96-494. Acid Rain Program; Nitrogen Oxides Emission Reduction Program

[Federal Register Volume 61, Number 13 (Friday, January 19, 1996)]
[Proposed Rules]
[Pages 1442-1480]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-494]

[[Page 1441]]

_______________________________________________________________________

Part II

Environmental Protection Agency

_______________________________________________________________________

40 CFR Part 76

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

Federal Register / Vol. 61, No. 13 / Friday, January 19, 1996 /
Proposed Rules

[[Page 1442]]

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 76

[AD-FRL-5400-2]
RIN 2060-AF48

Acid Rain Program; Nitrogen Oxides Emission Reduction Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule and notice of public hearing.

-----------------------------------------------------------------------

SUMMARY: The proposed rule would implement the second phase of the
Nitrogen Oxides Reduction Provisions in Title IV of the Clean Air Act
(``the Act'') by establishing nitrogen oxides (NOX) emission
limitations for certain coal-fired 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.

DATES: Comments. Comments must be received on or before March 4, 1996.
Public Hearing. A public hearing will be held in Washington, DC on
February 8, 1996, beginning at 10:00 a.m. Persons interested in
presenting oral testimony must contact Peter Tsirigotis at EPA's Acid
Rain Division, telephone number (202) 233-9133, by February 2, 1996 to
verify arrangements.

ADDRESSES: Comments should be submitted (in duplicate, if possible) to:
Air Docket Section (A-131), Attention, Docket No. A-95-28, U.S.
Environmental Protection Agency, 401 M Street, SW, Washington, DC
20460.
Public Hearing. The public hearing will be held at the
Environmental Protection Agency, 401 M Street, Washington D.C., in the
Education Center Auditorium.
Docket. Docket No. A-95-28, containing supporting information used
in developing the proposed rule, 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, Waterside Mall, Room 1500, 1st Floor, 401 M
Street, SW, Washington, DC 20460. A reasonable fee may be charged for
copying.

FOR FURTHER INFORMATION CONTACT: Peter Tsirigotis, at (202) 233-9133,
Source Assessment Branch, Acid Rain Division (6204J), U.S.
Environmental Protection Agency, 401 M Street, Washington, DC 20460.

SUPPLEMENTARY INFORMATION: The information in this preamble is
organized as follows:

I. RULE BACKGROUND AND SUMMARY
A. Benefits of Reducing NOX Emissions
B. Cost-Effectiveness of this Regulatory Action
II. REVISION OF PHASE II, GROUP 1 BOILER NOX PERFORMANCE
STANDARDS
A. Statutory Provision
B. Methodology
C. Feasibility of Achieving Revised Phase I Performance
Standards
D. Adverse Effects of NOX and Benefits of Reduction
E. Revised Emission Limits for Group 1 Boilers
F. Compliance Date
G. Definition of Coal-Fired Utility Unit
III. CONTROL OF NOX EMISSIONS FROM GROUP 2 BOILERS
A. Description of Group 2 Boilers
B. NOX Control Technologies for Group 2 Boilers
C. Statutory Requirements
D. Methodology for Establishing Group 2 Emission Limitations
E. Characterization of Costs
F. Emission Limits for Group 2 Boilers
G. General Issues Raised
IV. REFERENCES
V. REGULATORY REQUIREMENTS
A. Executive Order 12291
B. Paperwork Reduction Act
C. Unfunded Mandates Act
D. Regulatory Flexibility Act
E. Miscellaneous

I. Rule Background and Summary

A. Benefits of Reducing NOX Emissions

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 passage of the 1970 Clean Air
Act, NOX has increased by 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 the total
NOX emissions and, from 1980 to 1990, their contribution rose to
32 percent of total NOX emissions. Approximately 85 percent of
electric utility NOX comes from coal-fired plants.
The NOX emissions discharged into the atmosphere from the
burning of fossil fuels consist primarily of nitric oxide (NO). Much of
the NO, however, reacts quickly to form nitrogen dioxide (NO2)
and, over longer periods of time, is transformed into other pollutants,
including ozone and fine particles. These secondary 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 or snow (``wet deposition'') or
as gases, fog, or particles (``dry deposition''), they contribute to
excessive nitrogen loadings to estuaries (``eutrophication''), such as
in the Chesapeake Bay, and acidification of lakes and streams.
NO2 has been documented to cause eye irritation, either by
itself or when oxidized photochemically into peroxyacetyl nitrate
(PAN). Ozone (O3), 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 to morbidity and
mortality.

B. Cost-Effectiveness of this Regulatory Action

On April 13, 1995 EPA promulgated the Acid Rain NOX rule
setting emission limits for all Phase I and Phase II dry bottom wall-
fired and tangentially fired boilers (Group 1) in the U.S. that combust
coal as a primary fuel. The regulation is expected, by the year 2000,
to nationally reduce NOX emissions by an estimated 1.54 million
tons per year. The total annual cost of this regulation to the electric
utility industry is estimated at 321 million dollars, resulting in an
overall cost-effectiveness of 208 dollars per ton of NOX removed.
The nationwide cost impact on electricity consumers is an average
increase in electricity rates of approximately 0.21 percent (EPA's
Regulatory Impact Analysis, docket item II-F-2 ).
The proposal would set lower Group 1 emission limits and establish
emission limits for several other types of coal-fired boilers (i.e.,
cyclones, cell burners, wet bottoms, vertically fired, and fluidized
bed combustors) for Phase II. The proposal would, by the year 2000,
achieve an additional reduction of 820,000 tons of NOX annually.
The annual cost for these additional reductions would be approximately
143 million dollars, at an average cost-effectiveness of 172 dollars
per ton of NOX removed. The nationwide impact on electricity rates
of this proposal is an average increase of approximately 0.07 percent,
significantly lower than the impacts resulting from the April 13, 1995
rule (see EPA's Regulatory Impact Analysis, docket item II-F-2).
This rule, when promulgated, must meet statutory criteria which
relate to cost and performance of existing installations of low
NOX burner technology (LNBT) and to estimates of cost and
performance of future

[[Page 1443]]
installations of a variety of NOX control technologies. At this
time there remain significant uncertainties regarding this information
and the best approaches for analyzing it. The information collected to
date is incomplete. Resolving these issues is one of the purposes of
soliciting public comments on this proposed rule. Information received
in the course of this rulemaking may show that no change in the
standard for tangentially fired and dry bottom wall-fired boilers may
be appropriate and that no standard for cyclones may be justifiable
under the statutory criteria.

II. Revision of Phase II, Group 1 Boiler NOX Performance
Standards

A. Statutory Provision

Section 407(b)(2) provides that:

Not later than January 1, 1997, the Administrator may revise the
applicable emission limitations for tangentially fired and dry
bottom, wall-fired boilers (other than cell burners) to be more
stringent if the Administrator determines that more effective low
NOX burner technology is available: Provided, That, no unit
that is an affected unit pursuant to section 404 and that is subject
to the requirements of [section 407] (b)(1), shall be subject to the
revised emission limitations, if any. 42 U.S.C. 76516(b)(2).

