Federal Register, Volume 61 Issue 245 (Thursday, December 19, 1996)

[Federal Register Volume 61, Number 245 (Thursday, December 19, 1996)]
[Rules and Regulations]
[Pages 67112-67164]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-31839]

[[Page 67111]]

_______________________________________________________________________

Part II

Environmental Protection Agency

_______________________________________________________________________

40 CFR Part 76

Acid Rain Program; Nitrogen Oxides Emission Reduction Program; Final
Rule

Federal Register / Vol. 61, No. 245 / Thursday, December 19, 1996 /
Rules and Regulations

[[Page 67112]]

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 76

[AD-FRL-5666-1]
RIN 2060-AF48

Acid Rain Program; Nitrogen Oxides Emission Reduction Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This action promulgates standards 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 (NOX)
emission limitations for certain coal-fired electric utility units and
revising NOX emission limitations for others as specified in
section 407(b)(2) of the Act. The emission limitations will reduce the
serious adverse effects of NOX 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 NOX Emission Reduction Program
B. Summary of Final Rule
1. NOX Standards Promulgated by this Rule
2. Rationale for Revising Group 1 NOX Emission Limits and
Environmental Impact of Group 2 NOX Emission Limits
II. Public Participation
III. Summary of Major Comments and Responses
A. Phase II, Group 1 Boiler NOX Emission Limits
1. Boiler Population Used to Assess NOX Emission Limits
2. Time Period/Averaging Basis Used to Evaluate Performance of
Low NOX Burner Technology
3. Analysis Method Used to Establish Reasonably Achievable
Emission Limitations for Phase II, Group 1 Boilers
4. Percentile Used to Define Achievability
B. Group 2 Boiler NOX Emission Limits
1. Cost Comparability and Its Basis
2. Cost Comparison Methodology
3. Retrofit Nature of Group 2 Controls
4. Group 2 Boiler Size Exemption
5. Cyclone Boiler NOX Controls
6. Wet Bottom Boiler NOX Controls
7. Vertically Fired Boiler NOX Controls
8. Cell Burner Boiler NOX Controls
9. Revision of Proposed Group 2 Boiler NOX Emission Limits
C. Compliance Issues
D. Title IV NOX Program's Relationship to Title I and
NOX 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 NOX Emission Reduction Program

The primary purpose of the Acid Rain NOX 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, NOX has increased about 7%; it is the only conventional air
pollutant to show an increase nationwide.
Electric utilities are a major contributor to NOX emissions
nationwide: in 1980, they accounted for 30 percent of total NOX
emissions and, from 1980 to 1990, their contribution rose to 32 percent
of total NOX emissions. In 1994, electric utility emissions
represented about 33 percent of the total annual NOX emissions.
Approximately 90 percent of estimated electric utility NOX
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 NOX 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 (NO2) and, over longer periods of time, reacts
with and forms other pollutants, including ozone (O3), nitric acid
(HNO3) and fine particles. These pollutants are harmful to public
health and the environment.
NO2 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'').
NO2 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

1. NOX Standards Promulgated by This Rule
EPA today is promulgating new emission limitations to be
implemented for nitrogen oxides (NOX) 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 NOX
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 NOX
emission limitations for Group 1 boilers in Phase II if the
Administrator determines that ``more effective low NOX burner
technology is available,'' i.e., that data on the effectiveness of low
NOX 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 NOX 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 NOX 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 NOX burners
(LNBs) have been installed without any other NOX controls, and for
which EPA has both quality assured long-term post-retrofit hourly
NOX 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
NOX removal) of LNBs applied to Group 1 boilers.
For the final rule, EPA has adopted a methodology that employs
``load-weighted annual average NOX 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 NOX period,^{1 when the LNBs were
operating under optimized NOX 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 NOX/load weighting scheme, using hourly load data
reported for 1995, to develop ``load-weighted'' annual average NOX
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
NOX 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
NOX emissions.
---------------------------------------------------------------------------

\1\ The ``low NOX period'' EPA used for assessing
performance of LNBs applied to Group 1 boilers was defined by
identifying the lowest average NOX 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 NOX
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 NOX 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 NOX emissions reduction of approximately 90,000 tons
per year, beginning in 2000, below the emission levels anticipated
under the Phase I Acid Rain NOX 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
NOX emissions reduction of approximately 30,000 tons per year,
beginning in 2000, below the emission levels anticipated under the
Phase I Acid Rain NOX Emission Reduction Rule. As discussed
below, EPA exercises its discretion under section 407(b)(1) to adopt
these revised Group 1 NOX emission limitations because the
resulting additional reductions are a reasonable step toward
achieving necessary, significant NOX reductions and are
consistent with the guideline in section 401(b) concerning the level
of NOX 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 NOX 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 NOX control technology and
estimates the dollar cost per ton of NOX 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 NOX removed for each

[[Page 67114]]

NOX control technology applied to the Group 2 boiler category to
the dollar cost per ton of NOX removed for low NOX burners
applied to dry bottom wall-fired and tangentially fired boilers. Based
on this comparison, EPA determines whether the NOX control
technology applied to the Group 2 boiler category has a cost-
effectiveness 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 NOX control technology.
Fourth, EPA assesses the performance (percent NOX 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 NOX
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 NOX reductions are a
reasonable step toward achieving necessary, significant NOX
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 NOX 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 NOX
reductions are a reasonable step toward achieving necessary,
significant NOX reductions and are consistent with section 401(b).
EPA has decided not to set a NOX 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 NOX 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 NOX
reductions are a reasonable step toward achieving necessary,
significant NOX reductions and are consistent with section 401(b).
EPA has decided not to set a NOX 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 NOX
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 NOX reductions are a
reasonable step toward achieving necessary, significant NOX
reductions and are consistent with section 401(b). EPA has decided not
to set a NOX emission limitation for arch-fired boilers, a subset
of the vertically fired boiler category.
Finally, EPA has decided not to set a NOX emission limitation
for FBC boilers. Because these units are already low NOX emitters
by design, the NOX 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 NOX 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 NOX Emission Limits and
Environmental Impact of Group 2 NOX Emission Limits
EPA is exercising its discretion to revise the Phase II, Group 1
NOX emission limitations because: (1) NOX emissions have
significant adverse effects on human health and the environment; (2)
significant, additional regional NOX reductions from current
levels are likely to be necessary; (3) without additional actions
NOX 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 NOX reductions; and (5) the additional
reductions from the revision represent a reasonable step toward
achieving necessary NOX reductions. In addition, the resulting
NOX reductions are consistent with section 401(b). The adverse
health and environmental effects of NOX emissions are discussed in
the proposed rule on Phase II NOX emission limitations. 61 FR
1442, 1453-55, January 19, 1996. EPA reaffirms that discussion, which
summarizes the adverse impact of NOX 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 NOX
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 NOX 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 NOX 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 NOX 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 NOX
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 NOX emission reductions will decrease regional ozone, high
ozone, and ozone in non-attainment areas; and NOX 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 NOX 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 NOX and 25% for VOCs regionally, combined with 25% for
NOX and 75% for VOCs locally in the New York region (60 FR 4721);
and significant NOX 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 NOX 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 NOX 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 NOX 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

NOX emissions also contribute significantly to eutrophication,
i.e., an overabundance of nitrogen to water bodies that leads to
problems of nutrient enrichment. Regional NOX 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 NOX 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
NOX emissions can be as cost-effective as controlling non-
atmospheric 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 NOX 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 IV-
J-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)). NOX 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 IV-
J-3 (Valigura et al., 1996:23)).

iv. Utility Contribution to Atmospheric NOX Emissions

Electric utilities contributed approximately 33% of total
atmospheric NOX emissions in 1994, thus substantially contributing
to ozone formation, acid deposition, and eutrophication.
Table 1 summarizes the reductions in atmospheric NOX 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 NOX emissions from all sources of
NOX 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 NOX emissions,
the final rule provides reductions of about 5% of total NOX
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 NOX Reductions Necessary.... More than 50%.......... More than 40%.......... Up to 40%
NOX Reductions Achieved from the 5%..................... 5%..................... 5%
Final Rule as Percentage of Total
NOX Emissions.
----------------------------------------------------------------------------------------------------------------

v. NOX Reductions Not Sustained

Although national NOX 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 NOX control programs under the Clean Air
Act (including the Mobile Source Program under title II and the Acid
Rain NOX Program under title IV) limit NOX emission rates
(e.g., the pounds of NOX 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 NOX control
programs is largely completed and growth in sources and source use
continues, NOX emissions will gradually increase for the
foreseeable future (id. at 5-5). Section 401(b) of the Act suggested,
as a guideline, that NOX emissions should be reduced nationwide by
2 million tons from the 1980 level. By about 2006, total NOX
emissions will surpass that guideline unless additional efforts are
made (e.g., under title IV) to reduce NOX emissions (See figure 1,
below). The projected increase in total NOX emissions is well
within the time frame considered by Congress in title IV. EPA notes
that the nationwide annual cap for SO2 emissions, also established
under section 402, begins to apply in the year 2010. Until 2010, total
annual allocated SO2 allowances will exceed the cap, because of
additional allowances allocated under section 409 for repowered units
and bonus allowances under section 405. Additional NOX reductions,
such as these under today's final rule, are necessary both in light of
the likely need to reduce NOX to address ozone, acid deposition,
and eutrophication, and in light of the NOX reduction guideline in
section 401(b) of the Act. In short, new initiatives are needed to
reduce NOX 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)).
---------------------------------------------------------------------------

BILLING CODE 6560-50-P

[[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 NOX
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 NOX 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 NOX removed for
reductions under the final rule is less than, or at the lower end of,
the range of dollar cost per ton of NOX removed for most
alternative reductions. In short, the NOX 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 NOX 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 cost-
effectiveness ranges from $1,439/ton to $1,935/ton with percent
reductions ranging from 60-90%. For typical cyclone boilers, the cost-
effectiveness ranges from $440/ton to $880/ton with percent reductions
ranging from 60-90%. For typical cell-burner boilers, the cost-
effectiveness ranges from $624/ton to $801/ton with percent reductions
ranging from 60-80%. For typical wet bottom boilers, the cost-
effectiveness 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 NOX 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 NOX removed.
Non-Utility Point Sources: Non-utility point sources NOX
reductions are less cost effective, on average, than NOX
reductions under today's final rule. For example, the average cost-
effectiveness for process heaters ranges from $290-50,000/ton at an
average reduction of 5-90%. For cement manufacturing, the average cost-
effectiveness 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 NOX control options is also high, on average, as compared
to reductions under today's final rule. For example, the average cost-
effectiveness for light-duty on highway vehicles ranges from $1,100-
$260,000/ton, with percent reductions ranging from 0.2-21%. For heavy-
duty 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: NOX 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 NOX
controls for the three major NOX 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 coal-
fired 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 non-
utility 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 NOX Controls by Source
[Utility, other point source, mobile]
------------------------------------------------------------------------
Range in typical
cost- Percent
effectiveness ($/ reduction
ton)
------------------------------------------------------------------------
Utility sources (Coal w/advanced NOX
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 NOX 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: NOX 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 NOX 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 NOX emissions, significant, additional
reductions in regional atmospheric NOX emissions from current
levels are likely to be necessary. Further, the contribution of the
final rule toward the overall NOX reduction goal is approximately
5%. The NOX reductions under the rule represent only a portion of
the much larger NOX 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 NOX 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 NOX 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 NOX 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 NOX emissions when setting nationwide NOX 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 NOX emissions, it would still conclude that
additional NOX 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 SO2 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 NOX
reductions that can be required under emission limitations promulgated
under section 407.
In contrast to the SO2 provisions of title IV, which set a
nationwide cap on total tonnage of SO2 emissions (i.e., 8.95
million tons starting in 2010), the NOX provisions of title IV
provide only for limits on the NOX emitted per mmBtu of fuel
burned. Even if the NOX 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 NOX emissions. The
NOX emissions reductions projected to be achieved through adoption
of any given set of NOX emission limitations under title IV are
therefore not permanent. For this reason, when EPA estimates NOX
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 NOX Regulations at 1-7 and 1-8, December 8,
1995. Moreover, as discussed above, total NOX 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 two-
million-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 NOX 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 NOX emissions around 2 million tons less than
what they otherwise would have been in 2000. The annual NOX
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 NOX 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 NOX reductions
that are likely to be necessary, and are consistent with the 2 million
ton guideline for NOX reductions. The revision of the Group 1
emission limitations will result in about 120,000 tons of additional
annual NOX reductions. Actions to achieve NOX 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 NOX reductions and are consistent with the 2 million
ton guideline for NOX 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 NOX Emission Limits

1. Boiler Population Used To Assess NOX 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 NOX burners (LNBs) had been
installed without any other NOX 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
75. 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 NOX burner technology and the revised annual
NOX 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 NOX 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; IV-
D-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
NOX emission limit beginning May 31, 1995, whereas most other
applications have not had to comply with a recently established
NOX 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 NOX 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
NOX 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 NOX 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 NOX 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 NOX 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 wall-
fired 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; IV-
D-65, p. 20). For such boilers, measured post-retrofit NOX
emission reductions reflect the combined effects of switching to a coal
with inherently lower NOX 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 post-
retrofit 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 NOX 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 NOX 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 NOX 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 NOX 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 NOX
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 NOX reduction target
by retrofitting LNBs. This makes NSPS units
unrepresentative for establishing overall
LNB NOX 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 NOX 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 NOX emission rate data will be
used.
2D Hourly emission rate data will be adjusted Using bias adjusted NOX emission rates will
using the appropriate bias adjustment factor ensure compatibility of CEM NOX emission
for the boiler. rate measurements obtained from different
monitors.

[[Page 67123]]

3D NOX 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 NoX rate (ln/ optimization Percent NoX
mmBtu) NoX rate (ln/ removal
mmBtu)
----------------------------------------------------------------------------------------------------------------
1. 26 Gaston unit 1..... 1 0.900 0.384 57.3
2. 26 Gaston unit 2..... 1 0.780 0.384 50.8
3. 26 Gaston unit 3..... 1 0.800 0.413 48.4
4. 26 Gaston unit 4..... 1 0.800 0.413 48.4
5. 47 Colbert unit 1.... 1 0.800 0.421 47.4
6. 47 Colbert unit 2.... 1 0.670 0.421 37.2
7. 47 Colbert unit 3.... 1 0.830 0.421 49.3
8. 47 Colbert unit 4.... 1 0.860 0.421 51.0
9. 47 Colbert unit 5.... 1 0.780 0.434 44.4
10. 641 Crist unit 6...... 1 1.040 0.492 52.7
11. 641 Crist unit 7...... 1 1.160 0.517 55.4
12. 856 Edwards unit 2.... 2 1.000 0.514 48.6
13. 1043 Ratts unit 1SG1... 1 1.080 0.508 53.0
14. 1043 Ratts unit 2SG1... 1 1.090 0.468 57.1
15. 1295 Quindaro unit 2... 1 0.635 0.405 36.2
16. 1355 Brown unit 1...... 1 1.000 0.495 50.5
17. 1357 Green River unit 5 1 0.836 0.400 52.2
18. 1381 Coleman unit 1.... 1 1.410 0.489 65.3
19. 1381 Coleman unit 2.... 1 1.290 0.466 63.9
20. 1384 Cooper unit 1..... 1 0.900 0.419 53.4
21. 1384 Cooper unit 2..... 1 0.900 0.419 53.4
22. 2049 Watson unit 4..... 1 1.100 0.413 62.5
23. 2049 Watson unit 5..... 1 1.220 0.431 64.7
24. 2629 Lovett unit 4..... 2 0.570 0.349 38.8
25. 2629 Lovett unit 5..... 2 0.585 0.329 43.8
26. 2840 Conesville unit 3. 1 0.852 0.412 51.6
27. 2843 Picway unit 9..... 1 0.866 0.415 52.1
28. 3131 Shawville unit 1.. 1 0.990 0.486 50.9
29. 3131 Shawville unit 2.. 1 1.020 0.483 52.6
30. 3159 Cromby unit 1..... 2 0.600 0.378 37.0
31. 3178 Armstrong unit 2.. 1 1.042 0.420 59.7
32. 3948 Mitchell unit 1... 1 0.999 0.500 50.0
33. 3948 Mitchell unit 2... 1 0.999 0.500 50.0
34. 4042 Valley unit 1..... 1 1.100 0.477 56.6
35. 4042 Valley unit 2..... 1 1.100 0.477 56.6
36. 4042 Valley unit 3..... 1 1.050 0.473 55.0
37. 4042 Valley unit 4..... 1 0.925 0.473 48.9
38. 6041 Spurlock unit 1... 1 0.900 0.414 54.0
39. 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
NOX rate post-
---------------- optimization Percent NOX
Obs. No. ORISPL Unit name/unit ID Phase NOX rate removal
(ln/mmBtu) ----------------
(ln/mmBtu)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. 710 McDonough unit 1......................... 1 0.657 0.388 40.9
2. 710 McDonough unit 2......................... 1 0.600 0.388 35.3
3. 728 Yates unit Y4BR.......................... 1 0.561 0.421 25.0
4. 728 Yates unit Y5BR.......................... 1 0.650 0.421 35.2
5. 1374 Elmer Smith unit 2....................... 1 0.859 0.419 51.2
6. 1710 Campbell unit 1.......................... 1 0.690 0.456 33.9
7. 2554 Dunkirk unit 1........................... 2 0.478 0.343 28.2
8. 2554 Dunkirk unit 2........................... 2 0.478 0.331 30.8
9. 2642 Rochester 7 unit 4....................... 2 0.587 0.365 37.8
10. 2732 Riverbend unit 7......................... 2 0.580 0.421 27.4
11. 2732 Riverbend unit 8......................... 2 0.640 0.383 40.2
12. 2732 Riverbend unit 10........................ 2 0.772 0.357 53.8
13. 4041 S. Oak Creek unit 7...................... 1 0.661 0.377 43.0
14. 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
NOX reduction performance of the LNB portion of LNB+OFA systems is
problematic because the controls are designed to reduce NOX 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
NOX Burner Technology

i. Background

Because the Acid Rain Phase I NOX 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 NOX 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 NOX
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 NOX 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 NOX emission reductions are not yet required. Thus,
the average NOX emission rate measured over an extended pre-
compliance 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 NOX 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 NOX 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 (NOX) Emissions from Coal-Fired Boilers, and II-I-100,
Demonstration of Advanced Wall-Fired Combustion Modifications for the
Reduction of Nitrogen Oxide (NOX) Emissions from Coal-Fired
Boilers). EPA defined a 52-day ``low NOX period'' for the purposes
of assessing performance of LNBs applied to Group 1 boilers in the
proposed rule. The ``low NOX period'' was determined by
identifying the lowest average NOX 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 NOX 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 NOX period methodology. Accordingly, for the proposed rule,
EPA also developed estimates of post-retrofit average NOX 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 NOX 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 NOX period, allows for a variable-
length 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 NOX 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 NOX 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 NOX 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 NOX emission rate as a function of load during the low
NOX 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 NOX emission rates'' based on weighted averages of
the average emission rate during the low NOX 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 NOX period,
EPA also created bar charts comparing the percentage of time a boiler
operated in each load bin during the low NOX 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 NOX 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 NOX 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 NOX emission rulemakings had generally adopted the
industry accepted presumption of a NOX 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 NOX emission rates and boiler
load for all or some boilers could have significant ramifications for
proper application of a 52-day low NOX period methodology.
Accordingly, EPA developed the ``load-weighted annual average NOX
emission rates,'' defined above, to account for the potential existence
of a NOX vs. boiler load relationship. Because the load-weighted
annual average NOX emission rates were essentially the same as or
lower than the average NOX emission rates for the low NOX
period for these boilers (see 61 FR 1446 (Tables 5 and 6)) EPA selected
the simpler form, a straight average over the low NOX 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 NOX 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 NOX 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 NOX period methodology
whereas the last issue, for which EPA received approximately 25 site-
specific data submissions from utility boiler owners or operators, is
treated separately in the subsequent section.

ii. Use of 52-Day Low NOX 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 NOX 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 NOX test period. They
believed EPA had demonstrated that the 52-day methodology and ``load-
weighted annual average NOX 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 state-
mandated NOX Reasonably Available Control Technology (RACT)
requirements in 1995 said EPA should go even further and ``use NOX
data only from units that have had to comply with a recent NOX
standard (such as NOX 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 NOX RACT requirements.
The mean load-weighted annual average NOX emission rates over the
post-optimization period for these boilers are: 0.403 lb/mmBtu (wall-
fired) 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 NOX emission rates during this time frame indicate
``more effective low NOX burner technology is available'' (see
docket item IV-D-63, p.14). Another commenter endorsed the conclusion
that observations during the 52-day low NOX 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] NOX control
systems in a compliance mode even though its units were technically not
yet subject to the Phase I NOX standard. [The utility] established
performance goals based on operating NOX 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 NOX 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 NOX 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 NOX
RACT or any other state-mandated NOX control requirements. Their
decision to operate in a low-NOX 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 NOX emission rates is to use a full year of post-
retrofit 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 NOX 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 site-
specific 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 IV-
D-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 NOX period methodology and load-weighted
annual average NOX emission rates. As one utility said, `the post-
optimization period' emission results are the best data set
characterizing long-term low-NOX mode boiler operation. This
database maximizes the amount of low-NOX mode data (i.e., sample
size) collected following a period of demonstrated minimum NOX
operation.'' (See docket item IV-D-051, p. 8.)
Some commenters indicated a 52-day low NOX period methodology
would be credible for assessing the long-term performance of LNB
technology if NOX emission rates following LNB optimization do not
vary significantly with boiler load (see, for example, docket item IV-
D-72, p. 4). While these commenters generally believe NOX emission
rates are a function of load for many boilers (see discussion below
under NOX 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 NOX period
methodology is technically justified for evaluating the achievable
NOX 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
NOX period and for calendar year 1994 for most boilers in the LNB
Application Database. However, assuring proper selection of a low
NOX 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 NOX
period EPA had selected for the proposed rule analysis was atypical
because it represents ``a period of testing in a low NOX mode when
the boiler was not optimized.'' Shortly thereafter, the utility re-
tuned 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 NOX 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 NOX 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 post-
optimization 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 NOX 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 NOX 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 post-
optimization 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
NOX 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. NOX 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 NOX 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 NOX 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 NOX/load
relationship, in the analysis accompanying the proposed rule EPA
developed a methodology that assumed the existence of a functional
relationship between NOX and boiler load. EPA then used this
methodology to estimate ``load-weighted annual average NOX
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
NOX emission rates for each load bin observed during the low
NOX period. (The computational procedures EPA used to estimate
load-weighted annual average NOX emission rates for the proposed
rule are described under preamble section III.A.2.i.) Finding that the
load-weighted annual average NOX emission rates for these boilers
were essentially the same as or lower than the average NOX
emission rates for the low NOX period without the assumption of a
NOX/load relationship (see 61 FR 1446 (Tables 5 and 6)), EPA
believed it was not necessary to investigate the NOX 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 NOX/load
relationship raised the following main issues:
Lack of statistical measures to quantify the extent of the
NOX/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 NOX and boiler load.
As one utility said, EPA concluded ``through observance of the data''
that the relationship between NOX and load is not strong for wall-
fired 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 NOX/load relationship.
Examples to show presence of a NOX/load relationship: Many of
the commenters on this issue included site-specific data intended to
document the presence of a well-correlated NOX/load relationship.
On the other hand, some commenters who supported EPA's use of the
low NOX period for evaluating the performance of LNBs also said
EPA's comparison of load-weighted annual average NOX emission
rates vs. average NOX emission rates without the assumption of a
NOX/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
NOX 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 NOX/load
correlation that may have

[[Page 67128]]

existed at uncontrolled boilers and, in many instances, virtually
eliminates any long-term relationship. A NOX 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 NOX and boiler load, EPA
has employed a NOX/load weighting scheme in establishing NOX
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 NOX period, to estimate mean hourly NOX
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 NOX/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
NOX 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 NOX
emissions. Its use should allay concerns raised by commenters on how
the presence of a NOX/load relationship might impede accurate
assessment of long-term LNB performance. In addition, EPA's specific
responses to the main NOX/load issues are presented below:
Lack of statistical measures to quantify the extent of the
NOX/load relationship: Even among those commenters who most
strongly assert the presence of a NOX/load correlation, there is
little consistency from boiler to boiler in either the functional form
or the direction of the NOX/load relationship. For example, of the
three commenters submitting regression equations as evidence of a
NOX/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
NOX/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 NOX/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 NOX/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 NOX/load
relationship and a failure to persist across the full load range makes
application of a statistical measure to quantify the extent of the
NOX/load correlation difficult. Nonetheless, assuming a linear
relationship between NOX and boiler load, EPA estimated the
strength of correlation as indexed by R^{2 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 R^{2 statistic measures the fraction of the variability in
the dependent variable, hourly average NOX emission rate,
explained by the model. EPA chose an R^{2 of 40% as a threshold for
detection of the possible existence of a predictable correlation. For
the post-retrofit hourly average NOX emission rate measurements,
only 13% of the wall-fired and none of the tangentially fired boilers
or common stacks had an R^{2 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 R^{2 threshold to its annual dispatch pattern in 1995 and
concluded the patterns were similar enough that the improved load-
weighting methodology would mitigate the effects of any NOX/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 NOX emission
rulemakings generally adopted the industry accepted presumption of a
NOX 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 tangentially fired boilers
exhibit increasing NOX emission rates with decreasing boiler
loads, others show precisely the reverse correlation, and still others
have U-shaped curves. Uncontrolled wall-fired boilers typically exhibit
increasing NOX emission rates with increasing boiler loads.
However, this relationship was not found to be universally valid
either, and the strength of the correlation, when present, varies
considerably from one boiler to another.
For this final rule, EPA's analysis is more exhaustive than these
earlier studies. It encompassed more boilers, longer data streams, and
better quality data. Separate graphs were generated for every boiler or
common stack in the LNB Application Database, plotting NOX hourly
emission rates as a function of hourly load, using long-term quality
assured CEM data. To allow comparison of uncontrolled and controlled
emissions, wherever available, pre- and post-retrofit hourly data were
plotted on the same graph, differentiated by distinct symbols.
A comparison of the pre-retrofit and post-retrofit plots shows
that, with one exception, for both wall-fired boilers and tangentially
fired boilers, if any NOX vs. load relationship existed for
uncontrolled emissions, the installation of LNBs both reduced the
magnitude and shortened the effective range of that relationship.
As discussed above, EPA also developed a statistical measure
(R^{2) of the strength of the correlation between NOX and
boiler load, assuming a linear relationship. This statistical analysis
corroborates the visual assessment of the data plots. For the post-
retrofit hourly average NOX emission rate measurements, only 13%
of the wall-

[[Page 67129]]

fired and none of the tangentially fired boilers or common stacks had
an R^{2 of 40% or higher, suggesting possible presence of a
predictable correlation. Even though this analysis confirms that the
occurrence of a NOX-load relationship is generally slight and for
only some boilers, to eliminate all concerns in this regard, EPA has
based the final rule on load-weighted annual average NOX emission
rates (instead of a straight average emission rates) observed over the
post-optimization period (instead of the 52-day low NOX period).
Examples to show presence of a NOX/load relationship: A number
of commenters provided data intended to demonstrate the presence of a
NOX/load relationship. The submissions either had drawbacks which
rendered their conclusions questionable or corroborate EPA's finding
that the installation and operation of LNBs generally dampen any pre-
retrofit correlation of NOX and boiler load and, in many
instances, virtually eliminate any long-term relationship. The salient
aspects of each submission and EPA's responses are summarized below:
Docket item IV-D-020, Figure 20: Using CEM data for the period 06/
30/95 through 07/18/95, this submission included a regression analysis
for a 550 MW wall-fired boiler retrofit with LNBs. The regression model
fit NOX emissions to boiler load during the period analyzed. The
R^{2 statistic, which captures the explanatory power of the
regression model, was 77.3%, indicative of a good fit with the data.
There were a number of drawbacks, however, with the analysis.
First, the period analyzed represents only 19 calendar days. This is
too short a period to adequately represent long-term performance or to
distinguish a strong, but transitory, NOX/load correlation from a
persistent NOX/load correlation.
Second, the data plot shows a wide range of NOX emission rate
points at zero load. These appear to be spurious measurements which
improperly dominated the regression results.
Docket item IV-G-14, Tables 1-4 and Figures 1 and 2: This
submission included ``before LNB'' and ``after LNB'' regression
analyses for a 80 MW tangentially fired boiler. The ``before LNB''
regression is based on five-and-a-half months of CEM data and the
``after LNB'' regression is based on eight months of CEM data. During
the ``after LNB'' period, this boiler had to comply with a state-
mandated NOX RACT limit of 0.42 lb/mmBtu on a 24-hr average basis.
The commenter rightly excludes NOX emission data points for
periods when load is zero, which is consistent with EPA's DQO 3D.\8\ In
both the ``before LNB'' and ``after LNB'' case, the highest NOX
emission rate is at minimum load. The R2 statistic in the ``before
LNB'' regression was 57.8%, indicating that the model had moderate
explanatory power, whereas the R2 value in the ``after LNB''
regression was only 29.1%, indicating poor explanatory power.\9\ EPA
believes that this ``before LNB'' and ``after LNB'' comparative
regression analysis illustrates how the installation and operation of
LNBs can dampen any NOX vs. load relationship which may be
observed at uncontrolled boilers.
---------------------------------------------------------------------------

\8\ The commenter applies a cutoff at 5 MW, to exclude periods
when a small positive heat input may be recorded, but boiler load is
actually zero.
\9\ The commenter concludes that the relationship between
NOX and boiler load is much less well-defined after LNB
retrofit, but maintains the relationship still exists based on an
analysis of variance which produces a correlation coefficient of
-0.54.
---------------------------------------------------------------------------

