for most boilers.7 The post-optimization period also
includes six months of 1996 compliance data for each Phase I boiler in
the database. Table 6 presents summary statistics on the amount of
hourly CEM data and calendar months encompassed by the postoptimization
periods.

\7\ A notable exception is the post-optimization time period for
E.D. Edwards 2, which has been lengthened by a lesser amount. In
response to the utility's comments, EPA has selected another low
NO<INF>X period, beginning after October 1, 1995, the date on which
EPA believes corrections for adverse opacity and particulate
emissions were substantially complete.

Table 6.--LNB Application Database: Hours of CEM Data and Calendar
Months in Post-Optimization Periods

Hours of CEM Calendar
Boiler types data months

Wall-fired boilers: 85% have at least 11
months of CEM data in post-optimization
period:

Range.................................... 3,877-15,829 6-30
Average.................................. 9,547 16
Total.................................... 372,324 610
Tangentially fired boilers: 79% have at least
11 months of CEM data in post-optimization
period:

Range.................................... 1,280-12,327 4-18
Average.................................. 7,537 14
Total.................................. 105,523 190

iii. NO<INF>X vs. Boiler Load Relationship

Comment/Analyses: EPA received approximately 23 comment letters
(from 21 utilities and 2 utility associations) criticizing EPA's
decision in the proposed rule to base revised Group 1 emission
limitations on a time period and averaging method which do not
explicitly recognize the existence of a NO<INF>X vs. load relationship.
As mentioned previously under section III.A.2.i. of this preamble, EPA
found no strong correlation between boiler operating loads and hourly
average NO<INF>X emission rates for either wall-fired boilers or
tangentially fired boilers in the LNB Application Database when
analyzing long-term post-retrofit CEM data for the proposed rule.
Nevertheless, to test the potential impact of a NO<INF>X/load
relationship, in the analysis accompanying the proposed rule EPA
developed a methodology that assumed the existence of a functional
relationship between NO<INF>X and boiler load. EPA then used this
methodology to estimate ``load-weighted annual average NO<INF>X
emission rates'' for each boiler or common stack in the LNB Application
Database (see docket item II-A-9, pp. 9-10).
The load-weighting methodology produced a weighted average based on
the frequency of various operating load intervals (or ``bins'') during
calendar year 1994 as reported in the CEM data set and the mean hourly
NO<INF>X emission rates for each load bin observed during the low
NO<INF>X period. (The computational procedures EPA used to estimate
load-weighted annual average NO<INF>X emission rates for the proposed
rule are described under preamble section III.A.2.i.) Finding that the
load-weighted annual average NO<INF>X emission rates for these boilers
were essentially the same as or lower than the average NO<INF>X
emission rates for the low NO<INF>X period without the assumption of a
NO<INF>X/load relationship (see 61 FR 1446 (Tables 5 and 6)), EPA
believed it was not necessary to investigate the NO<INF>X vs. load
relationship further and selected the more conservative (i.e., higher)
of the two sets of estimates for modeling annual average emission rates
that could be sustained by LNBs installed on Phase II, Group 1 boilers.
The commenters who criticized EPA's treatment of the NO<INF>X/load
relationship raised the following main issues:
Lack of statistical measures to quantify the extent of the
NO<INF>X/load relationship: Several commenters indicated that a
critical missing link in EPA's analysis of this issue for the proposed
rule was the failure to develop any statistical measures describing the
strength of the association, if any, between NO<INF>X and boiler load.
As one utility said, EPA concluded ``through observance of the data''
that the relationship between NO<INF>X and load is not strong for wallfired
boilers (see docket item IV-D-023, p. 5)
Inconsistency with earlier EPA studies: Some commenters claimed
that earlier EPA studies and utility emission rulemakings supported the
existence of the NO<INF>X/load relationship.
Examples to show presence of a NO<INF>X/load relationship: Many of
the commenters on this issue included site-specific data intended to
document the presence of a well-correlated NO<INF>X/load relationship.
On the other hand, some commenters who supported EPA's use of the
low NO<INF>X period for evaluating the performance of LNBs also said
EPA's comparison of load-weighted annual average NO<INF>X emission
rates vs. average NO<INF>X emission rates without the assumption of a
NO<INF>X/load relationship satisfactorily addresses this issue (see,
for example, docket items IV-D-46, p. 5 and IV-D-56, p. 1). According
to a state agency, the ``52-day time frame is representative of a wide
range of operations in a facility'' because the load variations over a
seven-day week are likely to be more significant than seasonal
variations. This agency said that, for most load-following units, load
changes are likely to be more significant between weekends and weekdays
than between seasons. Only the highest base-loaded units do not exhibit
this load cycle and such units are ``likely not affected by seasonal
changes'' (see docket item IV-D-27, p. 9).
Response: After further extensive boiler-by-boiler analysis of
NO<INF>X and boiler load, using both data provided by commenters and
reported independently under 40 CFR part 75 requirements, EPA has
determined that the installation of LNBs dampens any NO<INF>X/load
correlation that may have