Under this provision, the Administrator may revise the applicable
NOX emission limitations for Group 1 boilers to be more stringent
if available data on the effectiveness of low NOX burner
technology shows that more stringent limitations can be achieved using
such technology. Any revised emission limitations will apply only to
Group 1 boilers that first become subject to NOX emission
limitations on or after January 1, 2000. Units with Group 1 boilers
that are subject to both SO2 and NOX emission limitations in
Phase I of the Acid Rain Program are entirely exempted from any revised
emission limitations. ``Early-election units,'' i.e., units with Group
1 boilers that are not subject to SO2 emission limitations until
Phase II but that have voluntarily become subject to the NOX
emission limitations by January 1, 1997 and demonstrate compliance with
these limitations throughout the rest of Phase I and during the period
2000-2007 are grandfathered from any revised limits until January 1,
2008, at which time any revisions will apply. 40 CFR 76.8.
Section II.B of the preamble summarizes the methodology the Agency
has used to evaluate the effectiveness of low NOX burner
technology applied to Group 1 boilers. Preamble Section II.C provides
estimates of the emission limitations (in lb/mmBtu) that a substantial
majority of units subject to any revised emission limitations can be
expected to achieve on an annual average basis. (The revised emission
limitations will hereafter be referred to as ``the Phase II, Group 1''
or ``revised Group 1'' emission limitations.) As with units subject to
the NOX emission limitations in Phase I, the designated
representative of a unit that is subject to the Phase II, Group 1
emission limitations and cannot meet the applicable emission limitation
using low NOX burner technology may seek to participate in a
NOX averaging plan with other units with the same owner or
operator or may petition for a less stringent alternative emission
limitation. The Technical Support Document, filed in Air Docket A-95-28
as item number II-A-9, contains a comprehensive description of the
methodology and results of the Agency's evaluation of the effectiveness
of Group 1 low NOX burner technology.
Preamble Section II.D addresses the benefits of reducing NOX
emissions. Finally, Section II.E concludes, based on the performance of
low NOX burners (LNBs) on Group 1 boilers and the benefits and
relative cost of reducing NOX by revising the Group 1 emission
limitations, that revised emission limitations should be adopted.
Section II.F addresses the compliance date for meeting the revised
limitations, an issue raised by the regulated utility industry.

B. Methodology

1. EPA's LNB Application Database
The Agency has developed a computerized database containing
detailed information on the characteristics and emission rates of coal-
fired units with Group 1 boilers on which low NOX burners (LNBs)
have been installed without any other NOX controls. The Department
of Energy (DOE) and Utility Air Regulatory Group (UARG), a major
industry association representing utility owners and operators, have
assisted EPA in identifying known applications of LNBs on Group 1
boilers.
EPA considered the option of including units on which LNBs have
been installed in combination with separated overfire air or other
NOX controls. EPA rejected this approach primarily because, in
many instances, the control technology vendor designed the combined
system, not the LNB component alone, to achieve the emission
performance standard. EPA also decided to exclude units on which LNBs
were installed before November 15, 1990, the date of enactment of the
Clean Air Act Amendments of 1990. Presumably, Congress was aware of
such LNB installations when it set the emission limitations in section
407 (b)(1); but the task here is to determine whether those limitations
should be revised because of the availability of more effective LNB, as
reflected in the performance of subsequent LNB installations.
The second criterion EPA used in selecting units for evaluating the
effectiveness of Group 1 LNB technology was the availability of post-
retrofit hourly emission rate data, measured by continuous emission
monitoring systems (CEMS), certified pursuant to 40 CFR part 75 (Acid
Rain Continuous Emission Monitoring Rule.) The only source of such
emission rate data has been the Acid Rain Emission Tracking System
(ETS), a computerized information system containing the quarterly
emissions reports submitted electronically by utilities under the Acid
Rain Program. For Phase I units, ETS provided hourly CEMS data on
NOX emission rates for four quarters of 1994 and the first two
quarters of 1995. In most instances, for Phase II units, ETS provided
CEMS data for the first two quarters of 1995, only. EPA solicits
comment on the appropriateness of using performance data collected by
means other than CEMS operated pursuant to 40 CFR part 75.
Using these selection criteria, EPA has compiled a database of
coal-fired units with Group 1 boilers, with LNB installations after
November 15, 1990, and for which post-retrofit hourly CEMS emission
rate data are available. This database presently consists of 24 dry
bottom wall-fired boilers (22 Phase I units, 2 Phase II units) and 9
tangentially fired boilers (6 Phase I units, 3 Phase II units). This
data set, called the ``EPA LNB Application Database,'' forms the
technical basis for EPA's evaluation of the effectiveness (percent
NOX removal) of low NOX burner technology for Group 1
boilers. EPA plans to continue this analysis as LNBs are installed on
more Phase II units and as additional quarters of hourly CEMS data from
ETS become available. Additional quarters of ETS CEMS data would be
expected to increase the size of this data set considerably since they
would include post-retrofit emission rate data for LNB installations
performed during summer and fall, 1995.
The EPA LNB Application Database contains the following information
for each boiler: nameplate capacity; firing type; pre-retrofit NOX
emission rate; source of pre-retrofit emission rate data; date of
boiler shutdown for LNB installation; date boiler resumed normal
operations after LNB installation, shakedown, and optimization; hourly

[[Page 1444]]
CEMS data from ETS for post-retrofit NOX emission rates; and
hourly data from ETS for boiler operating time and load. EPA contacted
utilities to verify the date of boiler shutdown for LNB installation
and the date the boiler resumed normal operations after post-retrofit
optimization whenever these dates could not be readily ascertained from
the hourly CEMS data and other information submitted by utilities to
EPA. The Agency solicits comment on what other data would be necessary
when assessing whether LNBs are operated in a low-NOX mode during
a certain time period (e.g., percent combustion air introduced through
close-coupled overfire air ports in tangentially fired boiler LNB
retrofits).
2. Determination of Achievable Annual Emission Limitations
Because the Acid Rain Phase I NOX Emission Reduction Program
goes into effect on January 1, 1996, units in the EPA LNB Application
Database have not been required to meet the Phase I NOX emission
rate standards in either 1994 or 1995. For every LNB retrofit there is
a period of time, immediately following the retrofit, during which
operators learn to operate the new equipment safely and in accordance
with the manufacturer's specifications. The operators then learn to
optimize NOX emissions reduction according to each utility's
compliance strategy. Performance of LNBs before optimization likely
overstates or understates the NOX reduction achievable by the
LNBs. Additionally, continued operation of LNBs to minimize NOX
emissions increases the operation and maintenance (O & M) costs of each
LNB retrofit after optimization. Therefore, even though LNB controls
are installed, the units may not be operated, throughout the entire
post-retrofit period, to sustain the NOX emission reductions the
controls were designed to achieve since this would increase O & M costs
when the NOX reductions are not yet required.
As discussed in EPA's Regulatory Impact Analysis (RIA), plants
incur both fixed and variable O & M costs when operating LNBs to lower
NOX emissions in order to meet the NOX emission limits. The
RIA assumes an annual maintenance cost increase of 1.5% of the
installed capital cost of the LNB equipment for both dry bottom wall-
fired and tangentially fired boilers and a variable cost of 0.04 mills/
kWh for dry bottom wall-fired boilers. While the incremental O & M
costs given in the RIA are estimated with respect to boiler O & M costs
prior to the technology retrofit. The sources of these incremental
costs (auxiliary fan power consumption, increased difficulty of
maintaining steam temperatures over the load range at reduced excess
air levels, higher maintenance demands), suggest that the absence of a
requirement to limit NOX emissions may result in operational
changes and higher NOX emissions. Thus, the average NOX
emission rate over the post-retrofit pre-compliance period may not be
representative of achievable 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.
It is intuitive that NOX reduction techniques which, by their
nature, create potentially damaging chemical environments inside
boilers and reduce overall plant efficiency when pushed to the highest
levels of NOX reduction performance, could be tested for several
weeks at levels which are not sustainable for longer periods of time.
According to certain utilities, there is anecdotal evidence that
initial performance levels for LNBs cannot be maintained indefinitely
on some boilers.\1\^{,\2\