Docket items IV-D-65, Enclosure 8; IV-D-23, Attachment 1; IV-D-73,
Attachment A: Several commenters submitted line plots or histograms of
average and/or maximum NOX emission rates recorded for different
load intervals or ``bins''. There were several problems with these
submissions. First, although they criticize EPA in this regard, the
commenters themselves do not develop any statistical measures of the
association between NOX and load for the data they submit (perhaps
because it, too, fails to demonstrate the presumed relationship). Nor
do they suggest functional representations for their plots.
A second drawback of these submissions is that some of the plots
represent boilers retrofit with LNBs plus separated overfire air. As
noted previously, such applications cannot be considered in this
rulemaking.
Third, while the submitted graphs appear to support the commenters'
statements about the existence of a NOX vs. load relationship for
the boilers analyzed, the use of a single value (whether the average or
maximum) to represent all values in a load range bin is misleading. It
hides the variability within the bin, thereby avoiding the issue of
whether the range of values in one bin are distinguishable from those
in another bin.
To address this issue EPA generated NOX/load box-and-whisker
plots for each boiler or common stack in the LNB Application Database.
The box-and-whisker representation not only shows a mid-point value
(the median), but it also characterizes the range of values found in
each bin by displaying the minimum, maximum, and first and third
quartile values. Where sufficient data were available, separate graphs
were created for NOX/load correlation before and after LNB
retrofits. In response to the commenter's criticism that EPA's earlier
analysis for the proposed rule had used too few load bins, ten load
bins (in 10 percent increments from zero to maximum gross unit load)
were used in all the NOX/load analyses for the final rule.
The box-and-whisker plots reveal so much overlap in NOX values
from bin to bin that drawing conclusions about a NOX/load
relationship is technically inappropriate. This is particularly true
for the post-retrofit situation.
Docket items IV-D-73, p. 5 and Attachment A; IV-D-65, p. 32: One
utility reported that the NOX emission rate guarantee, in its
contract for LNBs on a 375 MW wall-fired boiler (E.D. Edwards 3),
``[is] designed specifically to achieve specific NOX rates at
specific loads.'' The annual NOX emission rate is guaranteed to
meet 0.50 lb/mmBtu based on a specified capacity. The NOX emission
rate guarantees for particular loads range from 0.28 lb/mmBtu at 40% of
MCR (150 MW) to 0.63 lb/mmBtu at 100% of MCR (375 MW). The commenter
also submitted graphs depicting the ``remarkable NOX vs. load
relationship'' for another wall-fired boiler (E.D. Edwards 2). The
graphs plotted the average, maximum, and minimum hourly NOX
emission rates recorded in each of ten load bins for the four quarters
of 1995 as well as the entire year.
EPA has analyzed all the post-retrofit CEM data for E.D. Edwards 2
to evaluate the extent of a discernible NOX/load relationship. The
analysis confirmed the existence of a well-defined NOX vs. load
relationship for this boiler, but only in the upper 20% of the load
range (see docket item IV-A-6, Appendix D).
Another commenter noted that Babcock & Wilcox (B&W), a primary
designer of wall-fired boilers and a major LNB vendor in the U.S.,
attests to the existence of a NOX/load correlation. This commenter
said EPA did not find a strong NOX vs. load relationship because
EPA did not examine closely the post-retrofit CEM data for wall-fired
boilers designed by B&W. B&W has stated, ``a definite correlation
[exists] between NOX emissions and boiler load'' (see docket item
IV-D-65, p. 32).
The LNB Application Database contains 18 wall-fired boilers
designed by B&W. Five of these boilers, EPA believes, have also been
retrofit with LNBs manufactured by B&W (Model DRB-XCL). Only one B&W
boiler and none of the B&W LNB retrofits appeared among the wall-fired
boilers or common

[[Page 67130]]

stacks that had an R\2\ of 40% or higher for the correlation of post-
retrofit hourly average NOX emission rate measurements with boiler
load.
3. Analysis Method Used to Establish Reasonably Achievable Emission
Limitations for Phase II, Group 1 Boilers

i. Background

For the proposed rule, EPA used a three-step analytical procedure
for establishing reasonably achievable annual emission limitations for
the populations of wall-fired boilers and tangentially-fired boilers,
retrofit with LNBs, that would be subject to any revised emission
limitations (i.e., those units subject to NOX emission limitations
only in Phase II). The first step (Model Building) consisted of
deriving linear regression equations, one for wall-fired boilers and
another for tangentially fired boilers, that captured the percent
reduction in post-retrofit load-weighted annual average NOX
emission rate as a function of the uncontrolled emission rate for
boilers in the LNB Application Database. The second step (Calculation
of Achievable Emission Rates) was to enter the uncontrolled emission
rates of the Phase II boilers into the regression equations in order to
derive the controlled NOX emission rate that each boiler could be
expected to achieve by LNB retrofit. Using the resulting set of
achievable emission rates, the third step was to identify the annual
emission limitation that a specified percentage (i.e., 85 to 90%) of
the Phase II boilers could achieve. Separate limits were identified for
wall-fired boilers and for tangentially fired boilers.
This three-step procedure afforded several advantages. First, by
using regression equations, the estimates of achievable emission rates
were not rough extrapolations from average Phase I post-retrofit
experience but were estimates specifically tailored to the pre-retrofit
NOX emission rates actually observed at the Phase II units. As
shown in Table 12 in the preamble to the proposed rule (61 FR 1452),
Phase II units typically operate at lower uncontrolled emission rates
than Phase I units (i.e., 23% lower for wall-fired boilers and 18%
lower for tangentially fired boilers) so a simple extrapolation of the
experience of the mostly Phase I units in the LNB Application Database
would significantly underestimate the number of boilers that would be
expected to achieve a given emission limitation.
Second, using regression models also allowed for quantitative,
statistical evaluation of the explanatory power implicit in the
resulting estimates and enabled objective comparison of different
analytical approaches. Incorporating load-weighted annual averaging
into Step 1 of the procedure meant that any NOX/load effects would
be factored into the model.
Furthermore, responding to comments criticizing the proposed rule
for basing the regression model on 52 days of low NOX post-
retrofit emission data, the final rule uses the much longer post-
optimization data stream to build the regression equations. Use of this
longer data stream increases confidence that the regression equations
model the long-term behavior of boilers in the LNB Application
Database.
The Agency received detailed comments from utilities and a utility
association on three data issues and related technical components of
EPA's analysis methods. First, commenters questioned EPA's use of
short-term data to characterize pre-retrofit uncontrolled emission
levels when, for some boilers, long-term data were available.
Uncontrolled emission rates are used in Step 1 (Model Building) and
Step 2 (Calculation of Achievable Emission Rates) of EPA's analytical
procedure for deriving the annual emission limitations. Second, in a
related data issue, commenters believed that the uncontrolled emission
rates used for the affected population of Phase II boilers were biased
low, due partly to a misperception about how controlled NSPS units were
treated in Step 2. (Controlled NSPS units have older LNBs or some other
early type of NOX combustion control installed as original
equipment, so their measured baseline emission rates do not represent
uncontrolled emissions.) Third, commenters disagreed with or raised
questions about certain technical assumptions built into the models--
namely, the methods used to estimate percent NOX reduction outside
the range of the observed model inputs and the form of the regression
model. Finally, commenters said that monitored emissions data from
boilers sharing a common stack should be used cautiously, if at all,
when evaluating LNB performance and offered suggestions on how to
properly assess such measurements.
Salient background points regarding EPA's treatment of certain data
issues for the proposed rule are summarized in the paragraphs below.
The subsequent sections of this preamble discuss the comments more
fully, EPA's response to the issues raised, and how these data and
technical components are treated in the analysis supporting the final
rule.
EPA is fully cognizant that ``long-term data collection is the
definitive method to determine actual NOX reduction
characteristics of a low NOX combustion system'' and that DOE
Clean Coal Technology Demonstrations routinely collect long-term CEM
data to measure the baseline uncontrolled emission rate (see docket
item II-I-99, p. 8). At the time of the proposed rule analysis,
however, EPA had quality assured pre-retrofit long-term CEM data for
only 21% of the boilers in the LNB Application Database. Such CEM data
were unavailable for most of the wall-fired boilers (21 of 24) and over
half of the tangentially fired boilers (5 of 9). Generally, CEM data on
uncontrolled emissions were unavailable because the LNB retrofit had
begun prior to certification of the CEM system in accordance with 40
CFR part 75. EPA decided that it was preferable to use consistent,
quality assured, short-term measurements of uncontrolled emission rates
based on EPA Reference Method, certified CEM, or other test data rather
than to limit the LNB Application Database to only those boilers for
which EPA had quality assured, pre-retrofit, long-term CEM data. EPA
also rejected the possible option of using short-term data for some
boilers and long-term data for other boilers for the reasons explained
in detail in the next section of this preamble.
To assure that consistent data of known high-quality was used for
the model projections, EPA identified specific sources of acceptable
short-term uncontrolled emission rate data. These sources, listed in
priority order, are: (1) Short-term CEM data reported in monitor
certification review (CREV) tests (see docket item II-A-9); (2)
utility-reported CEM or EPA Reference Method test data provided on the
Acid Rain Cost Form for NOX Control Costs; and (3) other short-
term CEM or test data provided by utilities, generally as a correction
or update to data previously submitted to EPA.
For the proposed rule analysis, EPA obtained acceptable short-term
uncontrolled emission rate data for all units in the LNB Application
Database and for 69% of the Phase II boiler population. For the
proposal, EPA used uncontrolled emission rates based on long-term CEM
data or, as a last resort, estimates in the National Utility Reference
File (NURF), which were developed using emission factors, for the other
boilers in the Phase II population. For the final rule, EPA has located
substantial additional quality assured short-term uncontrolled emission
rate data and has discontinued using both long-term CEM and NURF

[[Page 67131]]

estimates for the Step 2 (Calculation of Achievable Emission Rates)
projections.

ii. Short-term vs. Long-Term Uncontrolled Emission Rate Data

Comment/Analysis. EPA received approximately 7 comment letters
(from 6 utilities and 1 utility association) on the use of short-term
uncontrolled emission rate data for assessing the performance of LNBs
applied to Group 1 boilers. Concern was expressed that using short-term
uncontrolled emission rates to build the regression equation would
cause the model to overestimate or, at least wrongly estimate, the
achievable reductions, because short-term uncontrolled emissions would
tend to reflect full-load uncontrolled emissions whereas the
corresponding controlled emissions values, used to build the regression
model, would represent the ``average of 1248 points at different
loads'' (see docket item IV-D-65, p. 51). The comments raised two
issues:
(1) Misuse of Short-Term Data: EPA used short-term uncontrolled
emission rate data even when, for some boilers, quality assured long-
term CEM data were available for determining pre-retrofit uncontrolled
emission rates. (See docket items IV-D-38, p. 3 and IV-D-65, pp. 50-51.
No commenter suggested, however, that EPA restrict the analysis to only
those boilers for which pre-retrofit, long-term CEM data were
available. EPA notes that one commenter, who recommended using a full
year of pre-retrofit monitoring data, selected CREV emission rates as
the best available substitute for baseline measurements when long-term
CEM data were not available.\10\
---------------------------------------------------------------------------

\10\ This commenter combined annual CEM and CREV baseline
measures when assessing the effect of a fuel switch on NOX
emissions for four boilers the utility owns and operates. The
analysis used annual CEM data for the ``before'' measurement on two
boilers, CREV emission rates for the ``before'' measurement on two
other boilers, and annual CEM data for the ``after'' measurement on
all four boilers (see docket item IV-D-038, Attachment A).
---------------------------------------------------------------------------

(2) Load Cell 10 Approach: Several commenters said the use of
short-term measurements of pre-retrofit uncontrolled emission rates in
both the EPA and DOE studies led to high estimates of uncontrolled
emission rates which, in turn, exaggerated LNB reduction efficiencies
(see, for example, docket items IV-D-11, p. 3 and IV-D-72, p. 3).
(Traditionally, LNB percent reduction efficiency has been measured on a
consistent pre-retrofit/post-retrofit basis, normally short-term to
short-term though occasionally long-term to long-term.) The load cell
10 approach was suggested by one commenter as a solution: its argument
runs as follows. In building the regression model, since EPA used
short-term uncontrolled emission rate data, which tends to be obtained
at full load, for consistency the post-retrofit controlled emission
values should have been ``the average NOX data in load cell 10 or
the highest load cell experienced at the boiler,'' not the average of
controlled emission values at all load levels. (See docket item IV-D-
65, p. 52.)
Response. (1) Misuse of Short-Term Data: For analytical, practical,
and statistical reasons, EPA chose to use short-term uncontrolled
emission data rather than only long-term uncontrolled emission data or
a combination of short-term and long-term uncontrolled emission data.
For analytical consistency, it is desirable, if not essential, for all
uncontrolled emission data to be long-term or short-term but not a
mixture of both. Maintaining this consistency across both the LNB
Application Database and the Phase II, Group 1 boiler population
database provides the logical underpinnings for drawing inferences from
the regression model to the Phase II data set, insofar as the
uncontrolled emission rate represents the independent variable in the
regression model. From an analytical standpoint it is perfectly
acceptable for the regression model's dependent variable (controlled
emission rate) to be based on a different duration standard (e.g.,
long-term as opposed to short-term) than the independent variable.
Practical and statistical considerations favored the selection of
short-term data over long-term data. In particular, it was not possible
to obtain quality assured long-term uncontrolled data for many units
because CEM requirements for Phase I boilers were generally coincident
with LNB retrofits. Fewer data points would have reduced the
statistical confidence in the conclusions drawn from the data.
Some commenters were apparently unaware of certain practical data
limitations. One commenter said, ``utilities have been required to
provide EPA with CEM data since at least January 1, 1995 (pursuant to
40 CFR part 75 . . . (so) the CEM NOX data should be used in most
instances for uncontrolled emissions'' (see docket item IV-D-65, p.
51). However, while desirable, this approach was not a practical
option. Since utilities are not required to report even approximate
dates of LNB installations for Phase II units to EPA, as they did in
Phase I on the Acid Rain Cost Form for NOX Control Costs, it is
exceedingly difficult to accurately determine the control status of
each unit, the date and hour on which a specific unit is being taken
off-line for installation of LNBs, and the end (i.e., date and hour) of
the pre-retrofit monitoring period. In contrast, reliable information
on unit control status accompanies the short-term uncontrolled emission
data in the CREV database since utilities are required to report the
type of NOX controls, if any, on each unit to EPA with the annual
certification review test data.
Using the short-term CREV data for the final rulemaking, EPA was
able to amass uncontrolled NOX emission rates for 85% of the Phase
II, Group 1 boilers. This includes virtually every Phase II, Group 1
boiler whose uncontrolled emissions were not otherwise obscured by
complex ``mixed'' common stack arrangements, either with respect to
boiler type (e.g., wall and tangentially fired boilers sharing a common
stack) or control status (e.g., controlled and uncontrolled boilers
sharing a common stack). Quality assured short-term uncontrolled
emission data were obtained for an additional 13% of the Phase II,
Group 1 boilers from other acceptable sources. In all, about 98% of the
affected Phase II, Group 1 boilers were included in the Step 2 analysis
(Calculation of Achievable Emission Rates) for the final rule.
Notwithstanding commenters' concerns, the ability of the regression
model to estimate achievable NOX emission limits is not diminished
by using short-term uncontrolled emission values as the regression
model's independent variable. This is a consequence of the structure of
the model. In the model building stage (Step 1) of EPA's analytical
procedure a functional relationship is established between short-term
uncontrolled emissions and the post-optimization load-weighted
controlled average emission rate achieved by boilers in the LNB
Application Database. In Step 2, as long as the Phase II short-term
uncontrolled emission values that are fed into the regression equation
remain within the range for which the model was designed, the model's
ability to estimate the corresponding achievable post-optimization
annual emission rate should remain unimpaired.
To evaluate the effect of using short-term rather than long-term
data for uncontrolled emission rate on the annual emission limitations
derived from the 3-step analytical procedure, EPA was able to assemble
a database of 18 boilers containing long-term pre-

[[Page 67132]]

retrofit emission rate values.\11\ This database was used to perform
sensitivity tests on the effect of using long-term vs. short-term
measurements of uncontrolled emission rate on the projections of the
number of Phase II, Group 1 boilers that could comply with various
performance standards. For these tests, EPA used the long-term, instead
of short-term, measurements for uncontrolled emission rate in Step 1
(Model Building) wherever such pre-retrofit data were available (18 out
of 53 boilers). The R^{2 values for the resulting regression models
based on load-weighted annual average emission rates over the post-
optimization period were 65.3% (wall-fired boilers) and 78.9%
(tangentially fired boilers), indicating acceptable fit (see docket
item IV-A-6, Tables 4-6a and 4-6b). Applying these models to the Phase
II, Group 1 data set of uncontrolled emission rates produced the
results shown in docket item IV-A-6, Tables 4-7a and 4-7b. Within the
primary range of interest (i.e., from 80th to 90th percentiles), the
percentage of boilers estimated to achieve a specified emission limit
using the long-term data typically varies by less than 2% (and not more
than 5%) from the percentage derived using strictly short-term data.
Both positive and negative differences occur, depending on the exact
percentile and type of boiler, suggesting the emission limit could be
lowered in some instances and raised in others. EPA concludes that
using short-term measurements of uncontrolled emission rate has not
systematically nor significantly lowered the resulting estimates of
controlled emission rates achievable by Phase II, Group 1 boilers
retrofit with LNBs.
---------------------------------------------------------------------------

\11\ Long-term pre-retrofit emission rate values were defined
from the hourly CEM data as follows. The pre-retrofit period, which
is called ``pre-retrofit minus 30 days'' (abbreviated as ``30-day
pre-rate'' in tabular column headings), starts at the beginning of
the CEM data set. Because some uncertainty exists as to the exact
date of the LNB retrofit, EPA used only quality assured CEM data
recorded more than 30 calendar days before the primary boiler outage
for installation of LNBs. These days are excluded to assure that no
post-retrofit data are mixed with pre-retrofit data in the baseline
measurement. Consistent with the post-retrofit situation, EPA
included only boilers which had at least 1,248 hours (or 52 days) of
quality assured pre-retrofit CEM data.
---------------------------------------------------------------------------

(2) Load Cell 10: Use of load weighting in EPA's regression model
makes the load cell 10 restriction unnecessary. As noted in the
preceding paragraph, the regression model establishes a functional
relationship between the short-term uncontrolled emission rate and the
load-weighted annual average emission rate maintained over the post-
optimization period. If, as the commenter maintains, the load level can
be assumed to relatively constant for all the short-term uncontrolled
emission data (i.e., at full load), all the more reason exists for the
functional relationship captured in EPA's regression equation to remain
intact.
The load cell 10 approach would establish a functional relationship
between the short-term uncontrolled emission rate and the long-term
controlled emission rate achieved when the unit is operating at
essentially full load (i.e., in ``load cell 10,'' at 90-100% of total
unit operating load).\12\ The dependent variable in this regression
model would be the unit's average ``load cell 10'' (or full-load)
controlled emission rate. This approach would discard all post-retrofit
CEM hourly data recorded when the unit is operating in load cells 1
through 9 and thus, would not be representative of unit's average
emission rate over a calendar year. This would be inconsistent with the
purpose under section 407(b)(2) of analyzing LNB performance, which is
to determine whether the existing Group 1 emission limitation applied
on any annual average basis should be made more stringent.
---------------------------------------------------------------------------

\12\ The ``load cell 10 approach'' uses only data recorded for
the highest load cell experienced at the boiler, which is normally
load cell 10.
---------------------------------------------------------------------------

EPA notes that for boilers where NOX emission rate increases
with increasing load, the achievable full-load emission rate determined
using the load cell 10 approach would be higher than the average
emission rate observed over varying boiler loads throughout a year. At
least 25% of the wall-fired boilers in the LNB Application Database
operated at full load for less than 20% of total operating hours in
1995. Basing the annual performance standard on an achievable full-load
emission rate would inappropriately bias the emission limitation since
many boilers are typically operating at lower loads most of the time.

iii. Potential for Low Bias in Phase II Uncontrolled Emission Rate
Estimates/Treatment of NSPS Units

Comments/Analysis: EPA received approximately 5 comment letters
(from 3 utilities and 2 utility associations) saying that EPA's
estimates of uncontrolled emission rates for the Phase II boiler
population appeared too low. The commenters cited different reasons for
this outcome and some submitted unit-specific estimates of uncontrolled
emission rate (see, for example, docket item IV-D-39, p. 3). Several
commenters attributed the seemingly low rates to the inclusion of NSPS
units in the Phase II boiler population baseline of uncontrolled
emission rates. As one commenter stated, ``the NSPS units are by
original design low NOX emitters . . . and (if included), the
overall Phase II, Group 1 boiler baseline rate will be artificially
biased downward and will lead to conclusions that overstate the ability
of both non-NSPS and NSPS units to achieve the final emission limit for
this boiler group'' (See docket item IV-D-72, p. 3).
Response: These commenters correctly noted that the technical
support document for the proposed rule does not contain a separate
baseline for NSPS units nor any explicit discussion of the how these
units are treated in Step 1 (Model Building) and Step 2 (Calculation of
Achievable Emission Rates) of EPA's projection analyses. EPA developed
a table comparing the average uncontrolled emission rates, by boiler
category, for the Phase II, Group 1 boiler population with and without
NSPS Subpart D and Subpart Da units against the Phase I, Group 1 boiler
population (see docket item IV-A-10). This table shows that average
uncontrolled emission rate for the Phase II population excluding units
identified as ``NSPS-vintage units'' \13\ is definitely lower than the
average uncontrolled emission rate for the Phase I population: the
difference is estimated as 10% for wall-fired boilers and 9% for
tangentially fired boilers.
---------------------------------------------------------------------------

\13\ This classification of ``NSPS-vintage units'' was based on
boiler age as reported in the NURF data file.
---------------------------------------------------------------------------

Subsequent to the rule proposal, EPA obtained additional data to
refine both the classification of Phase II units subject to NSPS
NOX requirements, including both Subpart D and Subpart Da, and the
description of any pre-existing NOX combustion controls installed
on these units. EPA notes that since no percent reduction standard for
NOX applies to Subpart D boilers, Subpart D units frequently do
not have combustion controls installed as original equipment. Subpart
Da boilers are required to achieve a specified percent reduction for
NOX, so Subpart Da units generally had some early form of NOX
combustion controls installed prior to November 15, 1990.
As discussed previously in section III.A.1 of this preamble, EPA
has excluded controlled NSPS boilers from the model building regression
analyses because their measured baseline emission rates do not
represent uncontrolled emissions. However, EPA has included all NSPS
boilers, controlled and uncontrolled, in the

[[Page 67133]]

Phase II boiler data set on which the regression models are applied
because coal-fired NSPS boilers are subject to this rulemaking.
NSPS boilers are by original design inherently lower NOX
emitters and have larger furnace volumes per MW than most pre-NSPS
boilers which makes it easier for NSPS boilers, when retrofit with
current LNB technology, to achieve specified levels of controlled
NOX emission rates.\14\ The only NSPS boiler for which EPA has
long-term post-retrofit CEM data (North Valmy 1) corroborates the
assessment that NSPS boilers, when retrofit with current LNB
technology, can generally achieve lower NOX levels than most pre-
NSPS boilers. North Valmy 1 sustained an average controlled emission
rate of 0.264 for calendar year 1995 (see docket item IV-A-9). Although
several commenters discussed this particular LNB installation, none
provided any information which would suggest this boiler is not typical
of controlled NSPS boilers.
---------------------------------------------------------------------------

\14\ Reference: Smith, L. 1988. Evaluation of Radian/EPA
NOX Reduction Estimation Procedures. ETEC-88-20046. February.
---------------------------------------------------------------------------

iv. Technical Assumptions Used in Group 1 Regression Model

EPA received approximately 3 comment letters (from 2 utilities and
one utility association) on certain technical assumptions in the Group
1 regression model approach--namely, the methods used to estimate
percent NOX reduction outside the range of the observed model
inputs and the form of the regression model.
a. Estimation Method for Units with High Uncontrolled Emission Rates
Comment/Analysis: Commenters said that percent NOX reductions
and controlled emission rates that seemed to be predicted by EPA's
regression model at theoretically high values of uncontrolled emission
rates were ``curious'' and seemingly contrary to experience and common
sense.
Any regression model is statistically verifiable only for the range
of data used to construct the model. Not realizing that EPA had assumed
the percent NOX reduction for any Phase II boilers with
uncontrolled emission rates above the highest value in the LNB
Application Database was equal to the percent NOX reduction
estimated for the highest data point (see docket item II-F-2, p. 4-3),
some commenters said the model ``predicts NOX control scenarios
that lead to absurd results'' such that if one can only increase
uncontrolled NOX emissions to a sufficiently high level, one could
achieve 100% NOX removal!'' (see docket item IV-D-65, p. 43 and
IV-G-16, p. 6).
Response: EPA's failure in the proposal to explicitly state a
caveat that is routinely assumed in regression analysis led these
commenters to draw erroneous conclusions from the model. The required
caveat is that the statistically verifiable fit of a regression model
is only assured within the range of the data actually used to construct
the model. Thus, for the regression equations used in the proposed
rule, the statistically verifiable range (in uncontrolled emission
rates) for wall-fired boilers was from 0.51 lb/mmBtu to 1.34 lb/mmBtu
and for tangentially fired boilers was from 0.48 lb/mmBtu to 0.66 lb/
mmBtu. With the addition of 20 boilers to the LNB Application Database
in support of the final rulemaking, the current upper limits on the
ranges have increased to 1.41 lb/mmBtu for wall-fired, and to 0.86 lb/
mmBtu for tangentially fired boilers (see docket item IV-A-6, Tables 3-
1a and 3-1b).
Had the commenters been cognizant of the caveat described in the
previous paragraph, they probably would not have drawn the admittedly
``curious'' conclusions noted above. Further, had they assumed proper
application of the model instead of presuming improper application,
they would have noted that the model was not applied outside its
effective range.
Similarly, the commenters were also troubled by the seeming
implication that the mathematical form of the regression seemed to pre-
ordain that emissions could never exceed a certain maximum bound. As
the commenter in docket item IV-D-65 puts it: The model predicts ``. .
. that controlled emissions at wall-fired boilers will never exceed
0.454 lb/mmBtu.'' In fact, based on existing data, the model simply
shows a maximum predicted emission reduction over the model's
statistically verifiable range. For points outside the range of the
model, no specific bound is implied, and the maximum observed emission
reduction was not exceeded.
As in the proposal, when estimating the controlled emission rates
for Phase II, Group 1 boilers with uncontrolled emission rates higher
than the verifiable range of the model, EPA made the following
assumption \15\: the percent NOX emission reduction for such
boilers was assumed to be no greater than the reduction obtained by the
boiler with the highest uncontrolled emission rate in the LNB
Application Database. In effect, this assumption would lead to emission
limits that are less stringent than if it were assumed that the
emission reductions for such boilers could exceed those of boilers in
the LNB Application Database.
---------------------------------------------------------------------------

\15\ Only 1 wall-fired boiler and 3 tangentially fired boilers
in the Phase II boiler data set (representing less than 1% and less
than 2%, respectively, of the affected populations) have measured
uncontrolled emission rates higher than the range used to construct
the regression model and thus fall in this category.
---------------------------------------------------------------------------

b. Form of the Regression Model
In both the analysis for the proposed and final rules, EPA
considered two alternative forms of the regression models used to
predict the achievable controlled emission rates from uncontrolled
boiler NOX emission rates:
Model #1 (One-step approach): Direct linear fit, regressing
controlled emission rate on uncontrolled emission rate.
Model #2 (Two-step approach): Step 1--Direct linear fit, regressing
percent NOX reduction on uncontrolled emission rate. Step 2--
Controlled emission rate is computed from the percent reduction derived
in Step 1.
EPA chose Model #2 because the regression equations derived using
this model explain the data better than those derived using Model #1.
Statistically, this is expressed in the higher ``R \2\ value'' of Model
#2 (R \2\=73.1% for wall-fired boilers; R \2\=70.7% for tangentially-
fired boilers) as compared to Model #1 (R \2\=59.7% for wall-fired
boilers; R \2\=17.0% for tangentially-fired boilers) (see docket item
IV-A-6, Tables 4-9a and 4-9b).
Comment/Analysis: A commenter criticized EPA's choice of Model #2,
saying that it models the wrong parameter: ``. . . while the key issue
in this rulemaking is the level of controlled emissions at Phase II,
Group 1 boilers, . . . (EPA's) model is designed to predict NOX
removal efficiency--a related but secondary parameter'' (docket item
IV-D-65, p. 45). Consequently, the commenter questioned the
meaningfulness of a superior R \2\ value from a model that regresses
percent reduction on uncontrolled emissions, when the true parameter of
interest is not percent emission reduction but controlled emissions:
``. . . just because Model 2 predicts removal efficiency better than
Model 1 predicts controlled emissions does not mean that Model 2
predicts controlled emissions better than Model 1'' (docket item IV-D-
65, pp. 45-46).
Response: While on the surface this criticism appears plausible, on
further investigation it is incorrect because the two-step approach of
Model #2 is algebraically equivalent to a one-step second order linear
regression model that directly regresses controlled

[[Page 67134]]

emissions on uncontrolled emissions.^{16 Thus, although its two-step
formulation makes Model #2 appear not to regress controlled emissions
on uncontrolled emissions, in actuality, by simply restating Model #2
in its second-order form, it can be shown to be no different in this
regard than Model #1: Both models regress controlled emissions on
uncontrolled emissions: Model #1 using a first-order linear expression;
and Model 2 using a second-order linear expression.
---------------------------------------------------------------------------

\16\ The two-step version of Model #2 fits a first-order linear
model p=0=1U+ data, where U is
the regressor variable ``uncontrolled emissions'' and P is the
response variable ``percent reduction.'' Then, in step 2, C, the
controlled emission rate, is calculated from P using the equation
C=U(1-P/100). However, Model #2 (two step) can be reformulated as a
one step second-order linear regression model,
C='0+'1U+11U^{2+
'. Like Model #1 (one-step), Model #2 (one step) regresses C on U.
---------------------------------------------------------------------------