[[Page 67128]]

existed at uncontrolled boilers and, in many instances, virtually
eliminates any long-term relationship. A NO<INF>X vs. load relationship
appears to have persisted for none of the tangentially fired boilers
and for only a few of the wall-fired boilers (Colbert 5, E.D. Edwards
2, Quindaro 2, and Jack Watson 5) in the LNB Application Database (see
docket item IV-A-6, pp. 4-2 through 4-7). However, despite these
findings, in response to commenters' insistence that a definite
functional relationship exists between NO<INF>X and boiler load, EPA
has employed a NO<INF>X/load weighting scheme in establishing NO<INF>X
emission limits in this final rule. This load-weighting method
incorporates at least two distinct improvements over the method used
for the proposed rule analysis. First, following commenters'
recommendation, the load weighting method employs ten load bins
consistent with the convention specified in 40 CFR part 75, rather than
the 25-MW increments used in the proposal. Second, the method uses
post-retrofit CEM data over the longer post-optimization period, rather
than the 52-day low NO<INF>X period, to estimate mean hourly NO<INF>X
emission rates for each load bin, thus making it unnecessary to combine
load bins due to sparse data. (Commenters had also said the combining
of load bins with little or no data tended to mask the NO<INF>X/load
relationship. See docket item, IV-D-65, p. 35.) The load weighting
method uses hourly boiler or common stack load as reported in the CEM
data set for 1995 to establish the frequency of operation in different
load bins over a year. EPA has rigorously investigated the relationship
of individual load patterns of boilers sharing a common stack to the
combined load patterns over a year and, thus, to the annual average
NO<INF>X emissions for the common stack (see discussion of common stack
issues in section III.A.3.v of this preamble). Finally, EPA has
compared, where data are available, boiler or common stack load
patterns for 1994 and 1995 to assess inter-year variations in dispatch
and demand for electrical power generation (see docket item IV-A-6).
This improved load weighting scheme accounts for any potential
impact that annual load dispatch patterns may have on NO<INF>X
emissions. Its use should allay concerns raised by commenters on how
the presence of a NO<INF>X/load relationship might impede accurate
assessment of long-term LNB performance. In addition, EPA's specific
responses to the main NO<INF>X/load issues are presented below:
Lack of statistical measures to quantify the extent of the
NO<INF>X/load relationship: Even among those commenters who most
strongly assert the presence of a NO<INF>X/load correlation, there is
little consistency from boiler to boiler in either the functional form
or the direction of the NO<INF>X/load relationship. For example, of the
three commenters submitting regression equations as evidence of a
NO<INF>X/load relationship, one was based on a cubic model (see docket
item IV-D-20, Figure 3), another was based on a logarithmic model (see
docket item IV-G-14, p. 3), and a third was based on a quadratic model
(see docket item IV-G-16). A fourth commenter, represented the
NO<INF>X/load relationship from one-third to full load for eight
boilers as straight line plots with slopes varying from approximately
15 deg. to 45 deg. (see docket item IV-D-72, Attachment 1). Although no
supporting documentation was provided explaining how these plots were
derived, they would imply a linear model was appropriate. The situation
is further complicated when a NO<INF>X/load relationship is discernible
over only a portion of the load range. This is particularly an issue
for wall-fired boilers retrofit with LNBs. EPA's plots of data from
post-retrofit wall-fired boilers show that if a NO<INF>X/load
relationship is discernible at all, it occurs almost entirely in the
upper 10-20% of the boiler load range.

The absence of a consistent functional form for the NO<INF>X/load
relationship and a failure to persist across the full load range makes
application of a statistical measure to quantify the extent of the
NO<INF>X/load correlation difficult. Nonetheless, assuming a linear
relationship between NO<INF>X and boiler load, EPA estimated the
strength of correlation as indexed by R2 during post-retrofit
period for 30 wall-fired and 11 tangentially fired boilers or common
stacks in the LNB Application Database and, during the pre-retrofit
period, for 13 wall-fired and 6 tangentially fired boilers or common
stacks (see docket item IV-A-6, Cadmus Group 1 technical report, Table
4-1). The R2 statistic measures the fraction of the variability in
the dependent variable, hourly average NO<INF>X emission rate,
explained by the model. EPA chose an R2 of 40% as a threshold for
detection of the possible existence of a predictable correlation. For
the post-retrofit hourly average NO<INF>X emission rate measurements,
only 13% of the wall-fired and none of the tangentially fired boilers
or common stacks had an R2 of 40% or higher (suggesting no
predictable correlation). EPA compared the load dispatch pattern during
the post-optimization period for each boiler or common stack crossing
the R2 threshold to its annual dispatch pattern in 1995 and
concluded the patterns were similar enough that the improved loadweighting
methodology would mitigate the effects of any NO<INF>X/load
correlation on estimated controlled annual average emission rates.
Inconsistency with earlier EPA studies: Earlier technical analyses
performed for EPA in conjunction with other utility NO<INF>X emission
rulemakings generally adopted the industry accepted presumption of a
NO<INF>X vs. boiler load relationship. However, this was almost
exclusively for uncontrolled Group 1 boilers, not boilers retrofit with
LNBs. Prior studies also showed the direction, magnitude, and form of
this correlation to be both highly boiler-specific and difficult to
predict. (See, for example, docket item IV-J-20). Thus, for example, in
these earlier studies, some uncontrolled tang