\1\ It was reported that three tangentially fired boilers at
Duke Power Company's Allen plant could not maintain design
efficiency at full load, while meeting the existing standard of 0.45
lbNOX/mmBtu. Plant engineers are currently attemping to resolve
the problem with a slagging additive. E-mail communication from
Robert McMurray, Duke Power, to Doug Carter, USDOE, 11/7/95.
\2\ Southern Company reports that two of its Georgia Power
Company, McDonough plant tangentially fired units cannot meet their
NOX performance and plant performance guarantees at the same
time. Telecommunication between Rob Hardman, Southern Company
Services, and Doug Carter, USDOE, 11/3/95.
---------------------------------------------------------------------------

In publications and in past rulemakings, DOE and industry have
addressed what time period is sufficient for determining an achievable
emission limit for a NOX control technology over the long-term.
For example industry has stated ``that acceptable results [of long-term
performance] can be achieved with 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 has adopted the 52-day framework for evaluating the
effectiveness of Group 1 LNB technology. The first objective was to
identify the lowest average NOX emission rate each boiler has
sustained for at least 52 days, i.e., over a period of 1248 hours
during the post-retrofit period when the boiler was operating and valid
CEMS data was available. (Such a 1248 hour operating period is
generally longer than 52 calendar days since hours during which the
boiler did not operate, or operated for only part of the hour are
ignored, as are hours for which valid CEM data was not available.) This
period, referred to as the ``low NOX period,'' is assumed to
simulate boiler operations under compliance conditions. The next
objective was to determine whether the distribution of operating
conditions (e.g., load and excess air) during the low NOX period
is representative of actual boiler operating conditions throughout a
year. For each boiler in the database, EPA has developed histograms of
hourly average NOX emission rates as a function of load for the
low NOX period and boiler operating load patterns throughout 1994
(see docket item II-A-9). If the operating conditions in the low
NOX period are representative, EPA assumes the boiler can achieve
an annual average NOX emission rate equal to the average emission
rate recorded for the period. EPA used these histograms to estimate
``load weighted annual NOX emission rates'' based on weighted
averages of the average emission rate during the low NOX period
for each operating load level (or ``load bin'') times the number of
hours during 1994 the boiler operated within each load bin.
Some utility commenters have expressed the concern that by not
using all the recorded post-retrofit CEM data EPA is not accurately
assessing the long-term performance capabilities of LNBs. These
commenters believe that all CEM data collected after a fixed shakedown
period (30 to 90 days) for equipment optimization and operator
training, which is applied universally to all installations, should be
used for this assessment. To address this concern, EPA analyzed the CEM
data for 2 time periods: (1) a time period that would begin 30 days
after LNB installation and include all the post-retrofit data, referred
to as the ``post-retrofit period,'' and (2) a time period beginning
with the first day of the low NOX period and continuing beyond 52
days to include all available CEM data throughout the

[[Page 1445]]
entire post-retrofit period, referred to as the ``post-optimization
period.''
One of the primary advantages of using the low NOX period or
the post-optimization period, as defined above, for assessing
performance capabilities of LNBs applied to Group 1 boilers is that
they explicitly recognize the site-specific nature of the LNB equipment
optimization and operator training processes. For some units, both the
shakedown of the technology retrofit and operator training proceed
smoothly and can be completed within 30 or 60 calendar days. Whereas
for other units, particularly units combusting a range of coals and or
cycling through load pattern shifts, these processes can take much
longer. EPA finds that for dry bottom wall-fired boilers in the
database, the beginning of the low NOX period generally occurs
between 2 and 5 months after completion of the LNB retrofit. Not as
much variation is seen among the tangentially fired boilers, although
only 3 such boilers in the database have more than one quarter of post-
retrofit CEM data available.
Utility commenters have also expressed the concern that NOX
emission rate data taken before the Phase I compliance period for Acid
Rain SO2 emission limitations, which began January 1, 1995, may
not represent ``normal operating conditions.'' Specifically, in some
instances, 1994 Phase I data may not represent the current range of
coal quality characteristics being combusted by affected boilers. LNB
installations and vendor guarantees are typically tied to operating
within a specific range of coals. Moreover, EPA has learned of at least
two Phase I boilers which experienced significant increases in NOX
emissions when switching to coal for SO2 compliance purposes.
Other units at the Joppa steam plant, for example, experienced
significantly lower NOX emissions, after switching from eastern
bituminous to Powder River Basin coal. These units were dropped from
the database for the purposes of assessing LNB performance because the
measured percent reduction in NOX emissions reflects the combined
effects of the control technology retrofit and the switch to a more
reactive subbituminous coal.
To address these concerns, for each boiler in the database where
the 52-day low NOX period began in 1994, EPA has identified a 52-
day low NOX period for 1995 and compared the average NOX
emission rates for the two periods (see docket item II-A-9). Where
these analyses show a noticeable change occurred in NOX emissions
after the beginning of the Phase I SO2 compliance period, EPA
intends to investigate whether switching to low sulfur coal for
SO2 control or whether other operational parameters might explain
the difference in LNB performance. Further, EPA solicits comments from
the utilities documenting the specific circumstances where the
characteristics of coal quality and operating parameters have impacted
NOX emissions.
Also in the Group 1 technical support document (docket item II-A-
9), EPA has developed and compared average NOX emissions rates for
the following: low NOX period, low NOX period in 1995, post-
optimization period, overall post-retrofit period, and the load-
weighted annual average NOX emission rate. The document contains
statistical tests of significance on the absolute values of the
differences between these alternative ways of estimating the average
achievable NOX emission rate over the long-term. The next section
of the preamble summarizes and discusses these comparisons.
EPA has used two complementary analyses to estimate annual average
emission rates that can be sustained by LNBs installed on Phase II
units with Group 1 boilers and to develop percentile distributions of
Phase II units that can comply with various performance standards more
stringent than the Phase I standards. The two analyses are described
briefly below:

(1) Analysis 1 analyzes actual average emission rates, as
measured by CEMS data, achieved by LNBs applied to Phase I units in
Phase I and a few Phase II units to calculate the percent reduction
achievable by LNBs as a function of uncontrolled emission rate; and
(2) Analysis 2 applies the percent NOX reduction derived in
Analysis 1 to boiler-specific uncontrolled emission rates for the
population of units that will be subject to any revised NOX
emission limitations in Phase II in order to determine achievable
emission rates for the Phase II, Group 1 population.