Interestingly, EPA's calculations indicate that had the Agency
adopted Model #1, as advocated by the commenter (a large association of
utilities), the resulting achievable annual emission rates at the 90th,
85th, and 80th percentiles, for both wall-fired boilers and
tangentially fired boilers, would be approximately one-half to one
percentage point lower (i.e., more stringent) than the achievable
annual emission rates obtained using Model #2. (See docket item IV-A-6,
Tables 4-10a and 4-10b). Thus, although EPA adopted Model #2 on
strictly statistical grounds, it turns out that in the analysis for the
final rule, Model #2 was more favorable than Model #1 to those
commenters seeking less stringent emission limitations.
v. Common Stack Issues in Group 1 Analysis
Background: In the proposed rule analysis, EPA found no strong
correlation between boiler operating loads and post-retrofit hourly
average controlled emission rates for single-stack boilers in the LNB
Application Database and therefore, assumed that two boilers of the
same type (i.e., wall-fired or tangentially fired) and NOX control
status (i.e., both had LNBs only) sharing a common stack would have
similar post-retrofit controlled emission rates. (EPA notes that some
utilities also made this assumption when completing the Acid Rain Cost
Form for NOX Control Costs for their Phase I LNB retrofits and
provided ``sister unit'' estimates of emission rates in instances where
multiple units were sharing a common stack.) In EPA's analysis,
therefore, the rates from similarly situated individual units at a
common stack were assumed to be the same, and single boiler and
multiple boiler data were analyzed together (i.e., the common stack
emission rate was assigned to each constituent unit).
Comment/Analysis: EPA received approximately 4 comment letters
(from 3 utilities and a utility association) on considerations for
using common stack data when analyzing LNB performance applied to Group
1 boilers. One commenter advised EPA to ``use caution when evaluating
NOX data from combined stacks'' (see docket item IV-G-14, p. 1).
Another commenter said EPA should ``either exclude common stack
emissions data from its analysis, or revise its analysis based on data
collected during periods when only a single unit [to a common stack] is
operating'' (see docket item IV-D-65, p. 42).
EPA notes that the decision on how to treat common stack data has
important ramifications for both: (1) The amount of post-retrofit CEM
data available for analysis; and (2) the number and representativeness
of LNB retrofit cases in the LNB Application Database. Sixteen (16) of
the 39 wall-fired boilers (41%) and 6 of the 14 tangentially fired
boilers (43%) in the LNB Application Database exhaust to common stacks
with similarly situated boilers also in the database; collectively,
these boilers contribute 242,000 hours to the total of 477,800 hours of
post-retrofit CEM data available through the second quarter of 1996 to
support the final rule. Twenty-two (22) of the boilers sharing a common
stack have post-optimization periods spanning 11 calendar months or
longer. EPA does not consider the approach of excluding common stack
emissions data, suggested by one commenter, a viable option because
disregarding the substantial collective experience of these boilers
would clearly reduce statistical confidence in the resulting assessment
of LNB performance.
Accordingly, EPA has sought other ways to address the commenters'
criticism that EPA did not provide credible support in the proposed
rule analysis for its treatment of common stack data. The specific
concerns cited are: (1) Using the common stack post-retrofit NOX
emission rate as the emission rate for each individual boiler sharing
the common stack in the regression analyses; and (2) developing
NOX/load curves for common stacks by summing the NOX
emissions and loads from the boilers sharing the stack (see docket item
IV-D-65, pp. 37-38).
Response: EPA has performed extensive follow-up analysis on whether
measured common stack emission rate data over the post-optimization
period reflects the combined annual averages of individual boilers
sharing the common stack. EPA compared the combined common stack
emission rate to the individual-unit emission rates at every common
stack in the LNB Application Database for which usable post-retrofit
CEM data could be identified for periods when only a single unit was
operating. In all, EPA studied 10 common stacks with 22 constituent
boilers and over 19,800 hours of individual-unit emission rate data.
The analysis included:
(1) Box and whisker plots: The plots present side-by-side displays
of the range of emission rates at common stacks when all units were
operating compared to when only single units were operating: for each
common stack, separate plots were generated using emission rates
observed during the low NOX period and the post-optimization
period. In both cases the plots show little difference between
multiple-unit common stack emission rates and the individual unit
emission rates over the averaging periods.
(2) Percent Difference Calculations: Computing the percent
difference between the multiple-unit and single-unit average emission
rates for the post-optimization averaging period revealed that, on
average, the percent difference for the wall-fired boilers was -0.3%,
while for the tangentially fired boilers the percent difference was
1.8%. (See docket item IV-A-6, Tables 4-8a and 4-8b.) This strongly
indicates that, contrary to the belief of some commenters, there is not
a significant disparity between the common stack and constituent unit
NOX emission rates for the post-optimization averaging period.
(3) Sensitivity Analysis: EPA performed a series of analyses to see
how estimates of achievable annual emission limitations were affected
by various treatments of common stack emissions. Three scenarios were
investigated. In the first, the regression model was built using the
constituent unit emission rates instead of the common stack emission
rates. In the second, each common stack emission rate was used only
once for each stack. In the third, the common stack emission rate was
repeated for each unit. The third treatment is the same as that used by
EPA in the proposed rule. The regression models fit the load-weighted
data over the post-optimization averaging period approximately equally
well, as measured by R^{2, for the various treatments of common
stack emissions data. (The R^{2's ranged from 73.1-75.1% for the
wall-fired boilers and from 62.8-72.1% for the tangentially fired
boilers (see docket item IV-A-6, Tables 4-9a

[[Page 67135]]

and 4-9b.) The differences among the achievable annual average emission
rates predicted by the regression models under the three scenarios at
the 90th, 85th, and 80th percentiles varied by only 0.001-0.003 lb/
mmBtu for wall-fired boilers and even less for tangentially fired
boilers (see docket item IV-A-6, Tables 4-10a and 4-10b). The
alternative scenarios produced estimates of achievable annual emission
limitations no less stringent than the third treatment, which is used
for today's final rule.
(4) Load Profile Analysis: One of the commenter's arguments against
using common stack NOX emission rates was the contention that the
emission rate for the stack could be artificially low because the
averaging period occurred during a time when only a single unit just
happened to be operating at an untypically low emitting load profile.
To respond to this concern, EPA verified that during the post-
optimization averaging period the ``load profile'' (i.e., the
distribution of load) of every unit exhausting to each common stack
analyzed was congruent with the annual load profile for that unit. This
analysis verified that no matter what configuration of boilers happened
to be operating, the common stack emission rates used to build EPA's
regression model could not have resulted from an atypical low emission
load profile during the post-optimization averaging period.
With respect to the commenter's argument that EPA developed
NOX/load curves for common stacks by summing the NOX
emissions and loads from the boilers feeding the stack, the commenter
appears to have misunderstood EPA's approach.
The commenter wrongly believed that EPA's analysis rests on one of
three alternative assumptions: no NOX/load relationship exists,
identical NOX/load relationships exist among constituent units, or
identical loading patterns prevailed for all units during the averaging
period (see docket item IV-D-65, p. 38). This misunderstanding led the
commenter to offer a hypothetical illustration to show how a single
NOX /load combination at the common stack can be produced by seven
different NOX/load combinations at the constituent boilers. Based
on the absence of a unique NOX/load correlation at the common
stack, the commenter concludes that ``common stack NOX data cannot
be used to characterize the NOX emissions for individual units.''
EPA's analysis in today's final rule does not presuppose any of the
three assumptions identified by the commenter. As discussed above, EPA
evaluated the load patterns of individual units on each common stack
and found that these load patterns for a given stack were very similar.
EPA's load-weighted post-optimization approach first calculates the
achievable percent emissions reduction without presumption of a
NOX/load relationship or a particular load pattern and then
adjusts the achievable percent reduction based on the annual NOX/
load patterns actually encountered. In effect, this approach takes into
account any NOX/load relationship that may be present without
assuming ahead of time that the relationship is present, absent, or
takes a particular form.
Finally, it should be noted that for compliance purposes, the
NOX emission limits will usually apply to common stacks, not their
constituent units. Under Sec. 75.17, a unit that utilizes a common
stack with other units, all of which are required to meet a NOX
emission limit, generally may: separately monitor the duct from each
unit to the stack and comply on an individual unit basis; or monitor
the stack and comply through an averaging plan with the other units,
individually with the most stringent limit for the units, or
individually based on an approved method of apportioning the stack
emissions rate. Most common stack units use the averaging plan option.
In fact, all common stack units analyzed in this rulemaking that are
subject to NOX emission limitations in Phase I are complying
through averaging their emissions with the other units in the common
stack, not individually. Thus, from a regulatory, as well as a strictly
technical perspective, it is appropriate to use common stack emission
data to build the model employed in establishing the Phase II, Group 1
NOX emission limits that will apply to boilers and common stacks.
4. Percentile Used to Define Achievability
Background. For the final step of the analysis, EPA arrayed the
estimates of controlled NOX emission rates that the Phase II units
could be expected to achieve when retrofit with LNBs. Separate rank
orderings were made for wall-fired boilers and for tangentially-fired
boilers. Using these rank orderings, EPA tabulated percentile
distributions of achievable annual emission rates for each boiler
category (see 61 FR 1452, (Tables 10 and 11)). EPA selected values for
the proposed annual emission limitations that, according to these
tables, about 90% of the affected units could comply with on an
individual basis. It was not necessary that 100% or even essentially
all of the affected units be able to comply with the applicable
performance standard on an individual basis because of the flexibility
offered by two compliance options available to Group 1 boilers: (1)
emissions averaging and (2) alternative emission limitations (AELs).
Comments/Analyses. EPA received approximately 5 comment letters
(from 3 state agencies representing 2 different states, a regional
association of state air pollution control agencies, and an
environmental organization) on the percentile used to define
achievability.
These commenters said that, given the serious and multifaceted
threat NOX poses to the environment and public health, EPA should
set the most effective controls possible within existing authority.
According to one state agency, ``the reductions in nitrogen oxide
anticipated by the proposed regulation . . . are minimal compared to
the amount of NOX reductions necessary to protect the sensitive
aquatic resources of the northeastern United States from further
degradation'' (see docket item IV-D-25, p. 3). A regional association
of state air pollution control agencies said, ``(While) EPA's authority
to promulgate emission limits derives in this instance from a section
of the CAA chiefly concerned with addressing acid deposition . . .
EPA's proposal should be viewed in light of the much more significant
emissions reductions needed to rectify other serious air quality and
public health problems that are also associated with NOX
emissions, including fine particulate pollution, ozone smog, regional
haze, and the eutrophication of aquatic ecosystems.'' (See docket item
IV-D-46, p. 2.) They urged EPA to base its revised emission limitations
for Phase II, Group 1 boilers on a lower threshold than 90% of the
affected population in light of the flexibility afforded by the
emissions averaging and AEL compliance options (see docket items IV-D-
46, p.6; IV-D-63, p.7; and IV-D-25, pp. 5-6).
The Offices of the Attorney General of two northeastern states and
an environmental organization said that EPA's proposal would allow
excessive NOX emissions for Group 1 boilers since, according to
the RIA for the proposed rule, ``less than half the potentially
affected sources may be required to implement new controls.'' (See
docket items IV-D-25, p. 5; IV-D-74 p. 4; IV-D-63, pp. 6-7.) Two of
these commenters recommended setting Phase II, Group 1 emission
limitations at 0.41 lb/mmBtu for wall-fired boilers and 0.35 lb/mm/Btu
for tangentially fired boilers, which would increase NOX

[[Page 67136]]

reductions from the Group 1 emission revisions by 57% and would make
the emissions averaging provision environmentally neutral (see docket
items IV-D-63, pp. 6-7 and IV-D-74, pp.4-5).
No commenter said that EPA's target of 90% compliance on an
individual basis was too low. As discussed in the previous sections,
however, some commenters disagreed with the technical methods EPA used
to develop the percentile distributions of achievable annual emission
limitations for Phase II, Group 1 boilers and, as a result, believe the
proposed emission limitations are too low. One commenter said EPA
should encourage the optional use of AELs or emission averaging plans
for Phase II, Group 1 boilers (see docket item IV-D-57, p. 3). Other
commenters (but none of the 15 state agencies or associations who
commented on the rule proposal) predicted an increase in the number of
AEL applications to be filed with state agencies (see, for example,
docket item IV-D-31, p. 2).
On the other hand, a regional association that has provided
technical expertise to its 8 member states and served as a forum for
coordinating region-wide air quality management practices for over 25
years said, ``Experience from reducing NOX emissions from coal-
fired boilers in the Ozone Transport Region (OTR) * * * solidly
support[s] EPA's finding that the revised emission limits for Phase II,
Group 1 boilers * * * are highly cost-effective, meet the statutory
requirements of Section 407, and can be achieved by the vast majority
of affected boilers.'' (See docket item IV-D-46, p. 2.) Corroborating
this view is the testimony at the public hearing on EPA's rule proposal
by the principal engineer for environmental affairs of the largest
utility in New England. Based on his experience in retrofitting six
coal-fired units that are achieving the proposed NOX emission
rates, he stated that his utility's initial reaction in 1989-1990 to
NOX control requirements ``was virtually identical to the reaction
that we're getting from the midwestern utilities and the southern
companies now.'' He added that his utility had believed NOX
control ``was frighteningly expensive, it was far more money than it
was worth, and our reaction at that point, knowing that we would
certainly have to do some controls, was essentially to turn loose the
engineers and operators and let them * * * find better ways to do this.
The bottom line was that we found that the harder that we looked, the
cheaper the controls got. Our final compliance costs are about a fifth
of what we thought they would be going into this * * * and we were very
pleasantly surprised.'' (See docket item IV-F-1, pp. 7-9.)
Response. As discussed in section I.B.2 of this preamble, EPA is
fully cognizant that recent acid deposition and ozone modeling studies
show that substantial additional NOX reductions, even beyond the
levels in the rule proposal, are needed to mitigate against the
multiple adverse effects of NOX on human health and the
environment, particularly since national NOX emissions are
projected to begin increasing after 2002. On balance, EPA has decided
in the final rule to define a reasonably achievable emission limitation
as one that 85 to 90% of the units subject to the limitation are
projected to meet on an individual unit basis. On one hand, the Agency
recognizes that the ability of units to comply by averaging their
emissions will increase further the percentage of units that will be
able to comply without seeking an AEL. Because almost six times as many
units are subject to NOX emission limitations in Phase II as in
Phase I, the opportunities for compliance through averaging will be
generally much greater in Phase II. In adopting the initial NOX
emission limitations for Group 1 boilers under section 407(b)(1), EPA
selected limitations that about 90 percent of the units were projected
to meet on an individual unit basis. In light of the significantly
greater opportunities for averaging in Phase II, EPA maintains that the
approach of setting Phase II emission limitations targeting a somewhat
lower (85 to 90%) individual-unit achievement level is justified. On
the other hand, EPA does not want to select emission limitations that
would lead to overuse of the AEL compliance option, which is intended
primarily for units with very high uncontrolled emission rates or units
that are otherwise unusually difficult to retrofit with LNBs. The RIA
for this final rule estimates the average cost to a utility for
testing, monitoring, and documentation associated with an AEL
application will run about $225,000, but this cost may vary
considerably by utility and for different states (see docket item V-B-
1, Exhibit 6-6). One commenter estimated each AEL application will cost
``the Company in excess of $300,000 in testing and analytical
expenses'' (see docket item IV-D-23, p. 6), although the commenter did
not say whether his utility imposes additional internal requirements to
justify filing with the permitting authority for a special (higher)
emission limitation. As discussed below, the RIA projects that AELs
will be used by less than 10% of Phase II boilers.
The Agency has developed Tables 5 and 6 displaying the percentage
of Phase II, Group 1 units, by boiler category that are projected to
achieve various annual average emission limitations when retrofit with
LNBs. The values EPA has selected to promulgate as revisions to the
Group 1 emission limitations are in bold print. In response to comments
stating that the proposed 90 percent passing threshold in the proposed
rule was too conservative, EPA has decided to set the emission limit
for Phase II, Group 1 and Group 2 boiler types based on the emission
level that 85 to 90 percent of the affected boilers can individually
meet. Thus, EPA considers an emission limit to be reasonably achievable
if 85 to 90 percent of the units of the particular boiler type are
projected to meet the emission limit. Therefore, in the absence of
unique, countervailing circumstances, EPA has generally selected as the
Phase II, Group 1 or Group 2 emission limit the emission rate with an
individual-unit achievement level that is between 85 and 90%. On this
basis, EPA adopts revised Phase II, Group 1 emission limits of 0.46 lb/
mmBtu for Phase II wall-fired boilers and 0.40 lb/mmBtu for
tangentially fired boilers.

Table 7.--Percentile of Phase II Wall-Fired Boilers Achieving Emission
Limit
------------------------------------------------------------------------
Percent of
boilers
Emission level (lb/mmBtu) meeting
emission level
------------------------------------------------------------------------
0.48.................................................... 96.0
0.47.................................................... 91.9
0.46.................................................... 88.3
0.45.................................................... 85.0
0.44.................................................... 83.2
0.43.................................................... 78.0
------------------------------------------------------------------------

Table 8.--Percentile of Phase II Tangentially Fired Boilers Achieving
Limit
------------------------------------------------------------------------
Percent of
boilers
Emission level (lb/mmBtu) meeting
emission level
------------------------------------------------------------------------
0.43.................................................... 98.2
0.42.................................................... 98.2
0.41.................................................... 95.7
0.40.................................................... 91.4
0.39.................................................... 78.1
0.38.................................................... 67.6
------------------------------------------------------------------------

The RIA for this final rule also projects the number of affected
units for

[[Page 67137]]

which utilities are apt to select the AEL compliance option. The
projection models a scenario where evaluation of emissions averaging
opportunities is not a pre-requisite for an AEL (a true assumption).
The RIA predicts that, with the annual emission limitations EPA is
promulgating in this final rule, AELs are likely to be sought for
approximately 42 Phase II, Group 1 boilers, representing 7% of the
affected population (see docket item V-B-1, Exhibit 7-5).

B. Group 2 Boiler NOX Emission Limits

1. Cost Comparability and Its Basis
Section 407(b)(2) the Act requires EPA to set Group 2 boiler
NOX emission limits based

on a degree of emission reduction achievable through the
retrofit application of the best system of continuous emission
reduction, taking into account available technology, costs and
energy and environmental impacts; and which is comparable to the
costs of nitrogen oxide controls set pursuant to (section
407)(b)(1). 42 U.S.C. 7651f(b)(2).

The Act does not define the term ``comparable'' or specify the
appropriate method of comparing ``costs''. In the proposal, EPA stated
that it believed that the terms ``comparable'' and ``cost'' were
ambiguous, and, therefore, EPA consulted the legislative history of
section 407(b)(2). Based on the legislative history, EPA's proposal
interpreted ``comparable'' to mean ``similar but not necessarily
equal'' and used cost-effectiveness ($/ton of NOX removed) as the
basis for conducting cost comparisons. 61 FR 1460. EPA interpreted the
comparable-cost provision in section 407(b)(2) to require that the
cost-effectiveness of applying NOX controls to any Group 2 boiler
population be comparable to the cost-effectiveness of applying LNBs to
the Group 1 boiler population . EPA also took account of the other
factors (e.g., ``costs and energy and environmental impacts'') listed
in section 407(b)(2) by, inter alia, determining whether the cost
impact to ratepayers (in mills/kWhr) of Group 2 boiler NOX
controls is similar to the cost impact (in mills/kWhr) of Group 1
boiler LNBs.
Comment/Analyses: EPA received 7 comments (from 3 utilities, 1
State, 1 utility associations, and 2 environmental groups) on the
interpretation and implementation of the comparability requirement in
section 407(b)(2).
Some utility commenters believe that the term ``comparable'' is not
ambiguous as used in the statute because it has a common dictionary
meaning of ``equivalent'' or ``similar.'' These commenters argue that,
because ``comparable'' has a commonly understood meaning, there is no
reason to consult legislative history. Other utility commenters believe
that ``comparable'' should be interpreted to mean ``equal to'' or
``less than or equal to.'' Other commenters cite the common dictionary
definition of the term ``comparable'' and maintain that the term is
inherently vague. These commenters believe that EPA's reliance on the
legislative history is proper since the common meaning of the term
``comparable'' is ambiguous, that the legislative history cited by EPA
is the only reference in the legislative history addressing what
Congress meant by the term ``comparable,'' and that the legislative
history supports EPA's interpretation.
EPA notes that, according to the Webster's Third New International
Dictionary (Springfield, Massachusetts, 1981), the term ``comparable''
is defined as: (1) ``Capable of being compared''; (2) ``suitable for
matching; coordinating; or contrasting: EQUIVALENT, SIMILAR....syn see
LIKE.'' Only the second definition appears to be relevant in the
context of section 407(b)(2). According to the same dictionary,
``similar'' means ``having characteristics in common: Very much alike:
COMPARABLE'' while ``equivalent'' means ``equal in force or amount.''
As further explained (under the dictionary's discussion of ``like''):
``COMPARABLE indicates a likeness on one point or a limited number of
points which permits a limited or casual comparison or matching
together.'' In short, one set is ``comparable'' to another set if the
two are equal or if they are ``similar'' to each other without being
identical. Therefore, ``comparability'' does not require ``equality,''
and the degree to which ``comparable'' sets must be ``similar'' to each
other is unclear under section 407(b)(2) and is a matter of
administrative judgment.
Some commenters further believe that section 407(b)(2) of the Act
states that what should be compared is the ``cost'' (allegedly mills/
kWh) of ``controls'' such as LNBs, not the ``cost-effectiveness'' ($/
ton of NOX removed) of those controls. These commenters argue that
cost-effectiveness is only appropriate when the ``cost'' to be measured
is the cost of attaining emission reductions and that the plain meaning
of section 407(b)(2), supported by the legislative history, is that the
Administrator is required to compare ``cost,'' not ``cost-
effectiveness,'' as the basis for setting Group 2 emission limitations.
Other commenters state that the plain meaning of section 407(b)(2)
requires that the ``degree of reduction'' on which EPA bases Group 2
emission limitations must be comparable to the costs of controls set
under section 407(b)(1) for achieving reductions from Group 1 boilers.
According to these commenters, the only way to determine and to compare
costs for achieving reductions is to use a measure of cost-
effectiveness. Commenters also state that the legislative history also
clearly indicates that ``cost-effectiveness'' is the appropriate
measure of comparing costs in setting Group 2 emission limitations.
EPA notes that in appendix B of the April 13, 1995 NOX rule
(and the March 22, 1994 rule that was remanded to EPA), EPA explained
that cost-effectiveness ($/ton of NOX removed) was to be used as
the basis for determining the comparability of Group 2 boiler NOX
controls to Group 1 boiler LNBs. As stated in Appendix B:

In developing the allowable NOX emissions limitations for
Group 2 boilers pursuant to subsection (b)(2) of section 407 of the
Act, the Administrator will consider only those systems of
continuous emission reduction that, when applied on a retrofit
basis, are comparable in cost to the average cost in constant
dollars of low NOX burner technology applied to Group 1, Phase
I boilers, as determined in section 3 below. 60 FR 18776 (1995); see
also 59 FR 13578 (1994).

Section 3 of Appendix B is titled ``Average Cost-Effectiveness for
Low NOX Burner Technology Applied to Group 1, Phase I Boilers,''
and the only cost-calculation methodology presented in the appendix is
one for calculating the average cost-effectiveness of LNBs. Both
annualized capital costs and annual operating and maintenance costs are
to be reflected in the cost-effectiveness calculations. The commenters
now opposing using cost-effectiveness as the basis for applying the
comparable-cost requirement for setting Group 2 emission limitations
did not challenge this approach in appendix B, either as part of their
appeal of the March 22, 1994 rule or with regard to the repromulgation
of the appendix (with minor changes) as part of the April 13, 1995
rule. It is difficult to see how these commenters can now argue that
the language of section 407(b)(2) ``clearly'' bars the use of cost-
effectiveness. Moreover, inconsistent with their claim that EPA must
compare ``cost'' not ``cost-effectiveness,'' some of these commenters
also argue EPA must follow, and cannot legally change in this
rulemaking, the appendix B procedures,

[[Page 67138]]

which are grounded on the comparison of cost-effectiveness. (See, for
example, docket item IV-D-65, p. 80-95.)
Response: The Agency continues to believe that the statutory terms,
``comparable'' and ``cost'' are ambiguous, and maintains that its
interpretation of ``comparable'' as ``similar but not necessarily
equal'' and its decision to compare cost-effectiveness are consistent
with a reasonable interpretation of the statutory language and the
legislative history. Therefore, the final rule uses a cost
comparability test similar to that in the proposed rule. However, in
response to commenters' concerns, EPA has modified its specific
criteria for determining whether control systems have comparable cost-
effectiveness. In the proposed rule, EPA considered a control option
for Group 2 boiler type to be ``comparable'' in cost-effectiveness to
LNBs on Group 1 boilers if: the cost-effectiveness range for the Group
2 control option fell within the range (excluding outliers) for Group 1
LNBs; and the median cost-effectiveness value for the Group 2 control
option was within 50% of that for the Group 1 LNBs. As discussed below,
in the final rule EPA considers Group 2 control options to be
``comparable'' if the median cost-effectiveness of the Group 2 control
option used to meet the Group 2 emission limitation: (1) Does not
exceed by more than one-third the median overall cost-effectiveness of
Group 1 controls used to meet the Group 1 emission limitations; and (2)
does not exceed the median cost-effectiveness of Group 1 controls for
either of the two types of Group 1 boilers, i.e., dry bottom wall-fired
boilers and tangentially fired boilers regulated pursuant to section
407(b)(1). Additionally, the 90th percentile cost-effectiveness value
of the Group 2 control option should not exceed the 90th percentile
value cost-effectiveness value of Group 1 LNBs.
EPA believes that the approach used in the analysis to support the
final rule is a reasonable interpretation of the term ``comparable'' in
the context of section 407(b)(2). Where sets of values are being
compared, EPA maintains that it is logical to consider the
distributions, not just the medians, of the sets of values. Comparisons
based solely on measures of central tendency (e.g., medians) neglect
important information (e.g., about the range and shape of the
distributions) that is relevant to determining whether the sets of
values are comparable. EPA notes, with regard to the cost-effectiveness
of NOX controls under section 407(b)(1), that: the costs reported
by utilities for LNB applications to Group 1 boilers ranged from $37 to
$2,625 per ton of NOX removed; the median cost-effectiveness of
Group 1 boilers as a whole is $413 per ton of NOX removed; and the
medians of cost-effectiveness of LNBs applied to dry bottom wall-fired
boilers and tangentially fired boilers (which boiler types each make up
about 50% of the Group 1 boiler population) are $270 and $611 per ton
of NOX removed, respectively. Particularly given this wide
disparity in the cost-effectiveness of Group 1 boiler controls, EPA
considers the above criteria used in the final rule to be a reasonable
interpretation of the meaning of ``comparable'' in the context of
evaluating the cost-effectiveness of various Group 2 NOX control
methods.
This approach is consistent not only with the meaning of the
statutory term, ``comparable,'' but also with the legislative history
of section 407(b)(2). The Conference Report for the bill that became
the Clean Air Act Amendments of 1990 did not itself address the meaning
of ``comparable'' but the report explicitly ``incorporated'' a portion
of the December 20, 1989 Senate committee report for an earlier version
of that bill, which discussed comparability. The Conference Report
explained :

Section 407(b)(2) is intended to incorporate a portion of the
Senate Environment and Public Works Committee Report of December 20,
1989, S. Report 101-228, that the NOX emission control
technology requirements for cyclone boilers, roof-fired boilers,
wet-bottom boilers, stoker boilers and cell burners are to reflect
the relative difficulty of controlling NOX emissions from these
boilers. Emission limitations that are promulgated under section
407(b)(2) are to be based on methods that are available for reducing
emissions from such boilers that are as cost-effective as the
application of low nitrogen oxide burner technology to dry bottom
wall-fired and tangentially-fired boilers. House Rep. No. 101-952,
101st Cong., 2d Sess. at 344 (October 26, 1990), A Legislative
History of the Clean Air Act Amendments, 103d Congress, 1st Sess. at
1794 (November 1993).

The relevant portion of the Senate report discussed the difficulty
and cost-effectiveness of reducing NOX emissions from cyclone, wet
bottom, and stoker boilers, explaining that the Senate bill was
intended:

to compel utilities to do no more than make most cost-effective
reductions. While in past years the Committee has reported
legislation that differentiated, and eased, the requirements imposed
on cyclone boilers, here the provisions also differentiates (sic),
and eases (sic), requirements for wet bottom and stoker boilers as
well. This reflects the relative difficulty of controlling NOX
for these technologies.
* * * Also favoring the cost-effectiveness of this section is
the development of new, lower-expense technologies. Sorbent
injection and decreasing costs for selective catalytic reduction
(SCR) may lower the expense of initial NOX reductions even
further. For example SCR has long been viewed as prohibitively
expensive, but recent dramatic declines in cost have brought the
per-ton-removed price of this technology down to as low as $600,
according to recent Electric Power Research Institute methodology
followed by EPA. This is comparable to the cost of conventional
control methods like low-NOX burners and thermal de-NOX.
However, the provisions in this section are not intended to mandate
use of SCR or any other specific technology. Senate Rep. No. 101-
228, 101st Cong., 1st Sess. at 332-33 (December 20, 1989) (emphasis
added) , A Legislative History at 8672-73.

Some commenters noted that the Senate report accompanied an earlier
version of the bill amending the Clean Air Act Amendments and that
version of the bill did not include the ``comparable cost'' language in
section 407(b)(2). However, because the Conference Report expressly
incorporated the Senate report, which is the only legislative history
concerning the term ``comparable'', EPA maintains that the Senate
report is relevant. The legislative history also indicates that, at the
time, the cost of LNBs was estimated to be about $150 to $200 per ton
of NOX removed. Id. at 8810. The fact that a cost-effectiveness
value for SCR that was, at $600/ton, 300-400% greater than the cost of
LNBs was expressly considered to be ``comparable'' to LNB costs,
supports the conclusion that the criteria used in the comparability
analysis in today's final rule is a reasonable approach to implementing
section 407(b)(2).
The Agency also disagrees with those commenters that argued that
``cost'', rather than ``cost-effectiveness,'' is the appropriate
measure of cost under section 407(b)(2). The language of section
407(b)(2) is ambiguous on this point, and EPA maintains that
interpreting that section to require that costs be measured in terms of
cost-effectiveness is reasonable and consistent with the legislative
history.
Section 407(b)(2) states:

The Administrator shall base (Group 2 emission) rates on a
degree of emission reduction achievable through the retrofit
application of the best system of continuous emission reduction,
taking into account available technology, costs and energy and
environmental impacts; and which is comparable to the costs of
nitrogen oxide controls set pursuant to (section 407)(b)(1). 42
U.S.C. 7651f(b)(2) (emphasis added).