The straightforwardness of the retrofit CEMS data analysis
(Analysis 1) is appealing in that it reflects actual boiler operating
experience. On the other hand, to the extent the Phase I population of
boilers is more difficult to retrofit and has higher baseline emission
rates and a greater proportion of tight, high furnace temperature
boilers than the Phase II population, emission rates based solely on
the retrofit CEMS data analysis will understate the achievable annual
emission limitations. Analysis 2, which uses a regression model applied
to the CEMS data to estimate the percent reduction as a function of
uncontrolled emission rates, captures differences in the two
populations of boilers.
Utilities complying with Group 1, Phase I reductions for
tangentially fired boilers had a spectrum of technologies to choose
from in addition to LNBs and some, perhaps due to other NOX
requirements such as title I of the Act, chose to go beyond LNBs in
their technology choice. As a result, DOE believes there is the
possibility that those units installing LNB were in some way different
from tangentially fired boilers in general and, therefore, existing LNB
installations may not be representative of how well LNBs will perform
on Phase II tangentially fired boilers. EPA seeks comment regarding the
representativeness of LNB installations.
Similarly, EPA is aware of no tangentially fired boiler with
uncontrolled NOX emissions exceeding 0.67 lb/mmBtu, which has been
retrofit with LNB. DOE believes that about one-fourth of the Phase II
tangentially fired boiler capacity exceeds this level of uncontrolled
emissions. EPA seeks comment on the ability of LNBs to meet the
proposed standards on boilers with uncontrolled NOX emissions
exceeding 0.67 lb/mmBtu, and requests any additional data which relates
to this issue.

C. Feasibility of Achieving Revised Phase I Performance Standards

1. Assessment Using Retrofit CEMS Data Analysis
Table 1 presents summary statistics on all known retrofit
applications of LNBs to Group 1 boilers, where LNB installation
occurred after November 15, 1990 and for which long-term post-retrofit
hourly CEMS emission rate data are available. The term ``baseline
NOX rate'' refers to the emission rate as of November 15, 1990 and
represents short-term uncontrolled NOX emissions.

[[Page 1446]]

Table 1.--Summary of the Known LNB Applications on Group 1 Boilers With CEMS Data Available
----------------------------------------------------------------------------------------------------------------
Low NOX period
No. of units Boiler size (MWe) Baseline NOX rate NOX rate (lb/
(lb/mmBtu) mmBtu)
----------------------------------------------------------------------------------------------------------------
Wall-Fired Boilers

Phase I:
Mean................................. 22 270.6 0.908 0.418
Range................................ 22 100.0-816.3 0.570-1.340 0.319-0.484
Phase II:
Mean................................. 2 267.4 0.757 0.354
Range................................ 2 254.3-280.5 0.513-1.000 0.262-0.445
Phase I & II:
Mean................................. 24 270.3 0.896 0.413
Range................................ 24 100.0-816.3 0.513-1.340 0.262-0.484
Tangentially Fired Boilers

Phase I:
Mean................................. 6 230.3 0.653 0.365
Range................................ 6 125.0-324.0 0.630-0.665 0.346-0.387
Phase II:................................
Mean................................. 3 80.5
80.0-81.6 0.514
0.478-0.587 0.325
0.304-0.363
Phase I & II:
Mean................................. 9 180.4 0.607 0.352
Range................................ 9 80.0-324.0 0.478-0.665 0.304-0.387
----------------------------------------------------------------------------------------------------------------

Tables 2 and 3 present detailed data on the 24 dry bottom wall-
fired LNB installations and the 9 tangentially fired LNB installations,
respectively. Table 2 does not include data for LNB installations that
occurred before the cutoff date of November 15, 1990 since these
installations occurred prior to the passage of the Act. Table 3 does
not include installations at the Joppa Steam plant (owned by Electric
Energy Inc.) since these units switched to Powder River Basin coal, nor
does it include installations at Lansing Smith, unit 2, (owned by Gulf
Power Co.) and Albright, unit 3 (owned by Monongahela Power Co.) since
EPA is unsure when during the post-retrofit period these units operated
with LNBs without separated overfire air. If EPA is provided
information during the comment period about when these latter two units
operated with LNBs only, EPA will add them to the database, provided
sufficient valid data is available.
EPA recognizes that the amount of compliance NOX data will be
increasing beginning January 1, 1996 as the Phase I units start
compliance reporting. EPA will carefully consider the first quarter
1996 data--subject to its timely receipt and required processing by
EPA--in preparing the final NOX rule for the Phase II units and
the Group 2 units. Therefore, it is important for quarterly 1996
emission reports to be accurate and timely submitted.

Table 2.--Known LNB Applications on Wall-Fired Boilers With CEMS Data Available
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low NOX
LNB Baseline period NOX
Phase State Utility Plant Boiler ID Size (MWe) retrofit NOX rate rate (lb/
date (lb/mmBtu) mmBtu)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1..... AL Alabama Power Co........... E. C. Gaston.......... 1 272.0 11/30/94 0.900 0.394
1..... AL Alabama Power Co........... E. C. Gaston.......... 2 272.0 04/07/92 .780 .394
1..... AL Alabama Power Co........... E. C. Gaston.......... 3 272.0 05/23/93 .800 .408
1..... AL Alabama Power Co........... E. C. Gaston.......... 4 244.8 05/21/94 .800 .408
1..... KY Big Rivers Electric Corp... Coleman............... C1 174.3 02/07/94 1.340 .436
1..... KY East Kentucky Power Coop Cooper................ 1 100.0 03/01/94 .900 .419
Inc.
1..... KY East Kentucky Power Coop Cooper................ 2 220.9 12/31/94 .900 .419
Inc.
1..... KY East Kentucky Power Coop HL Spurlock........... 1 305.2 04/08/93 .900 .402
Inc.
1..... FL Gulf Power Co.............. Crist................. 6 369.8 05/29/94 1.040 .462
1..... FL Gulf Power Co.............. Crist................. 7 578.0 01/02/94 1.160 .484
1..... IN Hoosier Energy REC Inc..... Frank E Ratts......... 1SG1 116.6 10/01/94 1.068 .469
1..... IN Hoosier Energy REC Inc..... Frank E Ratts......... 2SG1 116.6 07/01/94 1.090 .430
1..... KY Kentucky Utilities Co...... EW Brown.............. 1 113.6 06/16/93 1.000 .466
1..... WV Ohio Power Co.............. Mitchell.............. 1 816.3 02/01/94 .767 .455
1..... WV Ohio Power Co.............. Mitchell.............. 2 816.3 01/01/94 .767 .455
1..... PA Pennsylvania Electric Co... Shawville............. 1 125.0 12/25/93 .990 .438
1..... IN Southern Indiana Gas & Elec F B Culley............ 2 103.7 05/20/94 1.050 .348
Co.
1..... AL Tennessee Valley Authority. Colbert............... 1 200.0 05/15/94 .800 .397
1..... AL Tennessee Valley Authority. Colbert............... 2 200.0 05/15/94 .670 .397
1..... AL Tennessee Valley Authority. Colbert............... 3 200.0 12/24/91 .830 .397
1..... AL Tennessee Valley Authority. Colbert............... 4 200.0 05/15/94 .860 .397
1..... WI Wisconsin Public service Pulliam............... 8 136.0 05/15/94 .568 .319
Corp.
2..... IL Central Illinois Light Co.. Ed Edwards............ 2 280.5 01/01/93 1.000 .445
2..... NV Sierra Pacific Power Co.... North Valmy........... 1 254.3 06/01/94 .513 .262
--------------------------------------------------------------------------------------------------------------------------------------------------------