The meaning of the crucial phrase on cost-comparability (i.e., the
phrase,

[[Page 67139]]

``which is comparable to the costs of nitrogen oxide controls'') is
vague because there are two plausible antecedents in section 407(b)(2)
for the pronoun, ``which'': (1) The ``degree of reduction'' (i.e., the
level of removal of NOX); or (2) the ``retrofit application of the
best system of continuous emission reduction'' (i.e., the Group 2
control method). EPA maintains that the use of the conjunction,
``and'', at the beginning of the phrase suggests that the cost-
comparability phrase modifies the ``degree of reduction''. If the
phrase instead modifies the ``best system of continuous emission
reduction'', the statute could have been written, without the
conjunction, to read: ``the retrofit application of the best system of
continuous emission reduction, taking into account available
technology, costs and energy and environmental impacts'', which is
``comparable * * *'' (id.). However, because of the general grammatical
awkwardness of the entire sentence, EPA does not consider this analysis
to be dispositive .
The conclusion that the meaning of ``cost'' is ambiguous is
supported by the fact discussed above, that various commenters argued
that the ``plain meaning'' of section 407(b)(2) supports two mutually
inconsistent interpretations of the cost-comparability provision. On
one hand, some commenters argued that the ``plain meaning'' of the
provision is that the cost in mills/kwh of Group 2 control methods must
be comparable to the mills/kwh cost of Group 1 control methods, i.e,
that the cost-comparability phrase modifies ``best system of continuous
control reduction'' (see docket item IV-D-65, p. 75, note 172) ^{17.
On the other hand, some other commenters argued that the cost-
comparability phrase clearly modifies ``degree of reduction'' and that
the only way to compare the costs of reductions is by analyzing cost-
effectiveness, i.e., $/ton of NOX removed. (See docket item IV-D-
63, p. 15-16). In supporting their interpretation, these latter
commenters make the plausible claim that the words ``nitrogen oxide
controls set (pursuant to [section 407)(b)(1)'' refers to the NOX
emission limitations established under section 407(b)(1), rather than
to Group 1 NOX control methods (i.e. LNBs applied to Group 1
boilers). These commenters argue that it is the emission limitations,
not the control methods, that are set under section 407(b)(1). See
National Mining Association v. EPA, 59 F3d 1351, 1362 (D.C. Cir. 1995)
(holding that the word ``controls'' refers to ``governmental
regulations''); see also 42 U.S.C. 7511b(e)(1)(A) (section 183(e)(1)(A)
of the Act, which defines ``best available controls'' as the ``degree
of emissions reduction'' that the Administrator determines meets
certain requirements) and compare 42 U.S.C. 7511b(b)(3) and (4)
(referring to ``best available control measures'').
---------------------------------------------------------------------------

\17\ EPA notes that these same commenters support the Appendix B
methodology, which establishes cost-effectiveness as the basis for
comparing Group 1 LNBs to Group 2 NOX control systems.
---------------------------------------------------------------------------

However, this latter claim is not essential because, even if
NOX ``controls'' set under section 407 (b)(1) refers to LNBs
applied to Group 1 boilers, the cost-effectiveness interpretation of
the provision is still reasonable. The only way to determine if the
``degree of reduction'' achieved with a prospective Group 2 NOX
control method is comparable to the costs of LNBs applied to Group 1
boilers is to take into account both the level and the dollar cost of
achieving NOX reductions and, therefore, analyze the cost-
effectiveness of Group 1 and Group 2 control methods. If Group 1 and
Group 2 control methods were compared only on the basis of capital
costs (dollars per kilowatt) or total annualized costs (mills per
kilowatt hour), then the ``degree of reduction'' achieved with the
NOX control methods would be ignored. Under that approach, if
taken to its logical extreme, section 407(b)(2) could then be
interpreted to allow EPA to set emission limits based on specific
control systems with little or no regard for the NOX removal
capabilities of the control systems.
In short, the fact that section 407(b)(2) requires ``cost'' to be
comparable is not dispositive. Based on the context in which the term
is used, ``cost'' can reasonably be interpreted to refer to cost-
effectiveness. See, e.g., API v. EPA, 660 F2d.954, 962-64 (4th Cir.
1981) (interpreting statutory language in 33 U.S.C. 1314(b)(4)(B)
requiring consideration of the ``cost and level of reduction'' of
pollutants to require EPA to set standards based on comparisons of
cost-effectiveness).
Having concluded that the language on cost-comparability in section
407(b)(2) is ambiguous, EPA considered the legislative history. The
legislative history is consistent with the use of cost-effectiveness as
the measure of cost in determining cost-comparability. As discussed
above, the Conference Report for the Clean Air Act Amendments of 1990
explained that the Group 2 emission limitations are

to be based on methods that are available for reducing emissions
from such boilers that are as cost-effective as the application of
low nitrogen oxide burner technology to dry bottom wall-fired and
tangentially-fired boilers. House Rep. No. 101-952 at 344 (emphasis
added).

Further, the relevant portion of the Senate report, which is referenced
in the Conference Report, specifically discussed ``the decreasing costs
for selective catalytic reduction'', one method of NOX reduction,
stating:

Sorbent injection and decreasing costs for selective catalytic
reduction (SCR) may lower the expense of initial NOX reductions
even further. For example SCR has long been viewed as prohibitively
expensive, but recent dramatic declines in cost have brought the
per-ton-removed price of this technology down to as low as $600,
according to recent Electric Power Research Institute methodology
followed by EPA. This is comparable to the cost of conventional
control methods like low-NOX burners and thermal de-NOX.
Senate Rep. No. 101-228 at 332-33 (emphasis added).

In short, both the Conference Report, and the Senate committee report
that it incorporated, expressly state that ``cost comparability'' was
viewed in terms of costs per ton of NOX removed. Indeed, in
virtually every discussion in the legislative history (including those
instances cited by commenters) concerning the cost of NOX control
methods, the data on the cost of any specific control method--whether
LNBs, SCR, or any other method--was presented solely in terms of dollar
cost per ton of NOX removed ^{18. See, e.g., Senate Rep. No.
101-228 at 332-33 and 470; A Legislative History at 2546-7 (House floor
debate, submissions by Congressman Waxman); Senate Rep. No. 1894, 100th
Cong., 1st Sess. at 74, (November 20, 1982); A Legislative History at
9512 (report on predecessor legislation).
---------------------------------------------------------------------------

\18\ It appears that the only exception, where dollars rather
than dollars per ton of NOX removed were discussed, was a
reference to the total dollar cost of all NOX control methods.
A Legislative History at 977, 989.
---------------------------------------------------------------------------

The Agency notes that, when legislative history is considered, the
Conference Report and the Senate committee report are entitled to
greater weight than floor statements of individual legislators. EPA
examined the floor statements addressing section 407(b)(2) and earlier
versions of the section and finds that these statements either support
the Agency's use of cost effectiveness under the cost comparability
test or are, at most, ambiguous on this point.
For example, in the Senate debate on the Conference Report, Senator
Burdick (chairman of the Senate Committee on Environment and Public
Works) stated that

Cyclone and wet-bottom boilers may be required to reduce
nitrogen oxide emissions

[[Page 67140]]

only if the costs of such reductions are as cost-effective as
reductions from installation of low NOX burners on other types
of boilers. . . This provision is carefully worded to make cost
considerations the determinative factor in consideration of NOX
reductions from cyclone and wet-bottom boilers. A Legislative
History of the Clean Air Act Amendments of 1990 at 778 (emphasis
added).

In the same debate, Senator Baucus, subcommittee chairman and floor
manager for the Act, entered a statement into the record explaining
that

These (section 407(b)(2)) emissions limits must be based on
available technology, costs and energy and environmental impacts for
the best system of continuous emission reduction and must be
comparable in cost to the limits set for the Phase I units. Id. at
1039 (emphasis added).

In both of these statements the Senators indicated that what is being
compared is the cost of Group 2 reductions or emission limits (i.e.
cost-effectiveness of Group 2 NOX control methods) with the cost
of Group 1 reductions or emission limits (i.e. the cost-effectiveness
of LNBs used to meet the Group 1 limits).
Other floor statements are more ambiguous, referring both to
``costs'' of control methods and to ``cost-effective'' control methods.
For example, an earlier statement by Senator Baucus explained that if
the ``costs of SCR were to remain in excess of'' LNB technology, SCR
would not be ``required for cyclones'', but he also noted that ``we do
not know what the most effective controls will be at the end of the
century.'' A Legislative History at 7137. See also id. at 6168 (another
statement by Senator Baucus). Senator Lott, who introduced the bill
amendment that became section 407, stated that under the amendment,
``utilities will not be forced to install unreasonably expensive
equipment'' and NOX emission limits will be based on ``the
application of low NOX burner technology, a much more reasonable
and cost-effective method proven to successfully achieve significant
NOX reductions''. Id. at 6168. Senator Lott added that the
amendment allows flexibility to comply ``in the most cost-effective
manner''. Id. Similarly, Senator Chafee asserted that the provisions
that became section 407 would not force the installation of
``unreasonably expensive equipment'' and added that ``more reasonable
and cost-effective methods have proven to be successful in achieving
significant NOX reductions.'' Id. See also id. at 7181 (statement
of Senator Bumpers that Senate bill allows ``utilities the freedom to
choose the most cost-effective strategies to control'' SO2 and
NOX).
Finally, the Agency notes that some commenters argued that section
407(b)(2) must require measurements of ``cost'' rather than cost
effectiveness because the House version of the section 407 NOX
provisions expressly used the term ``cost effective'', which term was
not included in the final bill. House Bill 3030, passed May 23, 1990,
required the Administrator to set NOX emission limitations to
achieve in 2000 2.5 million tons of reductions below the 1989 projected
emissions and authorized adjustment of the limitations to increase
total reductions to up to 4.0 million tons if the reductions are, inter
alia, ``cost effective.'' A Legislative History at 2275-76. The
adjustment could apply to cyclone or wet-bottom boilers if the emission
reduction methods for such boilers were found to be ``as cost
effective'' as the application of low NOX burners to wall-fired or
tangentially-fired boilers. Id. at 2277. The Agency does not consider
this difference in language between the House bill and the final bill
persuasive in interpreting the cost-comparability requirement of
section 407(b)(2). As discussed above, the context in which the term
``cost'' is used in the final version of section 407(b)(2) is
reasonably interpreted to require the comparison of the cost
effectiveness of Group 1 and prospective Group 2 control methods.
In summary, EPA believes that the interpretation in the proposed
rule for the meaning of ``comparable'' and ``cost'' is reasonable and
consistent with both the language of the statute and the legislative
history. EPA therefore applies, in today's final rule, the cost-
comparability requirement of section 407(b)(2) by comparing the cost-
effectiveness (in $/ton of NOX removed) of Group 2 control
technologies and Group 1 LNB installations, which is the only measure
that incorporates both total cost and NOX reduction performance.
The next section discusses EPA's methodology for determining what Group
2 boiler NOX controls are ``comparable'' in cost-effectiveness to
Group 1 LNBs.
EPA notes that in addition to the cost-comparability requirement,
section 407(b)(2) requires that, in setting Group 2 emission
limitations, the Administrator ``tak[e] into account available
technology, costs and energy and environmental impacts.'' 42 U.S.C.
7651f (b)(2). While consideration of these factors is mandated,
Congress did not specify--and thus left to the Administrator's
interpretation--how to apply and balance these factors. In particular,
the Administrator must decide how to evaluate the factors and what
relative weight to give each factor. While the Administrator's
determination of cost-comparability is based on cost-effectiveness, the
Administrator did not ignore cost as measured in mills per kilowatt-
hour of generation. In giving meaning to the requirement to take
``account of . . . costs and energy. . . impacts'' (42 U.S.C.
7651f(b)(2)), EPA considered the impact of mills/kWh-of-generation
costs of Group 2 NOX emission limitations on electricity
consumers.
2. Cost Comparison Methodology
EPA must develop data on the costs for LNB retrofits of the Group 1
boiler categories (i.e., dry bottom wall-fired and tangentially fired
boilers) so that a comparability of retrofit costs between LNBs and
NOX controls for Group 2 boiler categories can be established. The
procedures originally to be used in developing these LNB costs were
outlined in Appendix B of the Phase I NOX rule. Appendix B also
required that the comparability of retrofit costs between LNBs and
NOX controls for Group 2 boilers be established on the basis of
cost-effectiveness of NOX control technology expressed in $/ton of
NOX removed. For the LNB retrofits in Phase I, appendix B
procedures called for developing curves depicting capital cost as a
function of boiler size, computing an average capital cost,
characterizing operation and maintenance costs, and computing an
average cost effectiveness in $/ton of NOX removed based solely on
the population that reported LNB costs to EPA.
In support of the proposed rule, EPA prepared a report (see docket
item IV-A-1) that compiled available cost and performance data from the
Phase I LNB retrofits, developed curves to explain the dependence of
capital cost of these retrofits on boiler capacity, and developed
annualized costs for these retrofits. EPA then applied these costs to
the whole Group 1 boiler population, developed a distribution of Group
1 cost-effectiveness values, and compared that distribution to the
distribution of NOX control cost-effectiveness for each Group 2
boiler/NOX control combination. The distribution of NOX
control cost-effectiveness for each Group 2 boiler/NOX control
combination was developed in a similar way to the Group 1 cost-
effectiveness distribution. In the proposed rule, EPA considered Group
2 controls comparable if (1) the upper-end of their cost-effectiveness
range (in $/ton removed) was within the upper-end of the of cost-
effectiveness range of Group 1 boilers with LNBs; and (2) their median
cost-

[[Page 67141]]

effectiveness value was within 50% of the median cost-effectiveness
value for Group 1 boilers with LNBs. The methodology used by EPA has
been criticized by commenters because it deviates from the appendix B
procedures, which imply a comparison of averages rather than
distributions.
Comments/Analyses: Some commenters believed that EPA's approach of
comparing distributions is contrary to appendix B and allows for very
wide ranges in cost due to boiler-specific influences such as
utilization and uncontrolled NOX emissions. These commenters
believed that the comparison should be made using ``typical'' values
for utilization and uncontrolled NOX emissions and deriving a
single number for the cost-effectiveness of Group 1 LNBs and each Group
2 boiler/NOX control combination. The commenters, however, did not
provide any insight as to how the cost-effectiveness values will be
compared under this alternative approach, stating only that in order
for the costs to be comparable they must be equal.
Some commenters believed that EPA's attempt to modify the Appendix
B cost comparison methodology is illegal because EPA has failed to meet
the legal requirement to justify abandoning it. They also stated that
the appendix B analysis is valid (and should be used) because it
produces results consistent with earlier estimates of LNB costs.
However, EPA notes that these commenters have not supplied information
addressing the accuracy of appendix B.
Numerous comments supporting EPA's departure from the appendix B
approach have also been received. These comments stated that EPA's
improvement of its cost-comparison methodology is legal and justified.
Response: Although appendix B implies that the cost-effectiveness
comparisons of Group 2 boiler/NOX control technology combinations
to Group 1 LNBs will be done by single point comparisons, it does not
provide a precise methodology for how these comparisons will be
conducted. In addition, commenters supporting the appendix B approach
provided no insight into how they believe the comparisons should be
conducted. Thus, EPA's proposed methodology is the only methodology
presented to date that explains how to determine whether Group 2
boiler/NOX control technology combinations are ``comparable'' to
Group 1 boilers with LNBs. However, in light of the negative comments
received, EPA has decided to re-evaluate its cost-effectiveness
comparison methodology.
Some commenters argued that EPA's departure from the appendix B
procedures was illegal and resulted in erroneous conclusions and an
overstatement of wall-fired and tangentially fired LNB retrofit costs
experienced by the utilities. In order to respond to these comments, it
is necessary to review the methodology used by EPA in estimating LNB
costs, show the extent to which this methodology adheres to appendix B
procedures, and examine the appropriateness of the digressions from
appendix B taken in EPA's methodology.

i. Appendix B Methodology

To follow the procedures specified in appendix B, EPA compiled a
database of Phase I LNB retrofit costs and NOX reductions reported
by the utilities. (Hereafter this database will be referred to as the
``cost database.'') EPA compiled cost and performance data on 56 Phase
I boilers including 35 wall-fired boilers and 21 tangentially fired
boilers. These data include boiler-specific details on capital and O&M
costs and actual or projected annual NOX reductions. This database
can be found in docket item IV-A-1.
Appendix B required that, using the capital costs in the cost
database, capital cost curves or equations be developed for dry bottom
wall-fired and tangentially fired boilers. It further required using
these curves or equations to develop a weighted average capital cost
for the Phase I dry bottom wall-fired and tangentially fired LNB
retrofits, with the weighting factor being the unit gross nameplate
capacity (in MW) as reported in the NADB.
Following the appendix B requirements, EPA developed capital cost
equations. It should be noted that the importance of the derived
capital cost equations is that they represent characteristic values of
and trends in capital cost that can be anticipated from retrofits of
each boiler firing type. The capital cost equations can be applied to
the much larger population of wall-fired and tangentially fired boilers
to arrive at characteristic capital costs of retrofits for the entire
population of Group 1 boilers because: (1) The regressions used are
good representations of the averages of reported costs (see docket item
IV-A-1); and (2) the ranges in the capacities of boilers currently in
the cost database (75 to 816 MW for wall-fired and 100 to 936 MW for
tangentially fired) are a good representation of the ranges in boiler
capacities found in the much larger Group 1 boiler population (30 to
900 MW for wall-fired and 50 to 1000 MW for tangentially fired).
To compute the appendix B average capital cost for wall-fired and
tangentially fired LNB retrofits in the cost database, EPA used all of
the data from the cost database. This computation yields an appendix B
average capital cost of $19.75/kW (in 1990 $s).
EPA notes that the population ratio of wall-fired boilers to
tangentially fired boilers in the current cost database is
approximately 63/37 percent on a unit basis, whereas the ratio for the
entire Group 1 boiler population ratio is approximately 50/50. In fact,
tangentially fired boilers in the entire Group 1 population have a
combined generating capacity greater than that of wall-fired boilers.
Since the average capital cost calculated by the appendix B method is
very much dependent on the boilers represented in the database,
strictly following appendix B to calculate an average $/kW from the
existing cost database would result in the cost of LNB retrofits being
biased toward those on wall fired boilers. Thus, the resulting
``average'' cost would not be consistent with the intent of the
appendix B requirement to calculate a ton of NOX reduced-weighted
average representative of Group 1 as a whole.
Following the capital cost determination, the procedures described
in appendix B require the development of an average cost-effectiveness
by annualizing the capital cost using a constant-dollar capital
recovery factor (e.g., 0.115 for a 20 year economic life), adding the
annualized capital cost to the annual operation and maintenance (O&M)
costs for each retrofit, summing the annualized costs for all
retrofits, and dividing this sum by the total tonnage of NOX
estimated to be removed each year following the retrofits.
As suggested by appendix B procedures, EPA used a standard
annualization factor of 0.115, based on a remaining useful life of 20
years, and an interest rate of 7 percent on borrowed money. These
standard assumptions have been used by the Electric Power Research
Institute (EPRI) and EPA in developing cost estimates for the utility
industry.
The other element of annualized capital, O&M, is a site-specific
cost often dictated by the pre-retrofit operating conditions of the
boiler, the type of coal used, and the degree of equipment improvements
or upgrades necessary to retrofit the LNBs. In fact, utilities that
submitted cost data for inclusion in the cost database reported O&M
costs ranging from -10 to 59 percent of annualized capital cost for
wall-fired boilers and from 0 to 114 percent of the annualized capital
cost for tangentially

[[Page 67142]]

fired boilers. A negative O & M number denotes lower O & M costs after
the LNB retrofit. The average O&M costs are 13.5 percent of the
annualized capital cost for wall-fired boilers and 23.3 percent of the
annualized capital cost for tangentially fired boilers ^{19.
---------------------------------------------------------------------------

\19\ Though not used in the appendix B methodology, average O&M
costs are used in EPA's final cost comparison methodology.
---------------------------------------------------------------------------

From the information in the cost database, CEM-measured post-
retrofit NOX emissions, and the above assumptions, EPA calculated
cost-effectiveness values for each of the boilers in the cost database.
Tables 9 and 10 present boiler-by-boiler results.

Table 9.--Calculated Cost-Effectiveness for Wall-Fired Boilers in Cost
Database
------------------------------------------------------------------------
Reported Calculated
capital cost
Plant ID cost ($/ effectiveness
kW) ($/ton)
------------------------------------------------------------------------
COLBERT 1.................................... 25.5 251
COLBERT 2.................................... 23.1 347
COLBERT 3.................................... 25.6 280
COLBERT 4.................................... 20.3 163
COLBERT 5.................................... 11 141
COLEMAN 1.................................... 9.32 37
COLEMAN 2.................................... 9.59 41
COOPER 1..................................... 44.05 237
COOPER 2..................................... 23.21 149
GASTON 1..................................... 4.74 61
GASTON 2..................................... 6.77 108
GASTON 3..................................... 6.55 121
GASTON 4..................................... 6.26 100
BROWN 1...................................... 18.65 309
RATTS 1 (*).................................. 12.84 110
RATTS 2...................................... 13.16 101
JOHNSONVILLE 7............................... 25.8 178
JOHNSONVILLE 8............................... 29.3 222
JOHNSONVILLE 9............................... 27.9 169
JOHNSONVILLE 10.............................. 24.8 159
MITCHELL 1................................... 12.86 163
PULLIAM 7.................................... 18.54 161
PULLIAM 8.................................... 10.84 155
QUINDARO 2................................... 11.31 250
SHAWVILLE 1.................................. 36.05 363
SHAWVILLE 2.................................. 44.03 382
SITE C....................................... 19.76 149
SITE D-1 (*)................................. 20.72 87
SITE D-2 (*)................................. 18.58 77
SITE D-3..................................... 15.66 65
SITE D-4..................................... 15.44 74
GREEN RIVER 5................................ 15.93 160
WATSON 4..................................... 27.89 263
WATSON 5..................................... 35.05 248
------------------------------------------------------------------------

Table 10.--Calculated Cost-Effectiveness for Tangentially Fired Boilers
in Cost Database
------------------------------------------------------------------------
Reported Calculated
capital cost
Plant ID cost ($/ effectiveness
kW) ($/ton)
------------------------------------------------------------------------
CONEMAUGH 1 (*).............................. 18.08 1007
CONEMAUGH 2 (*).............................. 17.23 874
BROWN 2...................................... 13.65 533
MCDONOUGH 1.................................. 54.24 1423
MCDONOUGH 2.................................. 34.58 1310
SHAWVILLE 3 (*).............................. 53.91 2436
SHAWVILLE 4 (*).............................. 52.24 2625
YATES 4...................................... 16.54 1622
YATES 5...................................... 16.54 1391
SITE A-1..................................... \20\ 28.69
417
SITE A-2..................................... \20\ 28.51 422
SITE A-3..................................... \20\ 33.53 500
SITE A-4..................................... \20\ 29.56 429
SITE A-5..................................... \20\ 28.60 408
SITE A-6..................................... \20\ 29.10 423
SITE B-1..................................... 16.69 489
SITE B-2..................................... 14.73 391
ALLEN 1...................................... 8.9 345
ALLEN 3...................................... 8.8 312
RIVERBEND 7.................................. 10.40 762
RIVERBEND 8.................................. 7.78 548
------------------------------------------------------------------------
\20\ Capital costs have been adjusted to exclude costs associated with
major waterwall modifications (see docket item IV-A-9).

Consistent with appendix B, EPA did not consider boilers in Tables
9 and 10 that were not achieving the statutory emission rates (i.e.,
the boilers marked with (*) in the tables) when determining average
cost effectiveness. EPA converted the figures in the tables from 1995
$/ton of NOX removed to 1990 $/ton of NOX removed using a
cost scaling factor of 0.963. Further, according to appendix B, instead
of averaging the individual $/ton to determine an average cost-
effectiveness for the population (i.e., Average $/ton = (($/ton21
+ ($/ton)2 + . . . + ($/ton)n)/n), the average cost-
effectiveness is determined on a ton-weighted basis, by adding all the
dollars and dividing by all the tons (i.e., Average $/ton = ($1 +
$22 + . . . + $n)/(ton1 + ton2 + . . . +
ton1)). This process yields an appendix B cost-effectiveness of
$282/ton of NOX removed, in 1990 dollars, for the combined wall-
fired and tangentially fired LNB retrofits in the cost database. The
ranges of cost-effectiveness for the populations of all wall-fired, all
tangentially fired boilers as well as the ton weighted average for each
boiler type, are shown in Table 11 below.

Table 11.--Distribution of Cost Effectiveness for the LNB Retrofits
(1990 Dollars)
------------------------------------------------------------------------
Average High ($/ Low ($/
Population ($/ton) ton) ton)
------------------------------------------------------------------------
All wall-fired............................ 161 382 37
All tangentially fired.................... 631 2625 312
All boilers............................... 282 2625 37
------------------------------------------------------------------------

As shown in the above table, the range in cost-effectiveness for
the population of LNB retrofits that reported cost information to EPA
is a very wide one which was not anticipated when appendix B was
developed or before appendix B was promulgated on April 13, 1995. EPA
does not believe that describing this wide distribution by a single
number would be appropriate. Doing so, for example, significantly
understates the $/ton cost-effectiveness for more than half of the
Group 1 population (i.e., the tangentially fired boilers). As
illustrated by Tables 8 and 9, the appendix B average of $282/ton does
not represent the average cost-effectiveness of controlling Group 1
boilers. The appendix B average is about 50% more than the average for
dry bottom wall-fired boilers but almost 60% less than the average for
tangentially fired boilers, which account for over half of existing
Group 1 capacity.
In fact, the 282 $/ton value determined by appendix B fails to
capture any of the reported costs from tangentially fired boilers and
falls far short of the average cost-effectiveness of the tangentially
fired boiler population, which accounts for over half of the existing
Group 1 capacity. This illustrates that the single number approach of
appendix B would be inadequate in characterizing the wide distribution
of cost-effectiveness of LNB retrofits. A more appropriate Group 1
average cost-effectiveness value is an average derived from the
averages of each boiler type in Group 1 weighted by their overall
capacities. This approach weighs the $161/ton and $631/ton averages for
the wall-fired and tangentially fired boilers by their respective
collective capacities in the U.S., resulting in a more representative
average Group 1 cost-effectiveness value.
The average cost-effectiveness value, calculated by weighing the
boiler type averages by their capacities, is $412/ton and is higher
than the median cost-effectiveness determined using EPA's methodology
in the proposed rule ($403/ton). The commenters urging EPA to follow
the appendix B methodology

[[Page 67143]]

anticipated that this methodology will yield a lower average cost-
effectiveness value (about $200/ton) than EPA's proposed $403/ton. From
the above information, their estimate is clearly much lower than the
average cost-effectiveness values reported to EPA by utilities. To
facilitate comparison, Group 2 boiler NOX control costs were also
developed following the appendix B procedures. Table 12 shows the
results of applying the modified appendix B cost-effectiveness
calculation methodology to the various boiler and NOX control
technology types.

Table 12.--Modified Appendix B Average Cost-Effectiveness of NOX
Controls
[$/Ton NOX Removed]
------------------------------------------------------------------------
Average cost-
Boiler/NOX control technology effectiveness
($/ton)
------------------------------------------------------------------------
Wall-fired boilers/LNB.................................. 161
Tangentially fired boilers/LNB.......................... 631
Group 1 boilers/LNB..................................... 412
Cell burners/plug-ins................................... 77
Cell burners/non plug-ins............................... 98
Cyclones/gas reburning.................................. 480
Cyclones/SCR............................................ 544
Cyclones/SNCR........................................... 614
Wet bottoms/gas reburning............................... 512
Wet bottoms/SCR......................................... 512
Wet bottoms/SNCR........................................ 437
Verticals/combustion controls........................... 136
Verticals/SNCR.......................................... 800
------------------------------------------------------------------------

As can be seen from the above table, with the exception of
vertically fired boilers applying SNCR, all the average Group 2 boiler
cost-effectiveness values are lower than the average tangentially fired
boiler cost-effectiveness value. Further, the average cost-
effectiveness of each Group 2 boiler/NOX control technology
combination, except SNCR applied to vertically fired and cyclone
boilers, is no more than one-third greater than the average cost-
effectiveness of all the Group 1 LNB retrofits reported to EPA and is
less than the average cost-effectiveness of the tangentially fired LNB
retrofits. Therefore, with the exception of SNCR applied to vertically
fired and cyclone boilers, all Group 2 boiler/NOX control
technology combinations would be considered comparable in cost-
effectiveness to Group 1 LNBs, using the modified appendix B approach.
Since the average cost-effectiveness of SNCR applied to vertically
fired and cyclone boilers exceeds the average cost-effectiveness of
Group 1 LNBs by 80 percent and 39 percent, respectively, these Group 2
boiler/NOX control technology combinations would not be considered
comparable in cost-effectiveness to Group 1 LNBs using the modified
appendix B approach.

ii. EPA's Comparison Methodology

Although the modified appendix B approach is presented above, EPA
maintains that the methodology used in the proposal, modified in
today's final rule, is the better approach. EPA is therefore relying on
such final methodology in setting Group 2 emission limitations and
adapting, in today's final rule, revisions to appendix B that eliminate
the inconsistencies between appendix B and the final methodology. As in
the proposal, EPA is taking the approach of removing the inconsistent
language in appendix B, rather than restating in appendix B the final
methodology described in this preamble.
EPA modified the methodology in the proposed rule due to public
comments. These modifications are: (1) Revised capital and O&M costs
and NOX reduction performance for LNBs applied to dry bottom wall-
fired and tangentially fired boilers; (2) revised capital and O&M costs
and NOX reduction performance for selective catalytic reduction
(SCR) and gas reburning applied to wet bottom boilers; (3) use of year
2000 capacity factors projected by a more sophisticated model
(Integrating Planning Model); and (4) use of short-term CEM-recorded
uncontrolled NOX rates in place of NURF emission factors and long-
term CEM-recorded NOX rates. Table 13 reflects the resulting
revisions to the cost-effectiveness values presented in the preamble of
the proposed rule.