[[Page 1447]]

Table 3.--Known LNB Applications on Tangentially Fired Boilers With CEMS Data Available
--------------------------------------------------------------------------------------------------------------------------------------------------------
Low NOX
LNB Baseline period NOX
Phase State Utility Plant Boiler ID Size (MWe) retrofit NOX rate rate (lb/
date (lb/mmBtu) mmBtu)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1..... GA Georgia Power Company........ McDonough, J............ 1 245.0 6/5/95 0.657 0.346
1..... GA Georgia Power Company........ McDonough, J............ 2 245.0 12/16/94 .657 .346
1..... GA Georgia Power Company........ Yates................... 4 125.0 4/1/95 .630 .387
1..... GA Georgia Power Company........ Yates................... 5 125.0 11/26/94 .650 .387
2..... NY Niagara Mohawk Power Corp.... Dunkirk................. 1 80.0 2/1/95 .478 .308
2..... NY Niagara Mohawk Power Corp.... Dunkirk................. 2 80.0 1/1/95 .478 .308
2..... NY Rochester Gas & Electric Corp Rochester 7............. 4 81.6 3/31/95 .587 .363
1..... WI Wisconsin Electric Power Co.. Oak Creek............... 7 317.6 7/15/94 .661 .362
1..... WI Wisconsin Electric Power Co.. Oak Creek............... 8 324.0 4/16/95 .665 .362
--------------------------------------------------------------------------------------------------------------------------------------------------------

Units in the same plant that have identical low NOX period
emission rates share a common stack. Under the Acid Rain CEMS Rule,
emissions discharged by units sharing a common stack may be monitored
by either a single monitor located in the stack or separate monitors
located in ducts going from the units to the stack. Similarly, units
sharing a common stack frequently have the same baseline NOX rate.
Virtually all of the baseline NOX rates in Tables 2 and 3 come
from utility-reported data provided to EPA on the Acid Rain Cost Form
for NOX Control Costs for Group 1, Phase I Boilers. Utilities used
a CEMS or an EPA Reference Method for measuring these emissions data.
The remaining baseline NOX rates come from CEMS data reported
in monitor certification review (CREV) tests (see docket item II-A-9).
These latter data represent average NOX emission rates calculated
from 9 test runs comprising the most recent relative accuracy test
audit (RATA). Each RATA test run contains about 25 minutes of CEMS
data.
Tables 4 and 5 summarize comparisons of post-retrofit average
NOX emission rates computed using alternative bases: low NOX
period, post-optimization period, low NOX period in 1995, and
overall post-retrofit period following a fixed 30-day start-up period.
EPA solicits comment on the relative merits of these alternative bases
for determining the performance of low NOX burners and in
particular, the use of a fixed 30-day, 60-day, or 90-day start-up
period, universally applied, or some other approach that reflects
stabilization of the NOX control equipment, and how to determine
the proper period using the reported hourly emissions data. Summaries
of these data are provided below.

Table 4.--Dry Bottom Wall-Fired Boilers
----------------------------------------------------------------------------------------------------------------
Low NOX period Post- Low NOX period Overall post-
Comparison of average emission rates (1994-1995 optimization (1995 data retrofit
data) period only) period
----------------------------------------------------------------------------------------------------------------
Phase I boilers................................. 0.418 0.436 0.437 0.455
Phase II boilers................................ .354 .368 .354 .385
Phase I & II boilers............................ .413 .430 .429 .449
----------------------------------------------------------------------------------------------------------------

Table 5.--Tangentially Fired Boilers
----------------------------------------------------------------------------------------------------------------
Low NOX period Post- Low NOX period Overall post-
Comparison of average emission rates (1994-1995 optimization (1995 data retrofit
data) period only) period
----------------------------------------------------------------------------------------------------------------
Phase I boilers................................. 0.365 0.373 0.365 0.375
Phase II boilers................................ .325 .327 .325 .334
Phase I & II boilers............................ .352 .358 .352 .361
----------------------------------------------------------------------------------------------------------------

For each boiler used in the retrofit CEMS data analysis, EPA has
identified the low NOX periods for both 1994 and 1995 as well as
examined a plot of daily average NOX emission rates over the
entire post-optimization period. Where these analyses show a noticeable
change occurred in NOX emissions after the beginning of the Phase
I compliance period, EPA will investigate whether switching to low
sulfur coal for SO2 control or whether other operational
parameters might explain the difference in LNB performance. EPA has
examined the relationship between the low NOX period and the post-
optimization period. The average NOX emission rates for wall-fired
boilers for the low NOX period are lower than the post-
optimization period. (No difference is observed for tangentially fired
boilers because these two time periods are essentially equivalent in
length.) Since the Phase I NOX Emission Reduction Program is not
in effect until January 1, 1996, even though LNBs are installed, the
units may not be operated to optimize NOX emissions throughout the
entire post-retrofit period since O&M costs increase when operating
LNBs to minimize NOX emissions. In addition, a literature review
indicates that through operational optimization NOX emissions can
be reduced by 10-20%. The existing wall-fired installations of LNBs do
show a difference in NOX reductions, depending on the portion of
the post-retrofit data considered. The performance of these units, and

[[Page 1448]]
therefore the data analysis period, is key to deciding whether the
statutory test of ``more effective'' LNBs have been demonstrated.
Hence, comment is solicited on defining the best approach to evaluating
this post-retrofit data. At this time, EPA has made no final decision
on the length of data analysis period.
Recent publications and comments from utility industry
representatives indicate that there is concern that 52-day periods (low
NOX periods) may not adequately capture annual dispatch patterns
and seasonal variations in demand for electrical power generation. EPA
therefore has developed estimates of ``load-weighted annual 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 during 1994 the boiler operated within each load bin. As
summarized below, in less than half of the comparisons, the load-
weighted annual NOX emission rate is no more than 10% above the
low NOX period rate and in the remaining is at or below the low
NOX period rate.

Table 6.--Comparison of Average NOX Emission Rates
[Dry bottom wall-fired boilers]
------------------------------------------------------------------------
Load-
weighted
Low NOX annual NOX
period emission
rate
------------------------------------------------------------------------
Phase I boilers................................. 0.418 0.409
Phase II boilers................................ .354 .355
Phase I & II boilers............................ .413 .405
------------------------------------------------------------------------

Table 7.--Comparison of Average NOX Emission Rates
[Tangentially fired boilers]
------------------------------------------------------------------------
Load-
weighted
Low NOX annual NOX
period emission
rates
------------------------------------------------------------------------
Phase I boilers................................. 0.365 0.325
Phase II boiler................................. .325 .330
Phase I & II boilers............................ .352 .327
------------------------------------------------------------------------

EPA believes the load-weighted annual NOX rate estimates
address the concern over the adequacy of using 52-day periods. The data
show that the annual emission rate projected over the actual dispatch
pattern of 1994, results in approximately the same emission rate as the
low NOX period identified during the post-retrofit timeframe. EPA
compared the dispatch patterns over the low NOX period with the
actual 1994 annual dispatch pattern and found them to be similar for
most boilers. This indicates that the low NOX period dispatch
patterns were representative. Additionally, a strong generic
relationship between NOX and load was not found (see docket item
II-A-9). Moreover, the ``52-day periods'' generally span more than two
calendar months; they represent NOX emission rates averaged over
1248 sequential hours during which the boiler was operating and valid
CEMS measurements were reported. Hours for which a valid NOX
emission rate measurement is not available (e.g., hours for which
substitute data was used for the NOX emission rate), the unit was
not operating, or the unit operated for only part of the hour are not
included. Valid CEMS NOX emission data after such a gap were moved
forward and linked to the 52-day low NOX data chain until there
are 1248 hours of NOX hourly data. The Technical Support Document
contains information on the beginning and end of each of the 52-day low
NOX periods as well as the other bases used for estimating post-
retrofit average NOX emission rates.
EPA has tabulated the percentage of time each boiler's daily
average NOX emission rate, during the low NOX period, was
less than or equal to alternative performance standards more stringent
than the existing Group 1 NOX emission limitations. Consistent
with the definition of 52-day periods and with the missing data
substitution algorithms in the Acid Rain CEMS Rule, a ``daily'' average
is defined as the average of a sequential (but not necessarily
continuous) set of 24 hours of valid NOX emission rate
measurements excluding missing data results. Tables 8 and 9 show the
percentile distributions of Group 1 boilers, by type. EPA estimated the
percentage of units in the Group 1 boiler data set that during their
low NOX period in 1994 or 1995, would have complied with various
alternative performance standards more stringent than the existing
Group 1 NOX emission limitations.

Table 8.--Dry Bottom Wall-Fired Boilers
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
% of Boilers Less Than or Equal to Standard for Low NOX Period
Average

----------------------------------------------------------------------------------------------------------------
NOX Performance Standard (lb/mmBtu)............ 0.47 0.46 0.45 0.44 0.43
Phase I boilers (22)........................... 95.5% 86.4% 72.7% 72.7% 63.6%
Phase II boilers (2)........................... 100.0% 100.0% 100.0% 50.0% 50.0%
Phase I & II boilers (24)...................... 95.8% 87.5% 75.0% 70.8% 62.5%
----------------------------------------------------------------------------------------------------------------

Table 9.--Tangentially Fired Boilers
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
% of Boilers Less Than or Equal to Standard for Low NOX Period
Average

----------------------------------------------------------------------------------------------------------------
NOX Performance Standard (lb/mmBtu)............ 0.42 0.40 0.39 0.38 0.36
Phase I boilers (6)............................ 100.0% 100.0% 100.0% 66.7% 66.7%
Phase II boilers (3)........................... 100.0% 100.0% 100.0% 100.0% 100.0%
Phase I & II boilers (9)....................... 100.0% 100.0% 100.0% 77.8% 77.8%
----------------------------------------------------------------------------------------------------------------

Viewed collectively, the various tabulations, analyses, and plots
of actual post-retrofit CEMS data suggest to EPA that dry bottom wall-
fired boilers with LNBs and tangentially fired boilers with LNBs can
easily achieve an annual emission limitation below the current emission
limitations of 0.50 lb/mmBtu and 0.45 lb/mmBtu respectively. Estimates
of post-retrofit average NOX emission rates using different bases
(i.e., low NOX period, low NOX period in

[[Page 1449]]
1995, load-weighted annual NOX rate, and post-optimization period
average) are consistent; all of these rates are 14 percent or more
below the current emission limitation. Commenters have observed that
there is substantial uncertainty concerning the ability of Phase II
boilers to meet a lower standard if one considers: (a) units with less
than 52 days of monitoring data; (b) the lack of control technology
performance data from tangentially fired boilers with uncontrolled
emission rates higher than 0.67 lb/mmBtu; and (c) periods of
performance monitoring other than the ``low NOX period.'' Further
comment is sought on this issue.
2. Assessment Using Phase II Population Projection Analysis
Figures 1 and 2 display plots of the average NOX reduction
achieved by LNBs, derived from actual retrofit CEMS data, as a function
of the short-term uncontrolled NOX emission rate. (These plots are
based on the data in Tables 2 and 3 above.) Also shown in the figures
are the results of linear regression models EPA developed to estimate
the LNB-controlled emission rate as a function of the short-term pre-
retrofit uncontrolled emission rate. EPA has selected the short-term
uncontrolled emission rate as the baseline for these analyses because
boiler-specific measurements of this variable are available from the
CREV test data sets for almost all Phase I, Group 1 boilers and for 69
percent of Phase II, Group 1 boilers. EPA further determined that the
Phase II data set (69% of the Phase II population) adequately
represents the entire Phase II population by comparing boiler size and
age distributions (for details of this analysis, see page 3 of docket
item II-A-9).
Based on the information in Figures 1 and 2, EPA estimated the
emission rates that can be achieved by Group 1 units subject to any
revised emission limitations using LNBs. For both types of Group 1
boilers, EPA used the regression equation with boiler-specific CREV
uncontrolled emission rates to develop projections of the LNB-
controlled emission rate. For each unit, as shown by the coefficient of
correlation, R^{2, the regression equation accounts for about 68%
(wall-fired) and 67% (tangentially fired) of the variability observed
in the data. The regression equations result in NOX reduction
efficiency of low NOX burners applied to Group 1, Phase II boilers
with respect to uncontrolled NOX emission rate. The NOX
emission reduction percentage then typically ranges from 40 percent to
67 percent for wall-fired boilers and from 35 percent to 47 percent for
tangentially fired boilers, depending on each boiler's uncontrolled
NOX emission rate. The lower long-term average NOX reduction
is achieved by low NOX burners on boilers with lower uncontrolled
emission rates. Similarly, the higher long-term average NOX
reduction is achieved by low NOX burners on boilers with higher
uncontrolled emission rates. EPA solicits comment on the
representativeness of the reduction efficiency ranges in determining
performance of low NOX burners.