Table 13.--Distribution of Cost-Effectiveness of NOX Controls
[$/Ton NOX Removed]
------------------------------------------------------------------------
10th 90th
Boiler/NOX control technology percentile percentile Median
------------------------------------------------------------------------
Wall-fired boilers/LNB.............. 108 1,826 270
Tangentially fired boilers/LNB...... 286 2,621 611
Group 1/LNBs........................ 142 2,315 413
Group 2/NOX controls................ 82 657 407
Cell burners/plug-ins............... 52 162 91
Cell burners/non plug-ins........... 69 179 112
Cyclones/gas reburning.............. 357 985 537
Cyclones/SCR........................ 380 1,856 516
Cyclones/SNCR....................... 487 1,193 680
Wet bottoms/SCR..................... 424 657 501
Wet bottoms/gas reburning........... 413 814 520
Wet bottoms/SNCR.................... 339 733 456
Verticals/combustion controls....... 95 650 128
Verticals/SNCR...................... 651 1,600 831
------------------------------------------------------------------------

The median cost-effectiveness values of each Group 2 boiler/
NOX control technology combination, except SNCR applied to
vertically fired and cyclone boilers, are no more than one-third
greater than the median cost-effectiveness values of LNBs applied to
the Group 1 population and are less than the median values of LNBs
applied to tangentially fired boilers. Further, the range in cost-
effectiveness observed by the Group 2 boiler/NOX control
technology combinations is within the range in cost-effectiveness of
Group 1 LNBs. Therefore, with the exception of SNCR applied to
vertically fired and cyclone boilers, all Group 2 boiler/NOX
control technology combinations are considered comparable in cost-
effectiveness to Group 1 LNBs.

iii. Conclusions

EPA continues to believe that the original appendix B procedure
provides unrepresentative and inappropriate

[[Page 67144]]

results for the reasons set forth in the proposal, including the draft
report cited therein (61 FR 1459). If appendix B is modified to compute
averages of the two types of Group 1 boilers separately, this improves
somewhat its ability to represent the wide range of cost-effectiveness
of the Group 1 boiler types. However, this modification corrects only
one of appendix B's shortcomings, and, so, even as modified, appendix B
does not provide the most technically sound procedure for determining
cost-effectiveness. In contrast, EPA's final methodology is
representative of the wide variations in actual and expected costs and
corrects the shortcomings of appendix B. EPA notes, in any event, that
applying appendix B with modifications to improve its
representativeness of the costs of wall-fired and tangentially fired
boilers results in the same conclusions as to which Group 2 NOX
control systems are comparable.
3. Retrofit Nature of Group 2 Controls
In support of the proposed rule, EPA, through a contract with an
architectural and engineering contractor (A/E), developed cost
projections for NOX control applications to Group 2 boilers.
Because these controls need to be integrated with boiler hardware and
unit layout, such applications may be lower in cost when applied to new
boilers (where boiler and controls can be optimally designed) than when
retrofitted to existing boilers (where some of the existing hardware
must be modified or removed). Certain commenters raised issues that
generically apply to the EPA's cost estimating methodology for all of
the Group 2 boiler NOX control systems. In general, the emphasis
of these comments was on whether EPA's estimates considered all of the
cost impacts associated with retrofitting these NOX controls.
Comment/Analyses: One commenter believed that the EPA's estimates
did not fully address the magnitude of work involved in the
installation of different NOX control technologies to existing
boilers. This commenter also felt that these estimates relied heavily
on the information published by commercially motivated equipment
suppliers.
EPA notes that a primary consideration in the evaluation of Group 2
boiler NOX control systems was to fully address the requirements
encountered in installing such control systems into existing plant
settings. EPA, therefore, developed estimates only where a control
technology had a full scale application in the U.S. so that EPA could
evaluate its cost estimates against actual retrofit experience. In
addition, EPA's estimates included cost items that account for the
retrofit nature of the technology applications, including:
(1) Costs accounting for the impacts of incorporating these
NOX control systems on existing plant equipment so that costs
pertaining to modifications to the existing equipment and structures
are considered, in addition to costs for new equipment and structures,
in calculating the capital costs. The report issued by EPA on the Group
2 boiler NOX control systems contains a list of major equipment,
structures, and modifications required for each technology application
(see docket item IV-A-4), referred to in this preamble as the ``Group 2
Boiler Study'').
(2) Cost allowances for dismantling and relocation of existing
equipment.
(3) Costs for construction and engineering man-hours that reflect
the increased labor necessary to perform installation work in an
existing plant environment rather than a green field plant site.
(4) Contingency allowances to cover cost increases associated with
uncertain site-specific factors. All capital costs were loaded by
factors of 15 percent for project contingency and 5 percent for process
contingency. An additional 5 percent contingency factor was applied to
cover unexpected costs associated with technologies requiring
installation of equipment that may impact the existing general
facilities.
(5) Costs for modifications to the existing plant equipment that
may be typically encountered at some plants for each technology case.
In addition to the above, the costs developed for the various
technology cases were verified against several sources of information.
Information was not only obtained from equipment suppliers on major
pieces of equipment and specialty items, but also verified with price
quotations received on most of this type of equipment on other projects
by the A/E. Costs for all bulk quantities were developed based on
recent experience by the same A/E.
Other commenters alleged that the cost of particular items
including ``scope adders'' should be included in EPA's Group 2 boiler
NOX control cost estimates. EPA has considered these comments and
concluded that, in general, the ``scope adders'' are costs that are not
expected to be incurred in typical retrofits. Instead, to the extent
costs included as ``scope adders'' are typical-retrofit costs, they are
added to EPA's costs, and, to the extent scope adder costs are not
typical-retrofit costs, they are covered by the 5 percent contingency
factor in EPA's estimates (for details, see docket item IV-A-4).
Additionally, EPA does not include ``scope adders'' in its estimates of
Group 1 LNB costs or in its estimates of Group 2 NOX control
costs. Since the ultimate purpose is to compare Group 1 boiler cost-
effectiveness to Group 2 boiler cost-effectiveness, EPA's approach
provides for a more consistent cost-effectiveness comparison between
the two boiler types. Further, by adding contingencies to the Group 2
costs while not adding contingencies to the Group 1 costs, EPA is being
conservative in its cost comparisons.
Additionally, EPA notes that all of the boiler modifications
required for the technology retrofits were included in the costs
presented in the Group 2 Boiler Study. These, for example, include
draft fan replacement and reheat system (economizer bypass) addition
for SCR systems. Further, EPA's cost estimating methodology in general
complied with the procedures listed in the EPRI Technical Assessment
Guide (TAG).
Other commenters supported EPA's cost estimates. Two of these
commenters (one of which has performed the only retrofit of an SCR to a
cyclone boiler) referred to specific retrofit cases for SCR and cell
burner combustion modifications where the costs were within the EPA's
cost range. One of the commenters indicated that initial cost estimates
for retrofit projects could be substantially higher than the actual
costs.
Response: EPA believes that the cost estimating procedures used in
the Group 2 Boiler Study adequately address the site-specific factors
expected to be encountered at various Group 2 boiler sites. Certain
sites may have special requirements, such as ``scope adders.'' However,
the contingency allowances that have been included in EPA's cost
estimates are likely to cover such situations. Additionally, as noted
previously, EPA does not include ``scope adders'' in its estimates of
Group 1 LNB costs or in its estimates of Group 2 NOX control
costs. Since the ultimate purpose is to compare Group 1 boiler cost
effectiveness to Group 2 boiler cost-effectiveness, EPA's approach
provides for a more consistent cost-effectiveness comparison between
the two boiler types.
In addition, EPA further evaluated its cost estimates to determine
the extent to which they reflect the specific requirements imposed by
the retrofit nature of the Group 2 boiler applications (as
distinguished from applications to new boilers). Table 14

[[Page 67145]]

shows the costs associated with the retrofit-specific items for various
NOX control technologies. The cost data presented in this table
represent one specific Group 2 boiler application of each technology
considered in EPA's evaluation, including combustion controls (non
plug-in burners), coal reburning, gas reburning, SCR, and SNCR.

Table 14.--Percent of Total Accounted Capital Costs Related to Retrofit Activity
----------------------------------------------------------------------------------------------------------------
Percent
of total
Total Retrofit- capital
Boiler capital specific costs
NOX technology Boiler type size, cost, capital due to
(MWe) ($/kW) ($/kW) retrofit
activity
(%)
----------------------------------------------------------------------------------------------------------------
Non plug-in burners....................... Cell burner.................. 300 18.6 6.4 34
Coal reburning............................ Cyclone...................... 400 53.7 15 28
Gas reburning............................. Cyclone...................... 400 15.5 2.4 16
SNCR...................................... Cyclone...................... 400 7.8 1.5 19
SCR....................................... Cyclone...................... 400 40.9 11.1 27
----------------------------------------------------------------------------------------------------------------

In the above table, total capital cost is the total capital
requirement (without the scope adders) for the technology retrofit at
the corresponding boiler installation, as shown in the Group 2 Boiler
Study. The major retrofit-specific capital costs include the following
items:
(1) Boiler furnace wall modifications, coal pipe modifications,
sootblower relocations, electrical and control modifications, and
relocation of existing equipment for non-plug-ins.
(2) Boiler furnace wall modifications, enclosure modifications,
coal handling system modifications, electrical and controls
modifications, and demolition of existing equipment for coal reburning.
(3) Electrical and controls modifications, boiler pressure part
modifications, and structural modifications for gas reburning and SNCR.
(4) Draft fan replacements, ductwork modifications, electrical and
controls modifications, fan modifications, and fly ash handling system
modifications for SCR.
As shown in Table 14, a significant portion of the total capital
costs developed by EPA cover retrofit requirements.
Further, it should be noted that the above retrofit-specific
capital costs include only those items that can be directly associated
with the retrofit requirements. For each of these installations, there
are other costs included in the total capital cost column in Table 14
that are retrofit-related costs but are not easily separated from non-
retrofit-related costs in total estimated costs. These costs are
incurred because the work is performed in an existing plant setting and
because of the relatively high amount of on-site equipment assembly
work required (rather than maximizing assembly in the vendor's shops).
Such costs can add significantly to the percentage of total costs that
are retrofit-specific costs, and thus the last column in Table 14
likely understates the percentage of total costs that is retrofit-
related in EPA's estimates.
In addition to addressing the comments on SCR costs, EPA has
conducted an overall analysis to compare its estimated capital costs to
actual costs incurred by retrofit applications of these technologies to
assure that EPA's overall cost estimates are valid. Through its A/E
contractor, which has extensive experience with SCR installations in
the U.S. and abroad, EPA has developed a report comparing EPA's SCR
cost estimates to actual retrofit costs (see docket item IV-A-16, SCR
model validation study). This report shows that EPA's estimates are
conservative. Actual costs presented in this report are approximately
20 percent below EPA's estimated costs.
Further support illustrating that EPA's Group 2 Boiler Study
accounted for SCR retrofit costs is presented in section III.B.4.iii of
this preamble, which addresses the costs of applying SCR to cyclone
boilers. That section presents model validation results that show EPA's
costs to be conservative when compared to the actual SCR retrofit at
Merrimack Unit 2.
Therefore, as in the proposed rule, the analysis supporting the
final rule relies on the Group 2 costs developed by the A/E, with
extensive experience on SCR installations in the U.S. and abroad, to
compare the cost-effectiveness of Group 2 boiler/NOX control
option combinations to Group 1 boiler LNBs. These Group 2 costs
adequately address various retrofit cost considerations and, if
anything, may overestimate costs in comparison to actual retrofit
projects.
4. Group 2 Boiler Size Exemption
Comments/Analyses: The Agency received several comments favoring
the proposed exemption provided for small cyclone boilers. The preamble
proposed a size threshold of 80 MW for this exemption. Several
commenters noted that the proposed rule did not include explicit
language to implement the proposed exemption. Commenters also argued
that the exemption should be higher, ranging from 100-180 MW. Certain
municipal commenters noted that they operated cyclone boilers that were
just slightly larger than the proposed 80 MW threshold. One utility
argued that EPA has not provided a rationale for selecting the 80 MW
cutoff versus a higher cutoff level for the small cyclone exemption.
The commenter noted that a review of the boiler population does not
show that this is a logical break point, and the commenter could not
see any emissions or economic feasibility distinction between units
that fall below this level and units operated in the 80-90 MW range.
Other commenters suggested a cost-cutoff as an exemption for cyclones
if the final rule includes any limit for cyclones.
Certain commenters opposed any exemption for cyclone boilers. The
commenters noted that cyclones have large NOX emissions and should
be controlled either through technology or averaging programs. Gas
industry commenters disagreed with the exemption because they disagree
with EPA's assumption that gas reburning is unavailable for cyclones
under 80 MW.
EPA notes that, as shown in EPA's list of Group 2 boilers (see
docket item IV-A-4), there are 14 cyclone boilers with a nameplate
capacity of 80 MWe or less. There are an additional 19 units that are

[[Page 67146]]

between 80 and 155 MWe, five of which are owned and operated by
municipal utilities.
Response: Pursuant to the Unfunded Mandates Act, EPA notified all
municipal utilities (and the appropriate elected officials) with units
that are potentially subject to the Phase II NOX Program. Two of
the commenters that specifically commented on the NOX exemption
were municipal utilities, one of which requested that the exemption be
expanded to include two cyclone units operated by the utility with
nameplate capacity of 90.25 MWe each. The final rule includes an
exemption for all cyclones of 155 MWe or less nameplate capacity. The
overall impact of this exemption on the emission reductions achieved by
the rule is acceptable on balance. On one hand, with the exemption, the
cyclone boiler NOX emission reductions in 2000 are approximately
40,000 tons per year (or about 13 percent) less than without the
exemption. On the other hand, the exemption ensures that the NOX
emission limitation for cyclones is applied only to that segment of the
cyclone boiler population for which NOX control systems are
comparable in cost-effectiveness to Group 1 boiler LNBs. In addition,
the exemption reduces the impact of the rule on municipal utilities
with relatively small cyclone units.
The Agency does not believe any exemption beyond this for cyclone
boilers is warranted. The Agency believes that the 155 MWe threshold is
a rational break point because it results in significant NOX
reductions for many cyclone boilers while providing protection for
reducing the impact of the Acid Rain Program on a number of municipal
utility units.
For similar reasons, EPA is adopting a 65 MWe exemption for wet
bottom boilers. Because the proposed rule treated combustion controls
as the appropriate control technology for wet bottom boilers, EPA did
not consider any exemption for wet bottom boilers necessary. As
discussed above, the final rule is based on the use of either gas
reburning or SCR for wet bottom boilers. The Agency notes that the two
smallest wet bottom boilers, both of which are under 65 MWe nameplate
capacity are both owned by municipal utilities, but the municipal
owners did not specifically comment on the proposed limit for wet
bottom boilers. However, exempting wet bottom boilers of 65 MWe or less
ensures that the NOX emission limitation for such boilers is
applied only to that segment of the wet bottom boiler population for
which NOX control systems are comparable in cost-effectiveness to
Group 1 boiler LNBs. The exemption will also reduce the impact of the
Acid Rain Program on municipal utilities. The NOX reductions in
2000 will be about 5,000 tons lower with the exemption but the
reductions from wet bottom boilers will still be significant.
Further, since this rule affects utility boilers, not generators, a
more meaningful measure of the size cutoff is steam flow at 100% load
(measured in lb/hr) instead of generator capacity (measured in MWe).
DOE's Form EIA-767, Part III (Boiler Information), Section C (Design
Parameters), Item 3 lists each boiler's Maximum Continuous Steam Flow
(in thousand pounds/hour) at 100% load. Comparing the Maximum
Continuous Steam Flow rating found in Form EIA-767, to generator
capacity found in EPA's NOX boiler database, EPA determined that:
the 155 MWe cyclone boiler cutoff can be expressed in lb/hr as 1060 lb/
hr at 100% boiler load; and the 65 MWe wet bottom boiler cutoff can be
expressed in lb/hr as 450 lb/hr at 100% boiler load. Section 76.7 of
the final rule establishes cyclone and wet bottom cutoffs based on the
Maximum Continuous Steam Flow at 100% Load of the boiler. Thus, cyclone
boilers with a Maximum Continuous Steam Flow at 100% of Load of 1060
lb/hr or less are exempt from the cyclone boiler emission limit set in
this rule. Similarly, wet bottom boilers with a Maximum Continuous
Steam Flow at 100% of Load of 450 lb/hr or less are exempt from the wet
bottom boiler emission limit set in this rule (see docket item IV-B-2,
listing cyclones and wet bottoms and their respective generator
capacities and Maximum Continuous Steam Flow at 100% Load).
5. Cyclone Boiler NOX Controls

i. Coal Reburning

In the proposed rule, EPA based the limit for cyclone boilers on
the assumption that coal reburning (in addition to SCR) was applicable
to all cyclone boilers over 80 MWe and that either coal reburning or
SCR could achieve a 50% NOX reduction efficiency.
Comment/Analyses: Several comments were received by EPA on the
feasibility of using coal reburning technology on cyclone boilers. The
majority of these comments addressed whether a coal reburning retrofit
would be feasible given the existing cyclone boiler design parameters.
Other comments were directed to the impacts of this technology on
boiler performance or on the balance-of-plant equipment. The potential
for reduced precipitator performance, furnace waterwall corrosion, and
ability to maintain flame stability at reduced loads were included as
specific concerns about the potential impacts of coal reburning.
EPA notes that the adverse impacts of coal reburning on the boiler
and balance-of-plant equipment are speculative. The corrosion potential
of coal reburning was evaluated and reported for the Nelson Dewey
demonstration. This experience does not show any appreciable corrosion
as a result of retrofitting coal reburning.
The installation at Nelson Dewey also addressed the potential
impact of coal reburning on precipitator performance. Based on long-
term experience at this installation, the ash loading at the
precipitator inlet increased significantly with no adverse impact on
the precipitator outlet emissions and opacity; in fact, there was a
slight improvement. Based on the Nelson Dewey experience, it is
reasonable to assume that higher ash loadings associated with coal
reburning should not have an adverse impact on the performance of
existing precipitators. Because of this, the EPA study shows the
precipitator upgrade as a scope adder item, which is not expected to be
required by most Group 2 boiler installations.
Further, turndown to operating loads below 50 percent was
demonstrated at Nelson Dewey. One major factor in facilitating turndown
is the number of cyclone burners provided with the boiler. For boilers
with a large number of cyclone burners, turndown capability is improved
because one or more cyclone burners can be taken off-line during low
load operation while the cyclones in service operate at closer to full
load conditions. The Nelson Dewey cyclone boiler is equipped with only
three cyclone burners, rather than the more usual 4 to 23 burners.
Since this installation demonstrated the capability to operate at loads
less than 50 percent, it appears that the larger units with more
cyclones should not experience difficulty in maintaining their pre-
retrofit operating load levels.
Commenters questioned EPA's assumption that the experience from the
only operating coal reburning installation at the 110 MW Nelson Dewey
Station could be applied directly to all candidate cyclone boilers,
especially the larger boilers. Inadequate furnace residence time was
raised as the key issue that could make this technology unsuitable for
many boilers. Some of these commenters quoted an October 1995 letter
from Babcock & Wilcox (B&W) (the technology supplier at Nelson Dewey)
to EPA stating that

[[Page 67147]]

only 30.4 percent of the cyclone boiler population have an adequate
residence time for 50 percent NOX removal, another 15 percent have
residence time to support up to 35 percent reduction, and the remaining
are mostly unsuitable for coal reburning because of inadequate
residence times or expected high unburned carbon levels.
Another commenter, a new supplier of coal reburning that is also a
reputable existing supplier of gas reburning, supported the assumptions
and results used by EPA in its coal reburning technology evaluation and
provided further information on the feasibility of coal reburn. This
information is in general agreement with the design basis used in the
EPA study. According to this information:
(1) This commenter is in the process of installing coal reburning
systems at a 300-MW wet bottom boiler in Ukraine, an industrial 40-MW
cyclone boiler in the U.S., and a 240-MW tangentially fired boiler in
the U.S. The commenter considers reburning technology commercially
viable and is prepared to offer commercial guarantees.
(2) The commenter has conducted and reported a survey of furnace
depth for the cyclone boilers in the U.S. The furnace depth is a
critical parameter for the reburning feasibility assessment because it
affects the mixing of the reburn fuel within the furnace. The commenter
reported that there is little increase in the furnace depth for cyclone
boilers exceeding a 400 MW rating. The maximum furnace depth for
cyclone boilers is reported at 34 feet. There has been successful
experience with gas reburning at a furnace depth of 30 feet, and a coal
reburning system retrofit on a unit with the same depth is also
underway.
(3) The commenter has evaluated reburning feasibility for several
large size cyclone boilers and has found sufficient residence time
available for reburning application. The typical residence time for
these boilers is reported at 0.7 seconds, whereas this commenter's
minimum residence time criterion for its coal reburning system is 0.5
seconds.
(4) The residence time criterion may be the main difference between
the coal reburning technologies offered by the commenter and B&W. B&W
has previously provided a minimum residence time criterion of 1.1
seconds to EPA, which is a far more restrictive requirement than this
commenter's criterion of 0.5 seconds.
(5) Based on the above experiences, the commenter does not see
boiler size as a limiting factor for the reburning technology.
Response: The coal reburn evaluation presented in EPA's study was
based on the experiences with this technology at the Nelson Dewey
demonstration project with appropriate adjustments made for the study
boiler cases. The results of the Nelson Dewey demonstration were
contained in a detailed report by B&W and DOE. In this report, B&W also
provided an assessment of the feasibility of this technology, according
to which the only feasibility concerns were for the small cyclone
boilers (less than 80 MWe).
B&W's October 1995 letter referenced by some commenters was
submitted following the completion of EPA's study. This letter appears
to be inconsistent with the findings at Nelson Dewey and with the
results of analyses B&W reported along with the results of the
demonstration. Since B&W did not submit complete details and supporting
data regarding its new position, a direct comparison with the
information in the original report is not possible.
The concerns raised by some of the commenters are either based on
the position taken by one technology supplier (B&W) or are speculative
in nature. The information furnished by the new supplier of coal
reburning, referenced above, appears to address many concerns regarding
coal reburning feasibility on large cyclone boilers. However, because
of the inconsistency of the information and experience reported so far
with coal reburning, EPA has decided not to rely on this technology to
establish emission limitations for cyclone boilers.
Even though there is significant comment supporting the wide
availability and proposed achievable reduction performance capability
of coal reburning, the main manufacturer of this technology, B&W,
raises serious doubts as to its availability for all cyclone boilers
and its NOX reduction performance. At this time, EPA cannot
conclude that coal reburning is applicable at 50 percent NOX
reduction on all cyclone boilers. Since SCR and gas reburning have been
found to be available control technologies capable of achieving 50%
NOX reduction, EPA does not consider coal reburning technology as
one of the best systems of continuous emission reduction for cyclone
boilers under section 407(b)(2).

ii. Selective Catalytic Reduction (SCR)

Based on cost analyses conducted by the A/E contractor, EPA
proposed an emission limitation for cyclone boilers based on the use of
SCR, which was considered comparable to LNB applications on Group 1
boilers, and based the proposed cyclone boiler emission limit on SCR,
in addition to coal reburn.
Comment/Analyses: EPA received several comments on the cost of SCR
technology applied to cyclone boilers. These comments focused primarily
on whether EPA has included all of the new equipment and modifications
required for retrofitting SCR to cyclone boilers and whether EPA's cost
estimates are comparable to the SCR cost data reported by other
stakeholders.
Some commenters believe that EPA underestimated the retrofit cost
of SCR by not taking into account some of the necessary SCR system
design features, existing plant modifications, and impacts on plant
performance. According to the commenters, EPA should have accounted for
costs for: (1) Plant modifications listed by EPA as scope adders, (2)
initial SCR catalyst, (3) economizer bypass, and (4) proper accounting
of annual catalyst costs.
EPA notes that, as described in the Group 2 Boiler Study and in the
earlier preamble discussion on the retrofit nature of EPA's control
costs, scope adders are items that will not be required for typical
NOX control technology retrofits. Additionally, EPA does not
include ``scope adders'' in its estimates of Group 1 LNB costs or in
its estimates of Group 2 NOX control costs. Since the ultimate
purpose is to compare Group 1 boiler cost-effectiveness to Group 2
boiler cost-effectiveness, EPA's approach provides for a more
consistent cost-effectiveness comparison between the two boiler types.
For some special cases, however, scope adders may be required for
accommodating the control technology retrofit or may be selected by the
owners for other reasons, such as to provide an overall improvement in
the plant operations or design. For these reasons EPA's Group 2 Boiler
Study presents these costs, though they are not necessary for typical
retrofits. The contingency allowances included in all cost estimates in
the EPA study will cover any scope adder items that might be required
in special cases.
Additionally, EPA's costs include the initial catalyst costs (see
docket item IV-A-4, the first item in Table B4-17 and the first direct
cost item in Table B4-18) and costs for an economizer bypass (see
docket item IV-A-4, the first item of Table B4-17). Further, the
approach taken in the EPA study results in a conservative cost estimate
for the annual catalyst costs. In the study, it is assumed that one-
third of the catalyst would be replaced during each year of operation,
starting the very first year, to maintain the performance at the
originally specified levels. A less

[[Page 67148]]

conservative approach would be to assume catalyst replacement starting
only in the fourth year of operation, as suggested by the commenter
questioning EPA's costs. EPA's approach was taken to simplify the cost
estimation as well as to provide more conservative costs.
Several commenters have cited SCR retrofit costs reported by other
stakeholders that are higher than EPA's cost estimates. Two of the cost
sources reported include DOE and EPRI. Another utility commenter
submitted a study conducted recently on its behalf. EPA reviewed the
SCR retrofit cost information cited by the above commenters. EPA's
evaluation of the information provided by these sources is provided
below:
(1) A direct comparison of the DOE model-generated costs was made
with the costs in EPA's study. For a 400 MW boiler with the same design
basis as that selected for EPA's study boiler (a NOX reduction
efficiency of 50 percent and an inlet NOX of approximately 770
ppm), DOE reports a capital cost of approximately $50/kW vs. $41/kW
reported by EPA. The DOE costs are based on the use of extremely high
project and process contingency factors of approximately 25.6 and 15.8
percent, respectively (compared to 15 and 5 percent in EPA's study). In
addition, DOE uses a general facility contingency factor of 10 percent
(compared to 5 percent in EPA's study). EPA believes that in light of
the extensive worldwide experience with SCR retrofits to coal-fired
boilers, (see docket item II-I-37, Selective Catalytic Reduction
Controls to Abate NOX Emissions, prepared by the Institute of
Clean Air Companies), use of such high contingency factors as in DOE's
estimates are unduly conservative. If these differences are eliminated,
the capital costs developed by the DOE model would be slightly lower
than EPA capital costs: Using the EPA, in lieu of the DOE, contingency
factors, DOE's capital costs would be approximately $40/kW, as compared
to the EPA cost of $41/kW. Thus, the DOE model supports the results of
the EPA study when the effects of overly conservative contingencies are
removed. This is verified by calibrating the predictive power of the
two models with the only actual retrofit experience. EPA's cost
estimates compare more favorably with the only actual retrofit of SCR
on a cyclone boiler (Merrimack), predicting a conservative $68.53/kW
^{21 compared to the actual $56/kW, while DOE's model would predict
a significantly higher cost than EPA's estimate.
---------------------------------------------------------------------------

\21\ This is the capital cost estimate for a boiler of
Merrimack's size under EPA's methodology, after adjusting for this
particular boiler's NOX reduction efficiency of 65 percent
versus 50 percent used in EPA's study and the boiler's baseline
emission level of 2.66 lb/mmBtu versus 1.3 to 1.4 lb/mmBtu used in
EPA's study.
---------------------------------------------------------------------------

(2) EPRI quoted a capital cost range for retrofitting SCR to the
Group 2 boilers from $70 to $200/kW in its comments and provided no
supporting data. These costs are significantly higher than EPA's costs
and completely unrealistic when compared to the capital cost of $56/kW
reported for the SCR installation at the cyclone boiler at Merrimack
Station. This operating installation has been described by the utility
that conducted it as a moderately difficult retrofit. Still, even the
lower end of the EPRI's cost range is well above the Merrimack-reported
cost. The cost range predicted by EPRI is given little weight since the
cost range has no supporting data and is inconsistent with the only
actual retrofit of SCR on a cyclone boiler.
(3) One of the commenters submitted a report prepared by an
independent architectural & engineering firm and containing costs for
specific applications of SCR on cyclone boilers. A review of the report
revealed the following:
(A) The report itself notes that the nature of the analyses
performed was preliminary and states that further detailed evaluation
is needed to provide a reliable assessment of the SCR retrofit to the
cyclone boilers that were studied. The report relies on
constructability evaluations based on a review of drawings only and
cost estimates based on a roughly estimated SCR system design. While
EPA's study developed detailed component-level costs, the report does
not include any details for the cost estimates.
(B) The report discusses the impact of SCR on existing plant
equipment. However, the report is not clear as to what type of
modifications have been included for what equipment, while EPA's study
presents detailed lists of modifications to equipment. The SCR systems
have apparently been designed for a NOX removal efficiency ranging
from 35 to 45 percent. The operating costs are based on very low
NOX removal efficiencies ranging from 29 to 38 percent. Both of
these assumptions artificially increase the estimated costs/ton of SCR.
EPA costs are based on a NOX removal efficiency of 50 percent
(which is easily achievable by SCR).
EPA concludes that the subject report uses questionable
assumptions, is not a detailed analysis, provides inadequate supporting
details, compares poorly to the only actual retrofit at Merrimack, and
thus provides no basis for revising EPA's cost estimates.
In addition to the above sources, some commenters provided SCR cost
information based on their own evaluations and studies. In general,
these costs are not supported by actual data. In contrast, EPA's study
is heavily corroborated by experience and actual data, and therefore,
the comments do not provide a basis for revising EPA's cost estimates.
Other commenters have supported the costing methodology used by
EPA. Two commenters (one of which has performed the only retrofit of an
SCR to a cyclone boiler, i.e., Merrimack Unit 2) provide data from that
SCR retrofit in support of the costs developed by EPA.
Response: EPA's costs are intended to cover the SCR retrofit
requirements at typical Group 2 cyclone boiler installations. In EPA's
evaluation of these costs, it was recognized that the retrofit
requirements at some boiler installations could exceed the norm just as
other retrofit requirements could be below the norm. Boiler-specific
unique requirements beyond the norm were identified as scope-adders in
this evaluation. However, the EPA cost estimates included contingency
allowances that will cover the cost of these requirements.
As noted in the previous section addressing the retrofit nature of
EPA's costs, the Group 2 Boiler Study includes detailed lists of new
equipment and existing plant modifications applicable to each
technology retrofit. These lists provide detailed information on the
hardware associated with typical retrofits and scope adders. Thus, the
EPA costs, developed at the hardware component level, include the
retrofit requirements for typical and non-typical control technology
installations.
The high estimated capital and levelized costs mentioned by some
commenters and their sources (e.g., DOE, EPRI, and an architectural/
engineering firm hired by one commenter) are not borne out by the
reported experience at the aforementioned Merrimack SCR installation.
For this 330 MW cyclone-fired installation, designed for a 65 percent
NOX removal efficiency, the total capital cost was reported to be
$56/kW. This cost included the addition of a significant amount of
additional ductwork and support steel required for this retrofit
because of unusual space limitations. The baseline NOX emission
for this unit was also unusually high (2.66 lb/mmBtu), thus requiring a
relatively large and expensive ammonia handling system.