BILLING CODE 6560-50-P

[[Page 1450]]
[GRAPHIC][TIFF OMITTED]TP19JA96.000

[[Page 1451]]
[GRAPHIC][TIFF OMITTED]TP19JA96.001

BILLING CODE 6560-50-C

[[Page 1452]]

From these boiler-specific population projections, EPA has
developed percentile distributions estimating the number of Group 1
boilers (subject to any revised emission limitations) that can comply
with various alternate performance standards more stringent than the
current NOX emission limitations. The resulting distributions of
Group 1 boilers by percentile achievement for different performance
standards are shown below.

Table 10.--Percentile Achievement of Alternative Wall-Fired Boiler
Performance Standards
------------------------------------------------------------------------
Percentile Performance standard (lb/mmBtu)
------------------------------------------------------------------------
100................................ 0.465
95................................. 0.451
90................................. 0.448
85................................. 0.441
80................................. 0.434
------------------------------------------------------------------------

Table 11.--Percentile Achievement of Alternative Tangentially Fired
Boiler Performance Standards
------------------------------------------------------------------------
Percentile Performance standard (lb/mmBtu)
------------------------------------------------------------------------
100................................ 0.499
95................................. 0.401
90................................. 0.377
85................................. 0.370
80................................. 0.364
------------------------------------------------------------------------

The percentile distributions of estimated achievable annual
emission limits based on the Phase II population projection analysis
indicate that 99.5% of the Phase II dry bottom wall-fired boilers could
comply with a revised performance standard of 0.45 lb/mmBtu and 92.3%
of the Phase II tangentially fired boilers could comply with a revised
performance standard of 0.38 lb/mmBtu. These percentages indicate a
better performance than is indicated by the CEMS data analysis. To
determine why this difference exists, EPA investigated the uncontrolled
NOX emission rates of Phase I and Phase II boilers. A tabulation
of the average uncontrolled emission rates for the Phase I and Phase II
populations of Group 1 boilers shows, for both types, that Phase I
boilers have higher uncontrolled emission rates.

Table 12.\3\--Comparison of Phase I, Group 1 and Phase II, Group 1
Uncontrolled NOX Emission Rates
------------------------------------------------------------------------
Phase I Phase II
Boiler type average average Percent
NOX rate NOX rate difference
------------------------------------------------------------------------
Dry Bottom Wall-fired................... 0.963 0.744 23
Tangentially fired...................... .652 .536 18
------------------------------------------------------------------------

Hence, it is seen that Phase II boilers operate at typically lower
uncontrolled emissions rates. As a result, a greater fraction of those
boilers are expected to be able to meet a given emission target.

\3\ Based on CREV data taken from EPA's database of uncontrolled
NOX emissions, presented in Appendix A of RIA.
---------------------------------------------------------------------------

In the preceding discussion, performance data for Group 1 boilers
was based on emission data for the low NOX period, i.e., a period
of 52 days of operation as defined above. If the post-optimization
period as defined above were used to determine the performance of low
NOX burners, the applicable emission limits would be 0.46 lb/mmBtu
and 0.39 lb/mmBtu for wall-fired and tangentially fired boilers
respectively. Similarly, if the overall post-retrofit period were used,
the applicable emission limits would be 0.48 lb/mmBtu and 0.39 lb/mmBtu
for wall and tangentially fired boilers respectively by EPA's
calculation. DOE calculates an applicable emission limit of 0.50 lb/
mmBtu for wall-fired boilers using the overall post-retrofit period,
excluding 2 units considered by EPA, and using a different regression
formula than EPA (see docket item, II-D-62, Analysis of Proposed
Section 407(b)(2) NOX Rule, Department of Energy, Staff Paper,
December 14, 1995).
If the data used by DOE for the post-retrofit period, using DOE's
computations, are representative of performance of wall-fired boilers
retrofit with LNBs, then no change in the standard for such boilers
would be called for and EPA in the final rule would retain the existing
standard for such boilers. An analysis by DOE concluded that only 70%
of the affected wall-fired units could meet the proposed emission limit
of 0.45 lb/mmBtu (docket item, II-D-62, Analysis of Proposed Section
407(b)(2) NOX Rule, Department of Energy, Staff Paper, December
14, 1995). EPA seeks comment on the data and the computation used by
DOE and on whether the existing standard should be retained for wall-
fired boilers.
In the case of tangentially fired boilers, DOE reviewed performance
of tangentially fired boilers retrofit with LNBs in addition to those
considered by EPA. The emissions data for the units have only recently
been reported to EPA under part 75 and have not yet been analyzed.
DOE's analysis indicates that 90% of the affected units can meet the
current standard of 0.45 lb/mmBtu, but the proposed standard can be met
by only 40% (docket item, II-D-62, Analysis of Proposed Section
407(b)(2) NOX Rule, Department of Energy, Staff Paper, December
14, 1995). If DOE's data are representative of the actual performance
of these units, then no change in the standard for such boilers would
be appropriate and EPA in the final rule would retain the existing
standard for such boilers. EPA seeks comments on the data and on
whether the existing standard should be retained for tangentially fired
boilers.
EPA recognizes that in several instances the data on which today's
proposal is based relate to a limited number of boilers and that
analysis of the performance and cost of NOX controls could benefit
from fuller data, involving more units. For example, there are several
low NOX burner technology retrofits on tangentially fired boilers
for which the Agency does not yet have available CEM data collected in
accordance with part 75 and for which the Agency has not yet evaluated
data not reported through part 75 that recently became available.
During the comment period the Agency will have the opportunity to
examine NOX emissions data collected from these and other low
NOX burner technology installations. The Agency will also be able
to expand the hourly data examined for each boiler listed in Tables 2
and 3 above to include data collected after the second quarter of 1995.
In light of additional data that EPA may receive during the comment
period, the final rule may establish different Phase II, Group 1
NOX emission limitations than those proposed today. If the new
information is found not to justify revising the emission limitations
promulgated in Phase I, EPA will not revise them.
In light of the above discussion about new information that will be
received during the comment period, in developing the proposal the
Agency considered comment suggesting that the issuance of this proposal
should be delayed in order to obtain fuller data on which to base
determinations concerning the Phase II, Group 1 emission limitations.
However, as discussed above, title IV establishes a schedule for
issuance of and compliance