[[Page 67149]]

EPA used the information available from Merrimack to corroborate
its costing methodology (see docket item IV-A-16, SCR model validation
study). A comparison of the Merrimack cost with the EPA-reported costs
in the Group 2 Boiler Study (August 1995) is not directly possible
because of the differences in the design NOX reduction efficiency
(65 percent at Merrimack versus 50 percent in EPA's study) and the
baseline NOX emission levels (2.66 lb/mmBtu at Merrimack versus
1.3 to 1.4 lb/mmBtu in EPA's study). Thus, to ensure proper comparison,
EPA included the design criteria used at Merrimack while employing the
Agency's costing methodology. The capital cost developed with this
approach could then be compared to the actual Merrimack cost for
validation purposes.
Table 15 shows an equipment list for the Merrimack installation.
This list has been prepared from published information and information
received by EPA from the system supplier. It should be noted that this
installation did not require some of the existing plant modifications
that were included for the boilers used in the EPA study (e.g.,
replacement of the existing draft fans and an economizer bypass).
However, the SCR installation at Merrimack 2 did require extensive flue
gas ductwork to accommodate the SCR within the existing setting;
further, in this installation, a bypass around the SCR reactor was also
provided. The items in Table 15 were accounted for in the EPA cost
estimate to model the retrofit at Merrimack Unit 2.

Table 15.--Major Equipment List Merrimack SCR Anhydrous Ammonia-Based
Boiler Size: 330 MW
------------------------------------------------------------------------
No. Item Description/size
------------------------------------------------------------------------
1....... SCR reactor......... Vertical flow type, 1,615,350 acfm
capacity, equipped with a plate type
catalyst with 14,124 ft^{3 volume placed
in two layers, insulated casing with
two empty layers for future catalyst
addition, sootblowers, hoppers, and
hoisting mechanism for catalyst
replacement.
3....... Anhydrous ammonia Horizontal tank, 250 psig pressure; 87.5-
storage. ton storage capacity.
2....... Compressors......... Rotary type, rated at 400 scfm and 10
psig pressure.
2....... Electric vaporizer.. Horizontal vessel, 450 kW capacity.
1....... Mixing chamber...... Carbon steel vessel.
1 Lot... Ammonia injection Stainless steel construction.
grid.
1 Lot... Ammonia supply Piping for ammonia unloading and supply,
piping. carbon steel pipe: 4.0 in. diameter,
600 ft long, with valves, and fittings.
1 Lot... Air ductwork........ Ductwork between air heater, mixing
chamber, and ammonia injection grid,
carbon steel, 400 ft long, with two
isolation butterfly dampers, and
expansion joints.
1 Lot... Sootblowing steam Steam supply piping for the reactor
piping. sootblowers, consisting of 200 feet of
2'' diameter pipe with an on-off
control valve and drain and vent valved
connections.
1 Lot... Flue gas ductwork... Ductwork modifications to install the
SCR reactors, consisting of insulated
duct, isolation damper, turning vanes,
and expansion joints.
1 Lot... SCR bypass.......... Ductwork consisting of insulated duct,
12'x24' double-louver isolation damper
with air seal, and expansion joints.
1 Lot... Ash handling Extension of the existing fly ash
modifications. handling system modifications,
consisting of one slide gate valves,
one material handling valves, one
segregating valve, and ash conveyor
piping, 180 ft long with couplings.
1 Lot... Controls and Stand-alone microprocessor based
instrumentation. controls for the SCR system with
feedback from the plant controls for
the unit load, NOX emissions, etc.,
including NOX and ammonia analyzers,
air and ammonia flow monitoring
devices, and other miscellaneous
instrumentation.
1 Lot... Electrical supply... Wiring, raceway, and conduit to connect
the new equipment and controls to the
existing systems.
1 Lot... Foundations......... Foundations for the equipment and
ductwork/piping, as required.
1 Lot... Structural steel.... Steel for access to and support of the
SCR reactors and other equipment,
ductwork, and piping.
------------------------------------------------------------------------

Table 16 shows the capital cost estimate for the Merrimack retrofit
using the same cost model that was used to generate costs for EPA's
study. As shown in Table 16, the total plant capital requirement
according to EPA's model is $68.53/kW, which is over 20% higher than
the actual cost reported for Merrimack of $56/kW. Thus, this comparison
confirms the conservatism of the cost methodology used in EPA's study.

Table 16.--EPA's Retrofit Capital Cost Estimate Summary for SCR
Modifications to a Cyclone-Fired Boiler
------------------------------------------------------------------------
NOX Control Technology SCR
------------------------------------------------------------------------
Boiler Size (MW)......................... 330
Cost Year................................ 1994
Direct Costs ($/kW):
SCR reactors/ammonia storage......... 31.3
Piping/ductwork...................... 13.1
Electrical/PLC....................... 3.1
Draft fans........................... 0
Platform/insulation/enclosure........ 1.1
Total direct costs ($/kW).......... 48.6
Scope adder costs ($/kW), (Yes/No):..
Asbestos removal..................... 0
Transformer.......................... 0
Air heater modifications............. 0
Boiler system structural 0
reinforcement.
Total scope adder costs ($/kW)..... 0
Total direct process capital ($/ 48.6
kW):.

[[Page 67150]]

Indirect costs:
General facilities................... 5.0% 2.4
Engineering and home office fees..... 10.0% 4.9
Process contingency.................. 5.0% 2.4
Project contingency.................. 15.0% 8.7
Total Plant Cost (TPC) ($/kW)...... 67.1
Construction years....................... 0
Allowance for funds during construction.. 0
Total plant investment (TPI) ($/kW)...... 67.1
Royalty allowance........................ 0.00% 0
Preproduction cost....................... 2.00% 1.3
Inventory capital........................ Note 0.13
Initial catalyst and chemicals 0.00%..... 0
Total plant requirements ($/kW).... 68.53
------------------------------------------------------------------------
Note: Cost for anhydrous ammonia stored at site.

Based on the record, including the above comments and responses,
EPA concludes that SCR can be applied to cyclone boilers greater than
155 MW with at least 50% NOX reduction at the cost-effectiveness
projected by the Agency and that SCR so applied is comparable to Group
1 LNBs.

iii. Gas Reburning

Several comments were received by EPA concerning the use of gas
reburning technology on cyclone boilers. These comments primarily
focused on the adequacy of the gas reburning system design and cost
estimation procedures used in EPA's evaluation of this technology.
Comment/Analyses: In EPA's evaluation, natural gas was assumed to
be available within the plant fence of each application. Some
commenters did not agree with this assumption and cited specific
examples of plants where the nearest gas supply pipeline is several
miles from the plant sites. One commenter quoted a pipeline access cost
at $750,000 to $1,000,000 per mile of pipeline. Another commenter
provided pipeline costs for a specific station well below that range.
Yet another commenter suggested adding a cost of a 10 mile access
pipeline in EPA's estimates for this technology. This commenter
suggests a minimum cost estimate of $10/kW for this pipeline addition.
Another commenter provided detailed information on the available
gas pipeline size, pressure, and distance from the plant for all Group
2 cyclone-fired boilers. This commenter also noted that adequate
wellhead supplies exist to provide gas needed for gas reburning and
that 77 of the 89 cyclones included in EPA's database are located in
the Midwest regions with abundant pipeline capacities.
Another issue raised by some commenters is the natural gas to coal
price differential used by EPA in evaluating gas reburning. While one
commenter felt that the cost differential used by EPA was low, several
commenters either agreed with EPA's cost differential or suggested use
of lower differentials. One of these commenters cited the results of a
detailed study done to evaluate natural gas/coal price differential at
142 stations, which showed a median differential of only $0.41/mmBtu
and a mean average differential of only $0.49/mmBtu. Two commenters
suggested using the average differential of $0.96/mmBtu as reported in
the EIA's Annual Energy Outlook (1996) for the years 2000 to 2005.
Several commenters were in general agreement with EPA's capital
cost estimates for the gas reburning technology. Some provided examples
of actual retrofits with costs similar to EPA's costs. Other
commenters, however, objected to EPA's cost estimates. One commenter
believed that EPA should have included the cost of scope adders in the
evaluated technology costs. Some commenters provided their own
estimates of the gas reburning cost ($/ton NOX removed or mills/
kWhr) that were higher than EPA's estimates. One of these commenters
provided details of a specific study conducted by an architectural
engineering firm for specific cyclone boilers. EPA notes that, as
described in the earlier preamble discussion on the retrofit nature of
EPA's control costs, scope adders are items that will not be required
for typical NOX control technology retrofits. Additionally, EPA
does not include ``scope adders'' in its estimates of Group 1 LNB costs
or in its estimates of Group 2 NOX control costs. Since the
ultimate purpose is to compare Group 1 boiler cost-effectiveness to
Group 2 boiler cost-effectiveness, EPA's approach provides for a more
consistent cost-effectiveness comparison between the two boiler types.
Response: Through the comments received on the proposed rule,
additional information has become available on the availability of
natural gas supply at the cyclone boiler installations. Based on this
new information, EPA has revised its cost estimates for gas reburning
to include costs associated with providing access to gas supply beyond
the plant fence (see docket item IV-A-4). Further, EPA chose to use the
natural gas to coal price differential for the year 2010 since this
year would reflect the midpoint of the expected compliance period for
most of the Group 2 boilers. According to DOE's Energy Information
Administration (EIA) Annual Energy Outlook for 1996, this differential
is Sec. 1.10 per mmBtu, expressed in 1990 dollars. The resulting cost-
effectiveness of gas reburning, as shown in section III.B.2 of this
preamble, meets the cost comparability criteria.
Based on the record, including the above comments and responses,
EPA concludes that gas reburning can be applied to cyclone boilers
greater than 155 MW with at least 50% NOX reduction at the cost-
effectiveness projected by EPA and that gas reburning so applied is
comparable to Group 1 LNBs. As discussed above, applying the
requirements of section 407(b)(2), EPA is establishing a NOX
emission limitation for cyclone boilers based on SCR or gas reburning
at 50% NOX reduction performance. The EPA notes that the reliance
on gas reburning in setting emission limitations will encourage gas use
in appropriate cases.
6. Wet Bottom Boiler NOX Controls
At the time the proposed rule was issued, EPA believed that
combustion NOX controls (such as overfire air) would be applicable
to all wet bottom boilers. This belief was based on an ongoing
demonstration by the American Electric Power Company (AEP). Since
overfire air (OFA) seemed to be a very cost-effective way of achieving
significant reductions (about 50%), EPA did not rely on any other
available NOX control (i.e., SCR or gas reburning) in setting the
wet bottom boiler emission limit. EPA has, however, received comments
that the AEP demonstration has not been successful and that EPA should
investigate the retrofit of SCR and gas reburning to wet bottom
boilers.
Comments/Analyses: The utility (AEP) that is conducting the only
combustion NOX control demonstration on a wet bottom boiler has
commented that it is inappropriate to use that utility's engineering
estimates of what may be achievable using a two-stage OFA system.
According to this utility, actual reductions at their wet bottom
boiler, based on the retrofit of a two-stage OFA system, have been 22%
at 90-100% of full load, 31% at 70% load, and as small as 10% at
minimum (60%) load.
One commenter believes that even for boilers to which the two-stage
overfire

[[Page 67151]]

air approach may eventually apply, a technology cannot be considered to
be available when a single demonstration had just begun at the time the
proposal was signed. The same commenter also expressed concerns related
to the fact that the various categories of wet-bottom boilers feature
significantly different furnace size and firing characteristics and
thus would not be able to achieve acceptable carbon burnout or
protection of the lower furnace from corrosion. This commenter also
feels that the uncertainty over applicability and control performance
prevent a thorough cost evaluation.
According to another commenter, SNCR is estimated to have a cost of
over $900/ton removed, while SCR is estimated to have a cost of over
$830/ton. Allegedly, these technologies may not be cost-effective when
applied to wet bottom boilers.
Other commenters have recommended considering gas reburning and SCR
as being viable and cost-effective approaches for controlling NOX
from these boilers.
Response: The AEP demonstration of retrofitting a two-stage OFA
system to a wet bottom boiler has not proved to be successful as yet.
Thus, EPA does not find this technology to be the best system of
continuous emission reduction for wet bottom boilers and is not using
the technology to establish a NOX emission limit for wet bottom
boilers in this rulemaking.
In light of the comments received, EPA considered the
applicability, likely performance, and projected cost of gas reburning
and SCR applications on wet bottom boilers. Using information on full-
scale installations of gas reburning and SCR on wet bottom boilers and
information received through the comments on the availability of
natural gas at the wet bottom boilers, EPA has determined that gas
reburning and SCR are available to all wet bottom boilers that will
need to reduce NOX emissions. In any event, EPA maintains that,
because they are post-combustion control systems in that they are
applied downstream of the main combustion process, both gas reburning
and SCR are available to any boiler type, (e.g., in this case wet
bottom boilers). 61 FR 1457. Again, because these are post-combustion
technologies, their application to wet bottom boilers raises the same
applicability and performance considerations as those discussed in the
context of cyclone boilers, e.g., in the proposal (61 FR 1468 and
1470). For the same reason, the analysis of issues concerning SCR costs
and natural gas availability and costs (e.g., in section III.B.6.ii-iii
of this preamble) in the context of applying these technologies to
cyclone boilers is fully applicable to the application of these
technologies to wet bottom boilers. Having fully addressed gas
reburning and SCR applicability, performance, and cost-effectiveness-
related issues in the cyclone boiler context, EPA finds that these are
the best systems of continuous emission reduction for wet bottom
boilers. EPA has estimated the cost-effectiveness of gas reburning and
SCR as applied to each boiler in the wet bottom boiler population. The
same approach as that used for other boiler types--i.e., of using the
boilers' usage and uncontrolled emissions to determined the cost-
effectiveness distribution--was used here. The resulting cost-
effectiveness for gas reburning and SCR applied to wet bottom boilers,
as shown in section III.B.2 of this preamble, meet EPA's cost
comparability criteria. Based on the record, including the above
comments and responses, EPA concludes that gas reburning and SCR can be
applied to wet bottom boilers with at least 50 percent NOX
reduction and that gas reburning and SCR so applied are comparable to
Group 1 LNBs. As discussed above, applying the requirements of section
407(b)(2), EPA is establishing a NOX emission limitation for wet
bottom boilers based on gas reburning and SCR at 50 percent NOX
reduction performance.
7. Vertically Fired Boiler NOX Controls
Comments/Analyses: The Agency received comments from approximately
8 commenters (4 utilities, 1 utility association, 1 environmental
association, 1 vendor, and 1 vendor association) on the proposed
emission limitation for vertically-fired boilers. The utility
commenters generally supported the proposed limitation as being
achievable and comparable in cost, but raised some concerns about the
ability of the broad variety of boilers in this category to achieve the
proposed limit. Two commenters raised specific concerns about the
ability of arch-fired boilers to achieve the limit. These commenters
noted that because of design differences, neither of the combustion
control technologies demonstrated on other vertically-fired boilers
could be used on arch-fired boilers.
The environmental association argued that stricter limits should
apply. The vendor commenter disagreed with excluding SNCR as a control
option based on cost because the only SNCR retrofit on a vertically-
fired boiler was installed in an atypical manner with numerous non-
licensed design changes.
Response: As discussed in the proposed rule, EPA examined SNCR
applications to vertically fired boilers and found that SNCR did not
meet the cost comparability requirement. Hence, EPA did not base the
proposed emission limit for vertically fired boilers on SNCR. Further,
as discussed in the Group 2 boiler support document (see docket item
IV-A-4), in its examination of SNCR costs, EPA did not include any
atypical design features that could affect costs. Upon review of the
record, including the above comments, EPA is not revising its SNCR cost
estimates and still maintains that these costs do not meet the cost
comparability requirement.
Moreover, EPA, based on its analysis in the proposal and section
III.B.2 of this preamble and applying the requirements of section
407(b)(2), concludes that an emission limit should be set for
vertically fired boilers based on the application of combustion
controls with at least 40% NOX reduction. However, in light of the
information received from commenters showing the unavailability of
combustion controls for arch-fired boilers, a subset of the vertically
fired boiler category, EPA is excluding these boilers from the emission
limitation for vertically fired boilers. Because combustion controls
are extremely cost-effective (having a median cost-effectiveness lower
than the median for either wall-fired or tangentially fired boilers)
and can achieve significant NOX reduction (at least 40 percent),
EPA has determined that combustion controls are the best system of
continuous emission reduction for vertically fired boilers and that the
emission limit should not be based on other available NOX control
technologies (e.g., gas reburning or SCR) whose cost-effectiveness
values would be much higher.
8. Cell Burner Boiler NOX Control
Comments/Analyses: Utility commenters agreed that plug-in controls
for 2-cell burner boilers are available and are comparable to LNBs
applied to Group 1 boilers. However, some of these commenters asserted
that non-plug-in controls, though available for cell burner boilers,
are not comparable to Group 1 LNBs.
A commenter stated that plug-in technology is available for 2-cell
burner boilers and comparable to Group 1 LNBs but is unavailable for 3-
cell burner boilers. The same commenter stated that non-plug-in
technology is an available technology for cell burner boilers. Several
utility commenters claimed that non-plug-in technology is not
comparable to Group 1 LNBs. One

[[Page 67152]]

commenter stated that capital costs for non-plug-in retrofits range
from $20-27/kW, whereas LNBs average $14/kW. Another commenter
estimated non-plug-in retrofit would cost approximately $30/kW as
opposed to $6/kW for plug-in retrofit. However, yet another commenter
asserted that cost and cost-effectiveness of non-plug-in retrofit at
Brayton Point Unit No. 3 are within the cost range for Group 1 LNBs.
This commenter used EPA's methodology to determine a cost of $24/kW and
cost-effectiveness of $111/ton for the Brayton Point retrofit.
Response: In its proposal, EPA considered plug-in controls to be
available for controlling NOX emissions from 2-cell burner boilers
and considered non-plug-in controls to be broadly applicable on cell
burner boilers, including those with 3-cell configurations. Further,
EPA found both of these controls to be comparable to Group 1 LNBs. The
proposed limit of 0.68 lb/mmBtu was then based on achieving 50%
NOX reduction with either of the plug-in or non-plug-in controls.
The comments received support EPA's position with respect to
applicability of plug-in and non-plug-in controls and costs of plug-in
controls. However, comments express concerns with the costs of non-
plug-in controls. EPA continues to believe that non-plug-in controls
are comparable to LNBs. EPA's position with respect to cost of non-
plug-in controls is supported by the information obtained on the
retrofit at Brayton Point Unit 2 by the utility that owns this unit
(see docket item IV-D-30). Based on the record, including the above
comments and responses, EPA concludes that, as set forth in the
proposal and section III.B.2 of this preamble, plug-ins and non-plug-
ins applied to cell burner boilers at 50 percent NOX reduction are
comparable in cost-effectiveness to Group 1 LNBs. As discussed above,
applying the requirements of section 407(b)(2), EPA is establishing a
NOX emission limitation for cell burner boilers based on plug-ins
and non-plug-ins at 50 percent NOX reduction performance. Because
plug-ins and non-plug-ins are extremely cost-effective (having a median
cost-effectiveness lower than either wall-fired or tangentially fired
boilers) and can achieve significant NOX reduction (at least 50
percent), EPA has determined that plug-ins and non-plug-ins are the
best system of continuous emission reduction for cell burner boilers
and that the emission limit should not be based on other available
NOX control technologies (e.g., gas reburning or SCR), whose cost-
effectiveness values would be much higher.
9. Revision of Proposed Group 2 Boiler NOX Emission Limits
In the proposal, EPA chose to set the emission limits for the
various Group 2 boiler populations at the emission rates that a target
of about 95% of the pertinent populations could meet. In light of the
compliance flexibility available due to emissions averaging and AEL,
the above approach was considered to be conservative. The Agency,
however, requested comment on whether the approach should be consistent
with the approach being used in revision of Group 1 boiler
limits.^{22
---------------------------------------------------------------------------

\22\ For the Group 1 emission limits, EPA based the achievable
limit on the point at which approximately 90% of the affected
boilers would likely meet the limit.
---------------------------------------------------------------------------

Comments/Analyses: For cell burners, several utility commenters
agreed that the proposed emission limit is reasonable. According to one
other commenter, experience with cell burner boilers operated by the
commenter shows that the proposed limit can be achieved and provides a
margin to accommodate uncontrollable variability. However, the
commenter believes that any lower limit may be difficult to achieve,
especially for boilers owned by other utilities, because the
commenter's boilers appear to have below average uncontrolled rates.
One other commenter believes that the data from the plug-in retrofit of
Muskingum River Unit 5 indicates that the limit can be met. While the
design of that unit differs significantly from other cell burner
boilers in the AEP system, the commenter supports EPA's proposed
limits.
Other commenters support setting more stringent NOX limits for
all Group 2 boilers and cyclones in particular, stating that EPA should
set an emission limitation based on the emission rates that 50% of the
population can meet, since boilers not meeting the resulting limitation
can average their emissions with other, lower emitting boilers, or
apply for an AEL.
Response: EPA based the emission limit for Group 2 boilers on the
emission rate that 85 percent to 90 percent of the affected boilers
could meet on an individual unit basis. Based on the comments, EPA
concludes that it should be consistent in its approaches for
establishing the emission limits for Phase II, Group 1 boilers and
Group 2 boilers. In light of the compliance flexibility available due
to emissions averaging and alternative emission limitations (AELs),
this approach is reasonable. Since there is no restriction on what
boiler types may be included in an averaging plan, Phase II, Group 1
and Group 2 boilers have the same overall opportunities for averaging.
Under the NOX regulations, the availability of AELs is also not
different among boiler types.
As explained in the context of Group 1 boilers, in its Group 2
boiler database, EPA replaced long term ETS uncontrolled NOX rates
with short term CREV rates (see docket item IV-A-4). Using short-term
CREV data and quality assured short-term emission data, EPA was able to
obtain uncontrolled emission data for about 98% of the Group 2
population. This revised database was used in establishing any revised
emission limits described below.

i. Cell Burners

As elaborated above, none of the commenters, including utilities
with cell-burner NOX control retrofits claimed that the proposed
0.68 lb/mmBtu was not a reasonable limit to require if plug-ins or non-
plug-ins were installed. The only adverse comments were either that the
control technology (i.e., non-plug-ins) is not comparable to LNBs on
Group 1 boilers or that a more stringent emission limit should be
established. EPA's projections show that about 80 percent of the cell
burner boilers can achieve the 0.68 lb/mmBtu limit on an individual
unit basis. Although EPA's general approach is to set the emission rate
at a level that 85 percent to 90 percent of the units are projected to
achieve on an individual unit basis, EPA decided, in these unique
circumstances where no commenter contests the achievability of 0.68 lb/
mmBtu with plug-ins or non-plug-ins, to set that level as the emission
limit. With commenters asserting that a more stringent rate may not be
achievable, there is no basis for setting a lower limit. For this
reason and the reasons set forth in section I.B.1 of this preamble, EPA
is setting 0.68 lb/mmBtu as the emission limit for cell burners based
on plug-ins and non-plug-ins.

ii. Cyclones

As explained above, EPA is establishing an emission limit for
cyclone boilers greater than 155 MW based on gas reburning and SCR at
50% NOX reduction performance. Applying the projected 50% emission
reduction to the uncontrolled emissions of each boiler in the cyclone
boiler population for which NOX limits are to be set under section
407(b)(2), EPA determined the percentage of the boilers that could
achieve various NOX performance levels

[[Page 67153]]

on an individual unit basis, as shown in the table below.

------------------------------------------------------------------------
% of boilers
NOX level (lb/mmBtu) meeting NOX
level
------------------------------------------------------------------------
1.12.................................................... 100
0.92.................................................... 95
0.88.................................................... 90.9
0.86.................................................... 89
0.82.................................................... 86
------------------------------------------------------------------------

The table indicates that 89% of the cyclone boilers can achieve on
an individual unit basis a NOX controlled emission rate of 0.86
lb/mmBtu. Applying its general approach of setting emission limits
based on reasonable achievability, EPA sets that rate as the emission
limit based on gas reburning and SCR. EPA recognizes that a rate of
0.87 lb/mmBtu would also yield an 89 percent individual-unit
achievability level. However, because of emissions averaging under
Sec. 76.10, this would likely reduce the amount of NOX reductions
realized since a cyclone boiler could meet 0.86 lb/mmBtu and other
units in an averaging plan could use the excess reduction to reduce
less themselves. Taking account of this likely environmental result,
EPA adopts the 0.86 lb/mmBtu emission limit.

iii. Wet Bottom Boilers

As explained above, EPA is establishing an emission limit for wet
bottom boilers greater than 65 MW based on gas reburning and SCR at 50%
NOX reduction performance. Applying the projected 50% emission
reduction to the uncontrolled emissions of each boiler in the wet
bottom boiler population for which NOX limits are to be set under
section 407(b)(2), EPA determined the percentage of the boilers that
could achieve various NOX performance levels on an individual unit
basis, as shown in the table below.

------------------------------------------------------------------------
% of boilers
NOX level (lb/mmBtu) meeting NOX
level
------------------------------------------------------------------------
0.95.................................................... 100
0.94.................................................... 91
0.84.................................................... 87.8
0.8..................................................... 78.7
------------------------------------------------------------------------

The table indicates that 87.8% of the wet bottom boilers can
achieve a NOX controlled emission rate of 0.84 lb/mmBtu. Applying
its general approach of setting emission limits based on reasonable
achievability, EPA sets that rate as the emission limit based on gas
reburning and SCR. EPA recognizes that a rate of up to 0.93 lb/mmBtu
would also yield an 87.8 percent individual-unit achievability level.
However, because of emissions averaging under Sec. 76.10, this would
likely reduce the amount of NOX reductions realized since a wet
bottom boiler could meet 0.84 lb/mmBtu and other units in an averaging
plan could use the excess reduction to reduce less themselves. Taking
account of this likely environmental result, EPA adopts the 0.84 lb/
mmBtu emission limit.

iv. Vertically Fired Boilers

As explained above, EPA is establishing an emission limit for
vertically fired boilers, excluding arch fired boilers, based on
combustion controls at 50% NOX reduction performance. Applying the
projected 50% emission reduction to the uncontrolled emissions of each
boiler in the vertically fired boiler population for which NOX
limits are to be set under section 407(b)(2), EPA determined the
percentage of the boilers that could achieve various NOX
performance levels on an individual unit basis, as shown in the table
below.

------------------------------------------------------------------------
% of boilers
NOX level (lb/mmBtu) meeting NOX
level
------------------------------------------------------------------------
1.00.................................................... 100
0.85.................................................... 96.4
0.83.................................................... 92.9
0.80.................................................... 89.3
0.74.................................................... 82.1
------------------------------------------------------------------------

The table indicates that 89.3% of the vertically fired boilers can
achieve a NOX controlled emission rate of 0.80 lb/mmBtu. Applying
its general approach of setting emission limits based on reasonable
achievability, EPA sets that rate as the emission limit based on
combustion controls. EPA recognizes that a rate of up to 0.82 lb/mmBtu
would also yield an 89.3 percent individual-unit achievability level.
However, because of emissions averaging under Sec. 76.10, this would
likely reduce the amount of NOX reductions realized since a
vertically fired boiler could meet 0.80 lb/mmBtu and other units in an
averaging plan could use the excess reduction to reduce less
themselves. Taking account of this likely environmental result, EPA
adopts the 0.80 lb/mmBtu emission limit.

C. Compliance Issues

This final rule implements Phase II of the Nitrogen Oxides
Reduction Program for which EPA must: (1) Determine if more effective
low NOX burner technology is available to support more stringent
standards for Phase II, Group 1 boilers than those established for
Phase I; and (2) establish limitations for Group 2 boilers based on
NOX control technologies that are comparable in cost-effectiveness
to LNBs.
A utility can choose to comply with the rule in one of three ways:
(1) Meet the standard annual emission limitations at each of its units;
(2) average the emission rates of two or more units that it owns or
operates, which allows utilities to over-control at units where it is
technically easier and less expensive to control emissions and under-
control at other units; or (3) if the standard emission limit cannot be
met at a unit after installing the technology on which the limit is
based and which is designed to meet the limit, the utility can apply
for a less stringent alternative emission limit (AEL). Phase I units
are required to meet the applicable limits by January 1, 1996; under
the proposed rule, EPA stated that the statutorily mandated date by
which Phase II units must meet the applicable limits is January 1,
2000.
Comment: Utility commenters contend that the language in section
407(b)(2) shows that there is no statutorily required compliance date
for Phase II, Group 1 and Group 2 boilers. EPA allegedly has no basis
to set any deadline until it provides appropriate justification. They
contend that EPA must provide a statement of purpose justifying the
reasonableness of the January 1, 2000 deadline or propose an
alternative that can be justified. Commenters also express concern that
scheduling the design, procurement, and testing of NOX retrofit
technologies will make compliance with the January 1, 2000 deadline
difficult, especially since four times as many boilers are subject to
NOX emission limitations in Phase II as were in Phase I. Other
commenters contend that EPA does not have the authority to extend the
compliance date because, except in cases where the Act requires earlier
compliance, it clearly requires compliance by January 1, 2000. Other
commenters state general opposition to extending the compliance
deadline because of industry awareness of impending emission reductions
that would be required and because any delay in the implementation of
the rule will only serve to delay the benefits associated with the
rule. Many commenters opposed to an extension in the compliance date
state that the availability of compliance alternatives (i.e., averaging
and AELs) support the establishment of limits more stringent than those
proposed.
Response: Some commenters argue that section 407 does not set a
specific deadline for compliance by Phase II, Group 1 and Group 2
boilers with Phase II NOX emission limitations. According

[[Page 67154]]

to these commenters, by not setting a specific Phase II deadline,
section 407 left the matter to the discretion of the Administrator.
EPA concludes, however, that section 407 sets a Phase II compliance
deadline of January 1, 2000 both for Group 1 boilers subject to the
Phase II NOX emission limitations under section 407(b)(2) and
Group 2 boilers. Section 407(a), entitled ``Applicability'', states:

On the date that a coal-fired utility unit becomes an affected
unit pursuant to section 404, 405, 409, or on the date a unit
subject to the provisions of section 404(d) or 409(b), must meet the
SO2 reduction requirements, each such unit shall become an
affected unit for purposes of this section and shall be subject to
the emission limitation for nitrogen oxides set forth herein. 42
U.S.C. 7651f(a), (emphasis added).

The provision first establishes a general rule that a coal-fired unit
becomes ``subject to'' the applicable NOX emission limitation on
the date that the unit becomes an ``affected unit under sections 404,
405, (or) 409'' (42 U.S.C. 7651f(b)(1)), i.e., on the same date it
becomes subject to the SO2 emissions limitation. The Act defines
``affected unit'' as a unit that is ``subject to the emission reduction
requirements or limitations under (title IV)''. 42 U.S.C. 7651a(2).
Sections 404 (covering Phase I units in Phase I), 405 (covering Phase I
and Phase II units in Phase II), and 409 (covering Phase II repowering
extension units) are the sections under which utility units are
allocated SO2 allowances under Phase I and Phase II,^{23 which
allowances serve as the SO2 emissions limitation unless the unit
buys or sells allowances. EPA concludes that the phrase, ``affected
unit under section 404, 405, [or] 409'', refers to a unit that is
subject to the SO2 emissions limitation established in those
sections.
---------------------------------------------------------------------------

\23\ Section 406, which provides for bonus allowances if elected
by a State Governor, changes the bonus allowances for 2000-2009
under section 405 for units located in the State.
---------------------------------------------------------------------------

EPA maintains that the general rule established in section 407(a)
governs and, when applied to specific units, sets a specific NOX
compliance deadline, except to the extent any other provision in
section 407 modifies that compliance deadline. There are additional
provisions, including a portion of section 407(a) itself, that address
the compliance deadline. However, contrary to some commenters, the
existence of those provisions does not mean that section 407(a) fails
to set a general rule for determining the compliance deadline. On the
contrary, these additional provisions modify the general rule for the
NOX compliance deadline but only for specified categories of
units.
In particular, section 407(a) itself contains an exception for
those units (i.e., Phase I extension units under section 404(d) and
Phase II repowering extension units under section 409(b)) that are
given extra allowances to extend the date by which they are required to
make reductions in SO2 emissions. The provision similarly extends
the deadline for NOX compliance to coincide with the year in which
the extra allowance allocations cease. This provision modifies, for
those categories of units, the general rule for the NOX compliance
deadline.
In addition, section 407(b)(1), which requires the Administrator to
set NOX emission limitations for tangentially fired and dry bottom
wall fired boilers, states:

After January 1, 1995, it shall be unlawful for any unit that is
an affected unit on that date and is of the type listed in this
paragraph to emit nitrogen oxides in excess of the emission rate set
by the Administrator pursuant to (section 407(b)(1)). 42 U.S.C.
7651f(b)(1) (emphasis added).

This provision modifies the general rule for NOX compliance
deadlines, as applied to Phase I units. Under section 407(a), Phase I
units would be subject to the applicable Phase I NOX emission
limitation on the date that they become subject to the Phase I SO2
emission limitation. However, the section 407(b)(1) provision limits
the application of such a NOX compliance deadline to those Phase I
units that, as of January 1, 1995, are subject to the SO2
emissions limitation. All Table A units are subject to the SO2
limitation on January 1, 1995, but only substitution units with
substitution plans approved and effective as of that date meet that
requirement. EPA has interpreted this provision to mean that
substitution units with plans approved and effective after January 1,
1995 are not subject to the NOX emission limitations until January
1, 2000, the date on which they are subject to the SO2 emission
limitation under section 405. 40 CFR 76.1(c). In short, contrary to
some commenters, section 407(a) does not make the section 407(b)(1)
provision redundant; the section 407(b)(1) provision modifies, for some
Phase I units, the general rule established in section 407(a) for
determining NOX compliance deadlines.
In addition, section 407(d) provides for a 15-month extension of
the compliance date for Phase I units that are subject to section
407(b)(1) and meet certain requirements. The extension is provided for
units whose owner or operator shows that the necessary control
technology is not ``in adequate supply to enable its installation and
operation at the unit, consistent with system reliability, by January
1, 1995''. 42 U.S.C. 7651f(d).
Despite these modifications of the general compliance deadline
provision in section 407(a), that general provision still governs
certain categories of units. For example, section 407(b)(2) provides
that the Administrator may revise by January 1, 1997 the NOX
emission limitations, set under section 407(b)(1) for tangentially
fired and dry bottom wall fired boilers. Under section 407(a), any
revised emission limitations apply to units starting on the date on
which they become subject to the SO2 emissions limitation, i.e.,
January 1, 2000 for Phase II units that are allocated allowances under
section 405 and have tangentially fired or dry bottom wall fired
boilers. In order to remove any ambiguity as to whether revised
emission limitations would apply to Phase I units subject to the
original limitations for tangentially fired or dry bottom wall fired
units, there is a proviso at the end of section 407(b)(2) stating that
such Phase I units are not subject to any revised emission limitation.
Similarly, the general compliance deadline provision applies to
Phase II units that are allocated allowances under section 405 and have
other types of coal-fired boilers. Under section 407(a), those units
are subject to the NOX emission limitations for their respective
boiler types starting on the date on which they are subject to the
SO2 emissions limitation, i.e., January 1, 2000.
Some commenters suggested that section 407(a) merely establishes
what units are affected units subject to NOX emission limits and
not the date on which the NOX emission limits apply. However, it
is difficult to see how a section that identifies ``the date'' on which
a unit is ``subject to'' the NOX emission limits could be
interpreted as not setting a NOX compliance deadline. These
commenters attempted to circumvent this language in section 407(a) by
distinguishing between (1) the date on which a unit is ``an affected
unit under section 407'' and is ``subject to'' the NOX emission
limits and (2) the date on which a unit must comply with such emission
limits. Allegedly, a unit can be ``subject to'' an emission limit on a
given date but not required to comply with such emission limit until a
later date.
The commenters' interpretation of section 407(a) renders
meaningless the establishment of a specific date on which a unit
becomes ``subject to'' the

[[Page 67155]]

NOX emission limit. If a unit is ``subject to'' a NOX
emission limit on a given date without being required to meet the limit
on that date, then the specific date on which the unit becomes
``subject to'' the limit is of no consequence. Other sections of title
IV impose the non-emission-limit requirements concerning NOX
(e.g., the requirement to submit a permit application and compliance
plan under section 408(f) and the monitoring requirements of section
412) on affected units but specify different dates by which those
requirements must be met. The subject-to-the-limit date under section
407(a) is irrelevant to the non-emission-limit requirements; in fact,
the compliance dates for the non-emission-limit requirements logically
precede the subject-to-the-limit dates under section 407(a). See, e.g.,
42 U.S.C. 7651g(c)(1)(A) (deadline for submission of Phase I NOX
compliance plans) and (f) (deadline for submission of Phase II NOX
compliance plans) and 42 U.S.C. 7651k(b) (deadline for submission of
Phase I unit monitor installation) and (c) (deadline for Phase II
monitor installation). Yet, Congress carefully crafted language in
section 407(a) to identify specific dates on which units become
``subject to'' the NOX emission limits. Because the commenters'
interpretation essentially reads this carefully crafted language out of
the statute, EPA rejects this interpretation.^{24
---------------------------------------------------------------------------

\24\ While the compliance-date provisions of section 407 are not
well written and are difficult to parse, EPA does not conclude that
the provisions are ambiguous. However, if they were considered
ambiguous, the Agency maintains that its interpretation is
reasonable.
---------------------------------------------------------------------------

In support of their interpretation, the commenters pointed to
language in section 405 with regard to SO2 emissions limitations.
While the first sentence of section 405(a) states that each existing
unit is ``subject to'' the limitations in the section ``(a)fter January
1, 2000'' (42 U.S.C. 7651d(a)(i)), subsequent provisions of section 405
state that ``after January 1, 2000, it shall be unlawful for'' a given
category of units to exceed the applicable SO2 emissions
limitation. See, e.g., 42 U.S.C. 7651d(b)(1). However, despite some
similarity in language in sections 405 and 407, the commenters ignore a
crucial difference between the sections. On its face, the first
sentence of section 405(a)(i), which establishes the January 1, 2000
compliance date for all existing utility units, is a short-hand summary
of the long series of subsequent provisions of section 405. Those
provisions (section 405(b) through (j)) repeat the January 1, 2000
compliance date ^{25 and then lay out in detail the formulas for
allocating allowances for specific categories of existing utility
units. In contrast, as discussed above, section 407(a) sets the general
rule for determining a unit's compliance date for the NOX emission
limitations, and the subsequent provisions in section 407(a) and other
parts of section 407 modify that compliance date for some, but not all,
categories of units.^{26
---------------------------------------------------------------------------

\25\ The repetition of only the January 1, 2000 date in this
context is not a basis for rejecting this interpretation of section
405.
\26\ The commenters also cite language in sections 404 and 412.
The first sentence of section 404(a)(1) states that ``(a)fter
January 1, 1995, each source that includes one or more units listed
in Table A is an affected source under this section'', and the
second sentence adds that ``(a)fter January 1, 1995, it shall be
unlawful for any affected unit'' to exceed the SO^{2 emissions
limitation. 42 U.S.C. 7651c(a)(1). EPA's approach to interpreting
section 407(a) does not render superfluous the second sentence of
section 404(a)(1). The first sentence addresses only Table A units
and explains that a source that includes any such unit is an
affected source. The second sentence addresses all affected units in
Phase I, which includes substitution units under section 404(b) and
(c) and compensating units under section 408(c)(1)(b), and sets
forth in detail their SO2 emissions limitation. Similarly, the cited
language in section 412(e) (i.e., ``(i)t shall be unlawful''
tooperate without complying with section 412) is irrelevant to the
interpretation of section 407. The section 412 language does not
relate at all to emission limitations and refers, in general terms,
to the requirements specified in the other provisions of section
412.
---------------------------------------------------------------------------

Regarding concerns expressed by some commenters about retrofitting
NOX control systems to meet the January 1, 2000 compliance
deadline, actual experience to date in preparing for Phase I indicates
the commenters' anticipated technology shortage may not materialize.
Out of 266 Phase I boilers subject to Phase I NOX emission
limitations, EPA received only 9 requests for the 15-month compliance
extension under section 407(b)(2) of the Act. Moreover, EPA has already
received numerous inquiries and submissions concerning the early
election provision in Sec. 76.8 of the NOX rule, which allows for
compliance with the Phase I NOX emission limitations in 1997 by
units subject to NOX emission limitations starting in Phase II.
This suggests that an adequate supply of NOX control technologies
is available.
In any event, Congress, in section 407(a), set a fixed NOX
compliance date for units subject to the revised emission limits under
section 407(b)(2) of the Group 1 emission limits. Further, while
Congress was obviously aware of the option--which it exercised with
regard to Phase I--of providing for 15-month extensions of the
statutory compliance deadline for Phase II, Congress did not adopt such
a provision. EPA concludes that it therefore lacks the statutory
authority to establish such an extension by regulation.

D. Title IV NOX Program's Relationship to Title I and NOX
Trading Issues

The provisions of title IV, which specify requirements for NOX
reductions in order to control acid deposition, have often been
compared to provisions of title I, which specify requirements for
attainment and maintenance of national ambient air quality standards.
Since NOX reduction is an integral element in achieving the air
quality goals as specified under both titles, general concern has been
expressed as to the consistency, compatibility, and necessity of
potentially duplicative regulatory burdens for those utilities subject
to regulations under both titles.
Further, in the preamble to the proposed rulemaking, EPA solicited
comment on the legal basis and workability of a NOX trading system
under title IV. See 61 FR 1477. NOX trading involves giving credit
for emission reductions that are achieved beyond the minimum required
by applicable emission limitations and allowing credits to be
transferred for use by other entities in meeting their emission
limitations. In the proposal preamble, EPA noted that regional
emissions trading is being considered by the eastern U.S. to address
ozone nonattainment problems in that region. The preamble discussed the
efforts of the Ozone Transport Commission (OTC) to develop a NOX
cap and trade program, which is similar to the Acid Rain SO2 cap
and trade program, for the northeast and of the Ozone Transport
Assessment Group (OTAG) to consider a corresponding NOX program
for the eastern half of the U.S. EPA's guidance on open market trading
was also discussed.
Comment: Utilities commented on the legal necessity to coordinate
compliance deadlines of title IV with other NOX initiatives,
referencing the requirements of Executive Order 12866. The same
commenters encouraged the Agency to tailor its regulations to impose
the least burden on society. Other utility commenters recommended that
EPA establish compliance deadlines by accounting for other regulatory
initiatives. Some commenters favored a title IV NOX compliance
extension option for those boilers also obligated to meet more
stringent title I requirements.
A number of commenters favored the implementation of a NOX
trading program, agreeing that such a program would result in increased
flexibility and allow NOX reduction strategies at least

[[Page 67156]]

cost. At issue is the legality of implementing such a program under
title IV, the possibility for increased emissions as a result of such a
program, and the administrative actions necessary to develop and
implement a successful program. Most commenters recommended a cap and
trade program instead of an ``open market'' trading program.
Response: EPA believes that the NOX reduction requirements
under titles I and IV are not fundamentally inconsistent. As discussed
in section I.B.2 of this preamble, each of the goals of achieving ozone
attainment, reducing acid deposition, and reducing eutrofication will
likely require significant, additional regional reductions in NOX.
The level of needed reductions will likely be much greater than those
achievable under the title IV NOX emission limitations established
under today's final rule. Further, there is no record evidence that the
NOX control technologies on which the title IV NOX emission
limitations are based are incompatible with more advanced technologies
that may be needed to comply with title I. On the contrary, to the
extent title I requires the addition of post-combustion controls on
units with combustion controls under title IV or requires more
intensive use of post-combustion controls installed under title IV, the
requirements of the titles are compatible.
However, EPA believes that NOX reduction initiatives under
title I and title IV should be coordinated, consistent with statutory
requirements, in a way that promotes the goal of achieving necessary
NOX reductions in a cost effective manner. In particular, today's
final rule promotes this goal by including provisions that address the
interaction of efforts under title I to reduce NOX emissions
through cap and trade programs and the establishment of above-discussed
title IV NOX emission limits for Phase II.
With regard to title I, EPA actively supports, with the Department
of Energy, OTAG's efforts to develop a consensus approach for
regulation of NOX emissions in the eastern half of the country in
order to achieve ozone attainment throughout that region. Achievement
of ozone attainment is likely to require additional NOX emission
reductions significantly exceeding the reductions called for under
today's final rule. EPA supports OTAG's goal of reaching consensus
among the States on an approach and having the States voluntarily
implement the approach. However, EPA has indicated that if the States
fail to implement through State Implementation Plans an OTAG-developed
approach for accomplishing ozone attainment throughout the region, EPA
will take action to ensure that State Implementation Plans or Federal
Implementation Plans are put in place to address ozone attainment.
Among the approaches under consideration by OTAG is a region-wide
cap and trade program for NOX emissions. As has been demonstrated
by the Acid Rain Program with regard to SO2 emissions, a cap on
total annual NOX emissions for the region will assure achievement
of the necessary overall NOX emission reductions while trading of
NOX emission authorizations or allowances will enable sources to
reduce the costs of making reductions. EPA therefore believes that a
region-wide cap and trade program is the best method for achieving
necessary NOX reductions.
Utility boilers subject to the NOX emission limitations
established by today's final rule are likely to face significant,
additional NOX reduction requirements (e.g., under an OTAG-
developed approach to achieve regional ozone attainment). If, as EPA
supports, the ozone attainment requirements are implemented in the form
of a cap and trade program and the program results in utility NOX
emission reductions exceeding those that would be required by utilities
complying with today's final rule, EPA maintains that the cap and trade
system should be relied on, in lieu of this rule, to the fullest extent
permissible under the Clean Air Act. Under such an approach, the
reductions achievable under the rule will still be realized but in a
manner that allows utilities to take advantage of the cost savings that
result from flexibility within a cap to trade allowances among
utilities, as well as among boilers owned by a single utility. Relief
from the emission limits set by the rule is appropriately limited to
utility boilers in the State or States covered by the cap and trade
regime.
Under Sec. 76.16 of the final rule, the Administrator retains the
authority to relieve boilers subject to a cap and trade program under
title I from the emission limitations established in today's final rule
under section 407(b)(2) if the Administrator finds that alternative
compliance through the cap and trade program will achieve more overall
NOX reductions from those boilers than will the section 407(b)(2)
emission limitations. Section 76.16 sets forth the criteria that the
cap and trade program must meet in order to ensure that the program
will yield the necessary NOX reductions. Since alternative
compliance will be allowed only if the necessary NOX reductions
will still be made, this approach is consistent with the purposes of
title IV and the Clean Air Act in general.
EPA maintains that it has the authority under section 407(b)(2) to
provide relief from the revised Group 1 limits and the Group 2 limits
where the cap and trade program, replacing those limits, provides for
greater NOX emission reductions and thus greater environmental
protection. With regard to Group 1 boilers not subject to the existing
Group 1 limits until 2000, section 407(b)(2) provides that the
Administrator ``may'' establish more stringent emission limitations if
more effective low NOX burner technology is available. 42 U.S.C.
7651f(b)(2). As discussed above, the Administrator is exercising her
discretion to revise the Group 1 limits because more effective low
NOX burner technology is available and the resulting additional
reductions are cost-effective, represent a reasonable step toward
achieving significant, regional NOX reductions that are likely to
be needed, and are consistent with section 401(b). If it is determined
that, for boilers in certain States, NOX emissions will be lower
under a cap and trade program than under the revised Group 1 limits
(and the Group 2 limits), it is reasonable to conclude that, for those
boilers, it is not necessary to revise the Group 1 limits.
Imposing the revised Group 1 limits on boilers subject to such a
cap and trade program could limit the flexibility of utilities under
the cap and trade program and thereby limit the potential cost savings
from trading. While emissions averaging under section 407(e) provides
some flexibility for a utility to overcontrol at its cheaper-to-control
boilers and undercontrol at its expensive-to-control boilers, averaging
is limited by statute to boilers with the same owner or operator. In
contrast, under a cap and trade program, utilities may overcontrol at
some of their units and sell NOX allowances to other utilities
that may undercontrol at some of their units. It is this greater
flexibility, within a total annual emissions cap, that provides the
opportunity to reduce compliance costs. If boilers subject to a cap and
trade program are relieved of compliance with the revised Group 1
limits, this will likely result in achievement of reductions in a more
cost effective manner than if the revised Group 1 limits continued to
be imposed on these boilers.
Section 407(b)(2) gives the Administrator discretion to make the
existing Group 1 limits more stringent, but not to relax the existing
limits. Thus, the existing Group 1 limits,

[[Page 67157]]

established by the April 13, 1995 regulations, will apply to Group 1
boilers covered by a cap and trade program. While retaining the
existing Group 1 limits means that there may be less flexibility than
if there were no section 407 limits on these boilers, relieving the
boilers of the revised Group 1 limits still results in some increased
flexibility and therefore is likely to yield cost savings.
Similarly, with regard to Group 2 boilers, section 407(b)(2)
requires that the Administrator, taking account of environmental and
energy impacts, set emission limits that are based on the reductions
achievable using available control technologies with cost effectiveness
comparable to LNBs on Group 1 boilers. In setting the Group 2 limits,
the Administrator relied in part on the additional NOX reductions
that will result and determined that these reductions are cost-
effective, are a reasonable step toward achieving necessary regional
NOX reductions, and are consistent with section 401(b). Again, if
greater reductions from boilers in a State or group of States can be
achieved through a cap and trade program in a more cost effective
manner than through imposition of Group 2 limits (and revised Group 1
limits) on the boilers, it is reasonable to relieve those units of the
Group 2 limits. Taking account of these environmental and cost impacts,
the Administrator can, in such circumstances, allow the cap and trade
program to apply in lieu of the Group 2 limits.
Section 76.16 of the final rule establishes the procedural and
substantive requirements for relieving boilers of the revised Group 1
limits and the Group 2 limits. The rule itself does not grant or
require such relief. Under this section, the Administrator has the
discretion to act, on a case-by-case basis consistent with the
established procedures, to provide such relief if he or she determines
that the substantive requirements are met. As noted above, EPA supports
the cap and trade approach for achieving necessary reductions of
regional NOX emissions.
Consideration of whether to relieve boilers under a cap and trade
program of the section 407(b)(2) limits may be initiated either by a
petition by a State or group of States or on the Administrator's own
motion. Because of the large number of utility companies and coal-fired
boilers and the complexities that would result if relief from the
section 407(b)(2) limits were considered on a boiler-by-boiler or
utility-by-utility basis, the rule requires that any request for, and
any determination whether to grant, such relief be made for an entire
State or entire group of States. The cap and trade program involved
must therefore cover, for an entire State or group of States, all the
units for which relief is sought or considered. This approach has the
added benefit of making it more likely that the cap and trade program
involved will be broad enough to provide a robust NOX allowance
market.
Further, the cap and trade program may be established through State
Implementation Plans or Federal Implementation Plans covering the
States involved. The relief from section 407(b)(2) limits is
potentially available whether the cap and trade program is adopted
voluntarily by the OTAG States or imposed by EPA under title I. State
petitions for such relief may be submitted, and the Administrator's
consideration of whether to grant relief may commence, before the State
Implementation Plans or Federal Implementation Plans or revised Plans
establishing the cap and trade program are final and federally
enforceable. This allows the process of deciding whether to grant
relief from the section 407(b)(2) limits to be coordinated with the
processing of these Plans. However, relief may not be granted until the
Plans establishing the cap and trade program are actually in place,
i.e., are final and federally enforceable.
The substantive requirements that must be met by the cap and trade
program are essentially the same whether the program is implemented
through a State Implementation Plan or a Federal Implementation Plan
and whether the consideration of relief from section 407(b)(2) limits
is initiated by petition or on the Administrator's own motion. The
Administrator has discretion to grant relief only if the cap and trade
program meets certain requirements aimed at ensuring that the necessary
NOX reductions will still be achieved and that the program creates
an opportunity for cost savings. First, each unit that is in the State
or group of States and that would otherwise be subject to title IV
NOX emission limits must be subject to a cap on total annual
NOX emissions or two or more seasonal caps that together limit
total annual NOX emissions. This allows for a cap and trade
program with different caps during different seasons, e.g. a summer cap
aimed primarily at ozone attainment and a cap for the rest of the year.
Second, the units must be allowed to trade authorizations to emit
NOX within the cap. This element is what provides utilities the
flexibility to reduce the costs of making the reductions necessary for
achievement of the cap.
Third, the units must surrender authorizations to emit NOX
(i.e., NOX allowances) to account for their NOX emissions
during the period covered by the cap. In addition, the units must be
required to surrender allowances to account for the NOX emission
consequences of reducing utilization at the generation facilities
covered by the cap and shifting utilization to generation facilities
not covered by the cap. This addresses a problem that potentially
arises whenever a cap and trade program covers some but not all
generation facilities. If a utility can reduce the use of a unit
covered by the cap and offset the resulting reduced generation with
generation at a unit not covered by the cap, circumvention of the cap
may result. Because of the offsetting utilization changes at the two
units, the atmosphere may receive the same total amount of NOX
emissions from the units. In addition, if allowances are used only to
account for emissions by the unit subject to the cap, the unused
allowances are available for use by other units subject to the cap. The
net result is that the total emissions in the atmosphere (including
emissions by the reduced-utilization unit, the increased-utilization
unit, and the units acquiring and using the unused allowances) may
exceed the cap. This is analogous to the reduced utilization problem in
the SO2 cap and trade program in Phase I, during which most units
in the U.S. are not covered by the requirement to hold allowances for
their SO2 emissions. See 58 FR 60950, 60951 (November 18, 1993).
Section 408(c)(1)(B) of the Act and Secs. 72.91 and 72.92 of the
regulations require SO2 allowance surrender to account for the
emissions consequences of reduced utilization. See 60 FR 18462-63
(April 11, 1995).
The NOX cap and trade program must include appropriate
allowance surrender provisions to address this problem by requiring
NOX allowance surrender to the extent necessary to account for the
increased NOX emissions, if any, at generation facilities (i.e.,
combustion devices serving generators that produce electricity for
sale) not covered by the cap. EPA recognizes that any allowance
surrender provisions can only approximate the emissions consequences of
shifting utilization from within-the-cap facilities to outside-the-cap
facilities. See 60 FR 18466. EPA will evaluate NOX allowance
surrender provisions in light of this limitation and of the importance
of adopting provisions that are workable and not overly complicated.
Moreover, EPA believes that effective NOX

[[Page 67158]]

allowance surrender provisions can be developed that are less complex
than those in place for reduced utilization in the SO2 allowance
trading program. EPA also notes that the larger the group of States
covered by the cap and the more comprehensive the coverage by the cap
of generation facilities in such States, the smaller the potential for
shifting utilization from units under the cap to units outside the cap.
For example, the problem of shifting utilization, and therefore the
associated allowance surrender, will be significantly smaller for a cap
and trade program covering the generation facilities in the entire 37-
State OTAG area.
Fourth, the total annual emissions by all units that are subject to
the cap and that would otherwise be subject to the section 407(b)
limits must be less than the total annual emissions of such units if
they were subject to the section 407(b) limits (without adjusting for
alternative emission limitations and averaging). In determining the
units' total annual emissions under the section 407(b) limits, the
effect of alternative emission limitations--which reduce the amount of
NOX reductions achieved and whose precise levels for individual
units would be difficult if not impossible to project--will not be
considered. Requiring the cap and trade program to yield fewer total
annual emissions than the section 407(b) limits without considering
alternative emission limitations will help ensure that the
environmental benefits of the section 407(b)(2) are preserved under the
cap and trade program. See Economic Incentive Program Rules, 59 FR
16690, 16694 (April 7, 1994).
In addition, the effect of averaging will not be considered because
of the following reasons. If averaging is limited to units that are
also subject to the cap and trade program, averaging is unnecessary to
separately consider because it would not affect the total emissions of
the averaging units under the section 407(b) limits. See 60 FR 18756
(explaining that average emission rate of units in averaging plan
cannot exceed average emission rate if they had operated in compliance
with Secs. 76.5, 76.6, or 76.7 limits). If averaging includes units not
subject to the cap and trade program and those units select emission
rates under the plan that exceed the standard limits, this could have
the effect of understating the reductions achieved under the title IV
limits.
In order to avoid disputes over what year to use in comparing total
annual emissions under the cap and trade program and the section 407(b)
limits, the rule specifies how to select the year. The approach in the
rule ensures that actual data is available for such year.
In addition to the substantive requirements for relieving units of
the section 407(b)(2) limits, the rule addresses the procedures that
the Administrator must follow in determining whether to exercise his or
her discretion to grant relief. The Administrator must make this
determination in a draft decision, subject to notice and comment, and
then in a final decision. The draft decision must set forth not only
the determination and its basis but also the specific procedures that
will govern the issuance and any appeal of the final decision. The rule
imposes certain minimum procedural provisions that must be set forth in
the draft decision These procedural requirements are closely modeled
after the procedures in part 72 of the Acid Rain regulations for the
issuance of Acid Rain permits.
Notice of the draft decision must be provided by service on
interested persons and on the air pollution control agencies in States
that may be affected by the draft decision. This includes not only the
States in which the units involved are located, but also neighboring
States. The description in the rule of the neighboring States (and
neighboring, federally recognized Indian Tribes) on which notice must
be served is based on the definition of ``affected States'' in the
recently issued part 71 regulations, which govern federal issuance of
title V operating permits. See 61 FR 34202, 34229 (July 1, 1996).
Notice must also be provided in the Federal Register and equivalent
State publications. Notice in newspapers in general circulation in the
areas in which the units involved are located is not required. EPA
maintains that newspaper notice in these circumstances is unnecessary,
particularly since any NOX cap and trade program being evaluated
will have to go through notice and comment in order to be included in a
State Implementation Plan or Federal Implementation Plan. Newspaper
notice would also be unworkable in light of the number of units and
States (e.g., all Phase II, Group 1 and Group 2 units in the 37-State
OTAG area) that could be involved.
The provisions for public comment period and public hearing are
essentially the same as those in part 72. Notice must be given of the
final decision in the same manner as notice of the draft decision. Any
appeals of the final decision are governed by part 78, which governs
other Acid-Rain-related decisions of the Administrator.
Finally, after the Administrator decides to relieve units of the
section 407(b)(2) limits in light of a given cap and trade program, the
State Implementation Plan or Federal Implementation Plan could
potentially be revised in a way that may affect the cap and trade
program and the basis for the Administrator's decision. In such
circumstances, the Administrator may reconsider the decision to grant
relief from the section 407(b)(2) limits. The ability to reconsider is
explicitly preserved in the rule in order to ensure that the
environmental benefit of the section 407(b)(2) limits that would
otherwise apply to the units involved continues to be realized.
A number of commenters addressed whether NOX trading should be
established, along with the emission limits and other provisions of
part 76, as part of the title IV NOX program itself. Although many
commenters supported NOX trading and urged generally that EPA has
legal authority to implement a title IV NOX trading program, only
limited specific legal justification was provided. One commenter argued
that EPA lacks such title IV legal authority while another suggested
that means of accounting for reductions below the title IV emission
limits be established so that credit for such excess reductions could
be used in NOX trading under title I. Further, some commenters
supported title IV NOX trading following the Open Market Trading
approach with discrete emission reduction credits while other
commenters supported a title IV NOX cap and trade program similar
to the SO2 cap and trade program and opposed the Open Market
Trading approach. One commenter suggested that credits be given for
excess reductions below some target emission rate levels (lower than
the title IV emission limits) and that utilities be allowed to use
those credits to meet the title IV emission limits.
In light of the comments, EPA has decided to address--through the
above-discussed Sec. 76.16--the coordination of cap and trade programs
established under title I with the emission limits established under
title IV and not to address NOX trading under title IV itself at
this time. Substantial questions have been raised concerning the
authority to establish NOX trading under title IV because of
specific language in, and the legislative history of, section 407. See,
e.g., 59 FR 13561-62. These concerns do not apply to title I, under
which significant progress has been made toward establishing NOX
cap and trade programs, e.g., by the OTC and OTAG. The approach under
Sec. 76.16 will build on and encourage these efforts by integrating
title I cap and trade programs with the title IV emission

[[Page 67159]]

limit program in a way that achieves necessary NOX reductions in a
cost effective manner. Further, the approach in Sec. 76.16 avoids
creating multiple, potentially overlapping NOX cap and trade
programs under different sections of the Clean Air Act. As already
noted, EPA recognizes that, in cases where the Administrator exercises
his or her full discretion under Sec. 76.16, Group 1 boilers subject to
a title I cap and trade program will still be subject to the existing
Group 1 limits under title IV. To the extent that this significantly
limits the benefits of cap and trade, the Agency may consider
additional actions, consistent with the Clean Air Act, that will enable
affected units to meet NOX emission limitation requirements by
using cap and trade programs that provide at least equivalent
environmental benefits.

IV. Administrative Requirements

A. Docket

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

B. Executive Order 12866

Under Executive Order 12866 (58 FR 51735 (October 4, 1993)), the
Agency must determine whether the regulatory action is ``significant''
and therefore subject to Office of Management and Budget (OMB) review
and the requirements of the Executive Order. The Order defines
``significant regulatory action'' as one that is likely to result in a
rule that may:

(1) Have an annual effect on the economy of $100 million or more
or adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities;
(2) Create a serious inconsistency or otherwise interfere with
an action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements,
grants, user fees, or loan programs or the rights and obligations of
recipients thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.

Pursuant to the terms of Executive Order 12866, it has been
determined that this rule is a ``significant regulatory action''
because it will have an annual effect on the economy of approximately
$204 million. As such, this action was submitted to OMB for review. Any
written comments from OMB to EPA and any written EPA response to those
comments are included in the docket. The docket is available for public
inspection at the EPA's Air Docket Section, which is listed in the
ADDRESSES section of this preamble. A detailed breakdown of the total
cost and the corresponding NOX reductions is presented in Table
17.

Table 17.--Approx. Phase II NOX Rule Cost and Reductions by Boiler Type
[Including Averaging and AELs]
----------------------------------------------------------------------------------------------------------------
Cost-
Boiler type NOX reduction Total cost effectiveness
(tons/year) ^{27 (annualized $) ($/ton)
----------------------------------------------------------------------------------------------------------------
Dry Bottom Wall-Fired........................................... 90,000 22,000,000 244
Tangentially Fired.............................................. 30,000 18,000,000 600
Cell Burner..................................................... 420,000 33,000,000 79
Cyclone (>155MWe)............................................... 225,000 89,000,000 396
Wet Bottom (>65MWe)............................................. 80,000 35,000,000 438
Vertically Fired................................................ 45,000 7,000,000 156
Total....................................................... 890,000 204,000,000 229
----------------------------------------------------------------------------------------------------------------
\27\ Reductions projected, not true contribution of the emission limitations for each boiler type to total
reductions. With averaging, the more cost-effective boiler types to control will reduce more than required to
meet their individual emission limits and the less cost-effective boiler types will reduce less than required
by their individual limits.

EPA does not anticipate major increases in prices, costs, or other
significant adverse effects on competition, investment, productivity,
or innovation or on the ability of U.S. enterprises to compete with
foreign enterprises in domestic or foreign markets due to the final
regulations.
Commenters have expressed general concern regarding certain aspects
of the Regulatory Impact Analysis to the proposed rule. Issues raised
include the concern that: (1) The RIA failed to examine the costs and
impacts of a wider variety of options; (2) EPA underestimated the
number and costs of AEL applications; (3) costs for the proposed
revised Group 1 limits are less than costs specified in the April 13,
1995 rule; and (4) the RIA does not adequately address the risks of
decreased marketability of flyash.
In the RIA for the final rule, EPA analyzed two additional options
which considered economic and environmental impacts of the final rule,
totaling five options. These two additional options include: (1) No
revisions to the Phase I, Group 1 emission limits; and (2) no emission
limits for wet bottom or cyclone boilers. The inclusion of these two
options addresses comments that more options should be investigated in
the RIA.
In all the options considered, EPA assigned a cost to the AEL
process of $225,000. This cost is consistent with utility projections
and projections made during the April 13, 1995 NOX rule. The cost
of controls used in the RIA were developed in reports presented in
docket items IV-A-1, IV-A-2, IV-A-4, IVA-6, and V-B-1. These reports
were produced from previous EPA studies and comments received during
the comment period of the proposed rule. EPA's model projects an
additional 50 AELs for Group 1 and Group 2, as a result of today's
final rule.
The RIA does not attribute a cost to flyash marketability because:
(1) The revision of the Group 1 limits is based on the same basic
technology (i.e., low NOX burner technology) already considered in
the April 13, 1995 rule and does not impose any additional NOX
control technology requirements

[[Page 67160]]

relevant to flyash; (2) the impacts to flyash marketability from Group
2 boiler limits are minimal since the majority of these boilers sell
bottom ash, not flyash; and (3) as discussed in the proposed rule (61
F.R. 1467), there are currently low cost technologies that minimize, or
in some cases eliminate, unburned carbon (the main by-product affecting
flyash marketability) from flyash.
In assessing the impacts of a regulation, it is important to
examine (1) the costs to the regulated community, (2) the costs that
are passed on to customers of the regulated community, and (3) the
impact of these cost increases on the financial health and
competitiveness of both the regulated community and their customers.
The costs of this regulation to electric utilities are generally very
small relative to their annual revenues. (However, the relative amount
of the costs will definitely vary in individual cases.) Moreover, EPA
expects that most or all utility expenses from meeting NOX
requirements will be passed along to ratepayers. When fully implemented
in the year 2000, consumer electric utility rates are expected to rise
by 0.20 percent on average due to this rulemaking. Consequently, the
regulations are not likely to have an impact on utility profits or
competitiveness.

C. Unfunded Mandates Act

Section 202 of the Unfunded Mandates Reform Act of 1995 (``Unfunded
Mandates Act'') requires that the Agency must prepare a budgetary
impact statement before promulgating a rule that includes a federal
mandate that may result in expenditure by State, local, and tribal
governments, in the aggregate, or by the private sector, of $100
million or more in any one year. The budgetary impact statement must
include: (1) Identification of the federal law under which the rule is
promulgated; (2) a qualitative and quantitative assessment of
anticipated costs and benefits of the federal mandate and an analysis
of the extent to which such costs to State, local, and tribal
governments may be paid with federal financial assistance; (3) if
feasible, estimates of the future compliance costs and any
disproportionate budgetary effects of the mandate; (4) if feasible,
estimates of the effect on the national economy; and (5) a description
of the Agency's prior consultation with elected representatives of
State, local, and tribal governments and a summary and evaluation of
the comments and concerns presented. Section 203 requires the Agency to
establish a plan for obtaining input from and informing, educating, and
advising any small governments that may be significantly or uniquely
impacted by the rule.
Many utilities have expressed concern that EPA did not consider for
the proposed rule all possible options, including the option of ``no
revision'' for Group 1 boilers. Concern was also expressed regarding
the discrepancy between the budgetary impact statement which is based
on the proposed rule's preferred Option 2-80 (which excludes cyclones
with a generating capacity below 80 megawatts), and the proposed rule
language which did not explicitly exempt cyclone boilers below 80
megawatts. Others questioned the appropriateness of cost data and
whether EPA properly addressed State and local government issues.
For the final rule, EPA investigated new ways to minimize the
impact of the final rule on State, local government, and privately
owned utilities while carrying out the requirements of section 407.
These investigations, prompted by comments received during the public
comment period and by consultations with affected entities include: (1)
Investigation of what, if any, requirements of the rule imposed an
inordinately high burden on any specific utility; and (2) investigation
of incremental environmental and economic impacts of varying the size
cutoff for wet bottom and cyclone boilers affected by this rulemaking.
The results of these investigations were used in developing the
emission limits and applicability requirements that are now being
promulgated.
Under section 205 of the Unfunded Mandates Act, EPA must identify
and consider a reasonable number of regulatory alternatives before
promulgating a rule for which a budgetary impact statement must be
prepared. The Agency must select from those alternatives the most cost-
effective and least burdensome alternative that achieves the objectives
of the rule unless the Agency explains why this alternative is not
selected or unless the selection of this alternative is inconsistent
with law. In the final rule, the Agency discusses several regulatory
options and their associated costs. As discussed above, the Agency has
considered other regulatory options beyond the options discussed in the
proposal.
In the final rule, EPA expands the number of regulatory options
that are considered and selects the one that is the least cost, most
cost-effective, or least burdensome alternative that is consistent with
the objectives of the rule. Option 1 is the revision of the Group 1
emission limits and no establishment of Group 2 emission limits. Option
2 is no revision of Group 1 limits and the establishment of limits for
all Group 2 boilers, except stokers and fluidized bed combustion (FBC)
boilers. Option 3 is the revision of the Group 1 limits and the
establishment of limits for all Group 2 boilers, except stokers and FBC
boilers. Option 4 is the revision of the Group 1 limits and the
establishment of limits for all Group 2 boilers except cyclones with
capacity of 155 MWe or less, wet bottoms with capacity of 65 MWe of
less, stokers, and FBC boilers. Option 5 is the revision of the Group 1
limits and the establishment of limits for all Group 2 boilers except
cyclones, wet bottoms, stokers, and FBCs.
EPA has determined that of these options, only Option 4 is
consistent with the purposes of the rule. Under section 407(b)(2) of
the Act, the Administrator may revise the Group 1 limits if more
effective low NOX burner technology is available for Group 1
boilers. If EPA determines that more effective low NOX burner
technology is available, section 407(b)(2) does not specify the
criteria to be used in determining whether to adopt more stringent
Group 1 limits. However, consistent with the environmental purposes of
title IV and the Clean Air Act in general and in light of the likely
need to make significant, regional NOX reductions, EPA has decided
that it should exercise its discretion and that the objective of the
rule should be to adopt more stringent Group 1 limits. Consequently,
regulatory options under which the Group 1 limits would not be revised
(i.e., Option 2) are inconsistent with the objectives of the rule.
Further, under section 407(b)(2), the Administrator must set emission
limits for all Group 2 boilers based on degree of reduction achievable
using the best system of continuous emission reduction and with
comparable cost to low NOX burner technology on Group 1 boilers.
In setting the limits, available technology, costs, and energy and
environmental impacts must be considered. EPA has determined that there
are available control technologies of comparable cost-effectiveness to
that of low NOX burner technology on Group 1 boilers for cell
burners, cyclones greater than 155 MWe, wet bottoms greater than 65
MWe, and vertically fired boilers (except for arch-fired boilers) and
that the objective of the rule is to set limits for such boilers.
Consequently, regulatory options that do not set limits for each of
these Group 2 boiler categories (e.g., Options 1 and 5) or that set
limits for all cyclones and

[[Page 67161]]

wet bottoms (e.g., Options 2 and 3) are not consistent with the
objectives of the rule.
EPA concludes, for the reasons discussed above, that Option 4 is
the only option that is consistent with the objectives of the rule. EPA
also notes that the size cutoffs for cyclones and wet bottoms were
established both to limit the boilers covered to the group for which
the applicable control technologies were of comparable cost
effectiveness to LNBs on Group 1 boilers and to limit the number of
municipally owned boilers covered by the emission limits. While the
cutoffs could have been set at lower levels if only comparability of
cost effectiveness were considered, the cutoffs were adjusted in order
to exempt certain municipally owned boilers that were close to the
potential cutoff points, while having only a minimal impact on the
total amount of NOX reductions that would be realized. Adopting
lower cutoffs would increase the impact of the rule on municipal
utilities and result in limited additions in NOX reductions. Under
these circumstances, EPA maintains that, in selecting Option 4, the
Agency is choosing the least costly, most cost effective, or least
burdensome alternative that is consistent with the objectives of the
rule.
In addition, EPA notes that, considering the alternative approaches
under the Clean Air Act for reducing NOX emissions by utility and
non-utility sources, Option 4 represents the most cost effective
alternative. Having determined that significant, regional reductions of
NOX emissions are likely to be needed, EPA compared the cost
effectiveness of alternative approaches for reducing NOX
emissions, i.e., the cost effectiveness of achieving reductions by
coal-fired utility boilers under Option 4, by coal-, oil-, or gas-fired
utility boilers using more advanced control technologies than under
Option 4, by non-utility stationary sources, and by mobile sources. The
reductions under Option 4 are the most cost effective of these
alternative approaches and represent a reasonable step toward achieving
necessary, regional NOX reductions.
Because this final rule is estimated to result in the expenditure
by State, local, and tribal governments and the private sector, in
aggregate, of over $100 million per year starting in 2000, EPA has
addressed budgetary impacts in the Regulatory Impact Analysis, as
summarized below.
The final rule is promulgated under section 407(b)(2) of the Clean
Air Act. Total expenditures resulting from the rule are estimated at
approximately $204 million per year starting in 2000. There are no
federal funds available to assist State, local, and tribal governments
in meeting these costs. However, title V of the Act authorizes State,
local, and tribal permitting authorities to collect permitting fees
from utilities to cover all costs of developing and issuing title V
operating permits, including Acid Rain provisions reflecting standard
NOX emission limits, AELs, and emissions averaging. Prudent costs
incurred in complying with this rule may be recovered by utilities by
passing them on to ratepayers. There are important benefits from
NOX emission reductions because atmospheric emissions of NOX
have significant adverse impacts on human health and welfare and on the
environment.
The final rule does not have any disproportionate budgetary effects
on any particular region of the nation, any State, local, or tribal
government, or urban or rural or other type of community ^{28.
Further, the rule will result in only a minimal increase in average
electricity rates. Moreover, the rule will not have a material effect
on the national economy.
---------------------------------------------------------------------------

\28\ As shown in EPA's Unfunded Mandates Act Analysis, as a
result of this proposal, State and municipality owned boilers
experience average control costs of 0.024 mills/kWh while the
national average control costs are 0.125 mills/kWh.
---------------------------------------------------------------------------

In developing the final rule, EPA evaluated the public comments and
concerns, and to the extent consistent with section 407 of the Clean
Air Act, those comments and concerns are reflected in the final rule.
These procedures ensured State and local governments an opportunity to
give meaningful and timely input and to obtain information, education,
and advice regarding compliance. Additionally, EPA solicited comments
from the 25 State and municipality owned utilities, as well as elected
officials of their respective State and local governments. They were
provided a summary of the EPA proposal and the estimated impacts.
As described in EPA's analysis (see docket item V-B-1 (RIA,
Unfunded Mandates Reform Act Analysis for the Nitrogen Oxides Emission
Reduction Program Under the Clean Air Act Amendments Title IV)), the
costs to some small municipally-owned or State-owned utilities, are
somewhat higher than for large utilities, which tend to be privately
held. However, the analysis indicates that the cost increase is
relatively small even for utilities owned by municipalities and States.

D. Paperwork Reduction Act

This final rule does not impose any information collection
requirements subject to the Paperwork Reduction Act, (44 U.S.C. 3501,
et seq.) not already required under the current provisions of part 75
and part 76 over the next three years. Before the year 2000, the year
in which these emission limits take effect, EPA will submit an
Information Collection Request renewal to OMB. The additional burden
hours, if any, will reflect the compliance of the Group 2 boilers
subject to this rule.

E. Regulatory Flexibility Act

The Regulatory Flexibility Act (5 U.S.C. 601, et seq.) requires EPA
to consider potential impacts of proposed regulations on small
entities. It has been determined that this is a major rulemaking
because it will have an annual effect on the economy of approximately
$204 million.
Some commenters question the accuracy of cost and impact data, as
well as whether EPA should exempt, or moderate the burden on, certain
units that would have difficulty complying with the proposed limits,
such as older or smaller units. As elaborated in the Small Entity
Screening Analysis for the final rule, (see docket item V-B-1), EPA
investigated new ways to minimize the impact of the final rule on
State, local government, and privately owned utilities while carrying
out the requirements of section 407. These investigations, prompted by
comments received during the public comment period and by consultations
with the affected industries, included investigation of what, if any,
requirements of the rule imposed an inordinately high burden on any
specific small business entity. The results of this investigation were
used in developing the emission limits and applicability requirements
that are now being promulgated.
Under the Regulatory Flexibility Act, a small business is any
``small business concern'' as identified by the Small Business
Administration under section 3 of the Small Business Act. As of January
1, 1991, the Small Business Administration had established the size
threshold for small electric services companies at 4 million megawatt
hours per year.
Of the estimated 700 small utilities (including small investor-
owned, cooperative, or municipally owned utilities) in the U.S., 64 are
subject to part 76, and of these, only 15 are expected to incur any
compliance costs as a result of this final rule. For this reason alone,
this rule will not have

[[Page 67162]]

significant adverse impact on a substantial number of small entities.
EPA notes that it also analyzed in detail the potential impact of the
final rule on various financial measures of the 15 adversely impacted
small utilities' profitability and short- and long-term solvency. The
results show that, though the financial impact of compliance with this
rule for the 15 small utilities is greater than that for medium and
large utilities, the impact of the rule, as reflected in changes in
various financial measures (such as return on equity and return on
assets), is not significant (see docket item V-B-1 (RIA, EPA's Small
Entity Screening Analysis)).
EPA has determined that it is not necessary to prepare a regulatory
flexibility analysis in connection with this final rule. EPA has
determined that this rule will have no significant adverse effect on a
substantial number of small entities.

F. Submission to Congress and the General Accounting Office

Under 5 U.S.C. 801(a)(1)(A) as added by the Small Business
Regulatory Enforcement Fairness Act of 1996, EPA submitted a report
containing this rule and other required information to the U.S. Senate,
the U.S. House of Representatives and the Comptroller General of the
General Accounting Office prior to publication of the rule in today's
Federal Register. This rule is a ``major rule'' as defined by 5 U.S.C.
804(2).

G. Miscellaneous

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

List of Subjects in 40 CFR Part 76

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

Dated: December 10, 1996.
Carol M. Browner,
Administrator.

PART 76--[AMENDED]

1. The authority citation for part 76 continues to read as follows:

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

2. Section 76.2 is amended by revising the definition of ``coal-
fired utility unit'' and ``wet bottom'' and adding, in alphabetical
order, definitions for ``arch-fired boiler'', ``boiler capacity'',
``coal-fired utility boiler'', ``combustion controls'', ``fluidized bed
combustor boiler'', ``maximum continuous steam flow at 100% of load''
``non-plug-in combustion controls'', ``plug-in combustion controls'',
and ``vertically fired boiler'', to read as follows:

Sec. 76.2 Definitions.

* * * * *
Arch-fired boiler means a dry bottom boiler with circular burners,
or coal and air pipes, oriented downward and mounted on waterwalls that
are at an angle significantly different from the horizontal axis and
the vertical axis. This definition shall include only the following
units: Holtwood unit 17, Hunlock unit 6, and Sunbury units 1A, 1B, 2A,
and 2B. This definition shall exclude dry bottom turbo fired boilers.
* * * * *
Coal-fired utility unit means a utility unit in which the
combustion of coal (or any coal-derived fuel) on a Btu basis exceeds
50.0 percent of its annual heat input during the following calendar
year: for Phase I units, in calendar year 1990; and, for Phase II
units, in calendar year 1995 or, for a Phase II unit that did not
combust any fuel that resulted in the generation of electricity in
calendar year 1995, in any calendar year during the period 1990-1995.
For the purposes of this part, this definition shall apply
notwithstanding the definition in Sec. 72.2 of this chapter.
* * * * *
Combustion controls means technology that minimizes NOX
formation by staging fuel and combustion air flows in a boiler. This
definition shall include low NOX burners, overfire air, or low
NOX burners with overfire air.
* * * * *
Maximum Continuous Steam Flow at 100% of Load means the maximum
capacity of a boiler as reported in item 3 (Maximum Continuous Steam
Flow at 100% Load in thousand pounds per hour), Section C ( design
parameters), Part III (boiler information) of the Department of
Energy's Form EIA-767 for 1995.
* * * * *
Non-plug-in combustion controls means the replacement, in a cell
burner boiler, of the portions of the waterwalls containing the cell
burners by new portions of the waterwalls containing low NOX
burners or low NOX burners with overfire air.
* * * * *
Plug-in combustion controls means the replacement, in a cell burner
boiler, of existing cell burners by low NOX burners or low
NOX burners with overfire air.
* * * * *
Vertically fired boiler means a dry bottom boiler with circular
burners, or coal and air pipes, oriented downward and mounted on
waterwalls that are horizontal or at an angle. This definition shall
include dry bottom roof-fired boilers and dry bottom top-fired boilers,
and shall exclude dry bottom arch-fired boilers and dry bottom turbo-
fired boilers.
* * * * *
Wet bottom means that the ash is removed from the furnace in a
molten state. The term ``wet bottom boiler'' shall include: wet bottom
wall-fired boilers, including wet bottom turbo-fired boilers; and wet
bottom boilers otherwise meeting the definition of vertically fired
boilers, including wet bottom arch-fired boilers, wet bottom roof-fired
boilers, and wet bottom top-fired boilers. The term ``wet bottom
boiler'' shall exclude cyclone boilers and tangentially fired boilers.

Sec. 76.5 [Amended]

3. Section 76.5 is amended by remaing paragraph (g).
4. Section 76.6 is revised to read as follows:

Sec. 76.6 NOX emission limitations for Group 2 boilers.

(a) Beginning January 1, 2000 or, for a unit subject to section
409(b) of the Act, the date on which the unit is required to meet Acid
Rain emission reduction requirements for SO2, the owner or
operator of a Group 2, Phase II coal-fired boiler with a cell burner
boiler, cyclone boiler, a wet bottom boiler, or a vertically fired
boiler shall not discharge, or allow to be discharged, emissions of
NOX to the atmosphere in excess of the following limits, except as
provided in Secs. 76.10 or 76.11:
(1) 0.68 lb/mmBtu of heat input on an annual average basis for cell
burner boilers. The NOX emission control technology on which the
emission limitation is based is plug-in combustion controls or non-
plug-in combustion controls. Except as provided in Sec. 76.5(d), the
owner or operator of a unit with a cell burner boiler that installs
non-plug-in combustion controls after November 15, 1990 shall comply
with the emission limitation applicable to cell burner boilers. The
owner or operator of a unit with a cell burner that installs non-plug-
in combustion controls on or before November 15, 1990 shall comply with
the applicable emission limitation for dry bottom wall-fired boilers.

[[Page 67163]]

(2) 0.86 lb/mmBtu of heat input on an annual average basis for
cyclone boilers with a Maximum Continuous Steam Flow at 100% of Load of
greater than 1060 lb/hr. The NOX emission control technology on
which the emission limitation is based is natural gas reburning or
selective catalytic reduction.
(3) 0.84 lb/mmBtu of heat input on an annual average basis for wet
bottom boilers, with a Maximum Continuous Steam Flow at 100% of Load of
greater than 450 lb/hr. The NOX emission control technology on
which the emission limitation is based is natural gas reburning or
selective catalytic reduction.
(4) 0.80 lb/mmBtu of heat input on an annual average basis for
vertically fired boilers. The NOX emission control technology on
which the emission limitation is based is combustion controls.
(b) The owner or operator shall determine the annual average
NOX emission rate, in lb/mmBtu, using the methods and procedures
specified in part 75 of this chapter. 5. Section 76.7 is amended by
adding paragraphs (a) and (b) to read as follows:

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

(a) Beginning January 1, 2000, the owner or operator of a Group 1,
Phase II coal-fired utility unit with a tangentially fired boiler or a
dry bottom wall-fired boiler shall not discharge, or allow to be
discharged, emissions of NOX to the atmosphere in excess of the
following limits, except as provided in Secs. 76.8, 76.10, or 76.11:
(1) 0.40 lb/mmBtu of heat input on an annual average basis for
tangentially fired boilers.
(2) 0.46 lb/ mmBtu of heat input on an annual average basis for dry
bottom wall-fired boilers (other than units applying cell burner
technology).
(b) The owner or operator shall determine the annual average
NOX emission rate, in lb/mmBtu, using the methods and procedures
specified in part 75 of this chapter.
6. Section 76.8 is amended by: removing from paragraph (a)(2) the
words ``any revised NOX emission limitation for Group 1 boilers
that the Administrator may issue pursuant to section 407(b)(2) of the
Act'' and adding, in their place, the words ``Sec. 76.7''; removing
from paragraph (a)(5) the words ``Secs. 76.5(g) and if revised emission
limitations are issued for Group 1 boilers pursuant to section
407(b)(2) of the Act,''; and removing from paragraphs (e)(3)(iii)(A)
and (B) the words ``Sec. 76.5(g) and, if revised emission limitations
are issued for Group 1 boilers pursuant to section 407(b)(2) of the
Act,''.

Sec. 76.10 [Amended]

7. Section 76.10 is amended by removing from paragraph (f)(1)(iii)
the words ``Secs. 76.5(g) or 76.6'' and adding, in their place, the
words ``Secs. 76.6 or 76.7''.
8. Section 76.16 is added to read as follows:

Sec. 76.16 Alternative compliance.

(a)(1) A State or group of States may submit a petition requesting
that the Administrator, or the Administrator, on his or her own motion,
may:
(i) Require the owners or operators of the Group 1, Phase II coal-
fired utility units with a tangentially fired boiler or a dry bottom
wall fired boiler in the State or the group of States to be subject to
the applicable emission limitations for NOX in Sec. 76.5, in lieu
of the applicable emission limitations for NOX in Sec. 76.7; and
(ii) Provide that the owners or operators of the Group 2 coal-fired
utility units with a cell burner boiler, cyclone boiler, wet bottom
boiler, or vertically fired boiler in the State or the group of States
are not subject to the applicable emission limitations for NOX in
Sec. 76.6.
(2) A petition under paragraph (a)(1) of this section must
demonstrate that the requirements in paragraphs (b)(1) and (2) of this
section are met.
(3) A petition under paragraph (a)(1) of this section may be
submitted, but may not be approved by the Administrator, before the
State Implementation Plan or Federal Implementation Plan covering the
entire State or the State Implementation Plans or Federal
Implementation Plans covering the entire group of States become final
and federally enforceable.
(b) The Administrator may take the actions set forth in paragraphs
(a)(1)(i) and (ii) of this section if he or she finds that, under the
State Implementation Plan or Federal Implementation Plan covering the
entire State or the State Implementation Plans or Federal
Implementation Plans covering the entire group of States:
(1) Each unit that is in the State or the group of States and that,
but for the provisions of this section, would be subject to emission
limitations under this part
(i) Is subject to a cap on total annual NOX emissions or two
or more seasonal caps that together limit total annual NOX
emissions;
(ii) May trade authorizations to emit NOX within each such
cap; and
(iii) Must use NOX emission authorizations to account for the
NOX emissions by such unit and to account for the NOX
emissions resulting from reducing utilization of such unit below its
baseline utilization (adjusted for changes in demand for electricity)
and shifting utilization to any other unit, or combustion device
serving a generator that produces electricity for sale, that is not
subject to each such cap; and
(2)(i) Total annual NOX emissions by all units that are in the
State or the group of States and that, but for the provisions of this
section, would be subject to emission limitations under this part will
be lower than total annual NOX emissions by such units if each
such unit is treated as subject to the applicable emission limitation
in Secs. 76.5, 76.6, or 76.7 that would apply but for the provisions of
this section.
(ii) In the case of a petition under paragraph (a) of this section,
total annual NOX emissions by the units will be determined using
the actual utilizations of the units for the last full calendar year
prior to submission of the petition but, in any event, for no later
than 1999. In the case of action by the Administrator on his or her own
motion under paragraph (a) of this section, total annual NOX
emissions by the units will be determined using the actual utilizations
of the units for the last full calendar year prior to issuance of the
draft decision under paragraph (c) of this section, but, in any event,
for no later than 1999.
(c) In acting on a petition or on his or her own motion under
paragraph (a) of this section, the Administrator will issue for public
comment a draft decision on the petition or a draft decision to act on
his or her own motion and then a final decision. The Administrator may
issue a draft decision, but not final decision, on a petition or on his
or her own motion before the State Implementation Plan or Federal
Implementation Plan covering the entire State or the State
Implementation Plans or Federal Implementation Plans covering the
entire group of States become final and federally enforceable. The
draft decision will set forth procedures that will govern issuance of
the final decision and will provide for:
(1) Service of notice of issuance of the draft decision on.
(i) Any interested person;
(ii) The air pollution control agencies that have jurisdiction over
a unit covered by the draft decision, are in a State whose air quality
may be affected by the draft decision and that is contiguous to a State
in which such a unit is located, or are in a State that is

[[Page 67164]]

within 50 miles of a unit covered by the draft decision; and
(iii) On any federally recognized Indian Tribe in an area in which
a unit covered by the draft decision is located, whose air quality may
be affected by the draft decision and that is in an area that is
contiguous to a State in which such a unit is located, or that is in an
area that is within 50 miles of a unit covered by the draft decision;
(2) Publication of notice of issuance of the draft decision in the
Federal Register and in any State publication designed to give general
public notice in the States in which the units covered by the draft
decision are located;
(3) A 30-day public comment period and extension or reopening of
the comment period by the Administrator for good cause;
(4) A public hearing, upon request or on the Administrator's own
motion, to the extent the Administrator determines that a public
hearing will contribute to the decision-making process by clarifying
one or more significant issues affecting the draft decision;
(5) Consideration by the Administrator of the comments on the draft
decision received during the public comment period or any public
hearing and written response by the Administrator to any such relevant
comments;
(6) Notice of issuance of a final decision using the methods set
forth in paragraphs (c)(1) and (2) of this section for providing notice
of the draft decision; and
(7) Appeals, governed by part 78 of this chapter, of the final
decision.
(d) If, after the Administrator issues a final decision under
paragraph (c) of this section and takes the actions set forth in
paragraphs (a)(1)(i) and (ii) of this section with regard to a State or
group of States, a State Implementation Plan or Federal Implementation
Plan covering the entire State or entire group of States is revised in
a way that may affect the basis for the findings on which such decision
is based, the Administrator may, upon petition or on his or her own
motion, reconsider such decision.
(e) For purposes of this section, the term ``State'' shall mean one
of the 48 contiguous States or the District of Columbia.

Appendix B to Part 76 [Amended]

9. Appendix B is amended by: removing from the heading the words
``Group 1, Phase I'' and adding, in their place, the words ``Group 1'';
removing from section 1 the words ``average cost'' and adding, in their
place, the word ``cost''; removing from section 1 the words ``average
capital costs and cost-effectiveness'' and adding, in their place, the
words ``capital costs and cost effectiveness''; removing from section 1
the words ``as determined in section 3 below''; removing from section 1
the words ``only overfire air'' and adding, in their place, the words
``overfire air''; removing from section 1 the words ``only separated
overfire air'' and adding, in their place, the words ``separated
overfire air''; removing from, the heading section 1 and the
introductory text of section 2 the words ``Group 1, Phase I'' in each
place that the words appear and adding, in their place, the words
``Group 1''; removing section 2.4; and removing and reserving section
3.
[FR Doc. 96-31839 Filed 12-18-96; 8:45 am]
BILLING CODE 6560-50-P}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}}