[[Page 1453]]
with the NOX emission limitations in this proposal. Section 407(b)
requires that any revision of the Group 1 emission limitations (and any
Group 2 emission limitations) be established by January 1, 1997 and
applicable in Phase II. Establishment by January 1, 1997 of the Phase
II NOX emission limitations under title IV will provide utilities
with the information that they need concerning emission requirements
for Phase II in order to fashion the most efficient strategies to
comply with the Acid Rain NOX emission reduction program. Under
the Acid Rain program, compliance strategies may include: early
election plans (where Phase II, Group 1 units elect to comply starting
in 1997 with Phase I NOX emission limitations and avoid any
revised Group 1 limitations until 2008); NOX averaging plans
(where NOX emissions of units with the same owner or operator are
controlled to various extents and averaged to meet an overall limit);
or alternative emission limitations (where a unit with controls
designed, but unable, to meet the standard emission limitation can
qualify for a less stringent limitation).
In light of the statutory deadlines under section 407 and EPA's
analysis of the presently available data, the Agency has concluded that
it has a sufficient basis for proposing revised emission limitations
for Phase II, Group 1 boilers. EPA intends to use the comment period on
the proposal to gather more data. The Agency stresses that it will
welcome, and fully consider in the final rule, any additional data
relevant to the proposed emissions limitations.
3. Conclusions
EPA proposes to find that currently available data on the
effectiveness of LNB technology on Group 1 boilers demonstrates that
``more effective LNB technology is available'' for both dry bottom
wall-fired and tangentially fired boilers under Phase II of the Acid
Rain NOX Emission Reduction Program. Projections developed by
applying CEM-based estimated percent reductions to boiler-specific
uncontrolled emission rate data for the Phase II population indicate
that over 90% of dry bottom wall-fired boilers could individually meet
a performance standard of 0.45 lb/mmBtu and over 90% of tangentially
fired boilers could individually meet a performance standard of 0.38
lb/mmBtu.
EPA has taken the approach of selecting, as the revised emission
limitations achievable by Group 1 boilers, the emission limitations
that will be achievable by 90% of the applicable boiler population.
EPA chose to base the proposed emission limitation on the emission
rate that a target of 90% of the population will be able to meet
because of the flexibility offered by two compliance options available
to all Group 1 boilers: (1) emission averaging and (2) alternative
emission limitations. Group 1 boilers that install the NOX control
technology and cannot meet the applicable emission limitation on an
individual boiler basis may average with other boilers that are below
the applicable emission limitation or may petition the permitting
authority for a more relaxed emission limit. While the Agency could
have assumed that significantly more than 10% of the boiler population
could use the averaging or alternative emission limitation option, the
Agency maintains that use of the compliance target of 90% reasonably
implements the statutory requirement that the emission limitations be
based on the degree of emission reduction ``achievable'' through
retrofit application of cost-comparable NOX control technology.
This is analogous to the approach used in setting NOX emission
limitations under section 407(b)(1) for Phase I, Group 1 boilers.
Section 407(b)(1) required that the Phase I, Group 1 emission
limitations reflect what could be ``achieved using low NOX burner
technology'' (42 U.S.C. 7651f (b)(1)), and, in adopting the presumptive
limits set forth in section 407(b)(1) (A) and (B), EPA relied on
analysis showing that ``less than 10 percent of the Group 1 units would
fail to meet the presumptive limits.'' 60 FR 18758.

Table 13.--Group 1 Boiler Statistics and Expected Results
----------------------------------------------------------------------------------------------------------------

----------------------------------------------------------------------------------------------------------------
For Dry Bottom Wall-Fired Boilers

----------------------------------------------------------------------------------------------------------------
Alternative NOX Emission Standard (lb/mmBtu)................ 0.46 0.45 0.44 0.43
% boilers estimated to achieve standard based on Phase II
population projection method............................... 99.5% 99.5% 87.0% 80.9%

----------------------------------------------------------------------------------------------------------------
For Tangentially Fired Boilers

----------------------------------------------------------------------------------------------------------------
Alternative NOX Emission Standard (lb/mmBtu)................ 0.40 0.39 0.38 0.36
% boilers estimated to achieve standard based on Phase II
population projection method............................... 95.2% 93.1% 92.3% 80.6%
----------------------------------------------------------------------------------------------------------------

EPA has estimated that adopting the revised Group 1 performance
standards will reduce nationwide NOX emissions by an additional
200,000 tons annually beyond the annual tonnage reductions under the
existing Group 1 emission limitations. When estimating the additional
emission reductions from boilers achieving the revised performance
standards, EPA has conservatively assumed that LNBs were not applied to
any boilers with baseline emission rates at or below the applicable
revised performance standard. Thus, these boilers would not contribute
to the aggregate estimate of tons NOX removed.

D. Adverse Effects of NOX and Benefits of Reduction

Nitrogen oxides (NOX) emissions result in an unusually broad
range of detrimental effects to human health and the environment.
NOX is a primary precursor to ozone formation and therefore is a
major component in smog (oxidant air pollution). Atmospheric deposition
of nitrogen compounds contributes to the degradation of water quality
in certain areas with its ensuing ecological effects. These and other
effects, described below, caused by NOX emissions or their
transformation products can adversely affect the environment and human
health.
Reducing NOX emissions from coal-fired power plants by
revising the emission limitations for Group 1, Phase II boilers (and by
establishing emission limitations for Group 2 boilers) would be
expected to produce multiple benefits. Benefits would accrue from
reducing ozone within and transported into ozone non-attainment areas,
reducing the formation of nitrate

[[Page 1454]]
particulate matter in the air, reducing ambient levels of NO2 and
PAN gases, reducing excessive nitrogen loadings to the Chesapeake Bay
and other estuaries, reducing acid deposition and resulting
acidification of lakes and streams, and improving visibility.
1. Formation of Secondary Pollutants, Eutrophication, and Acidic
Deposition
NOX emissions, as discharged into the atmosphere from the
burning of fossil fuels, consist primarily of nitric oxide (NO). Much
of the NO, however, reacts with organic radicals to form nitrogen
dioxide (NO2) and, over longer periods of time, is transformed
into other pollutants, including ozone (O3) and nitrate fine
particles.
Water quality degradation due to excessive nutrients
(``eutrophication'') can occur when airborne nitrogen compounds fall
directly on water, particularly an estuary, or the surrounding land and
enter the water through runoff. Acidic deposition occurs when airborne
nitrate compounds, which can be transported over long distances, return
to the earth through rain or snow (``wet deposition'') or as gases,
fog, or particles (``dry deposition''). While the severity of the
damages depend on the composition or sensitivity of the receptor,
acidic deposition, according to the 1990 Amendments of the Clean Air
Act, ``represents a threat to natural resources, ecosystems,
visibility, materials, and public health.''
2. Benefits from Reducing Ozone
Ozone, which is the most abundant of the photochemical oxidants, is
formed when NOX reacts with volatile organic compounds VOCs \4\
and sunlight. Heat accelerates this process, so ozone is most severe
during the summer months. Ozone is a highly reactive chemical compound
which can have adverse effects on human health, plants, animals, and
materials. Even 6-8 hours' exposure to elevated levels of ozone can
produce decreased lung function, increased airway inflammation,
increased sensitivity to lung infection in adults and children, the
effects being most pronounced during outdoor work and exercise (see
docket item II-A-10; Krupnick and Ozkanynak, 1991; Huang, 1988; Abbey,
1993). Elevated ozone increases the risk and intensity of asthma
attacks (Wittmore and Korn, 1980; Krupnick, 1988). The Public Health
Service of the National Institutes of Health estimates that, in 1992,
12.4 million Americans had asthma (Benson, 1994).

\4\ Like NOX, volatile organic compounds (VOCs) are emitted
directly into the atmosphere from a combination of man-made sources
(burning of fossil fuels in utility and industrial boilers, motor
vehicle emissions, hydrocarbon releases from dry cleaning and other
industrial processes) and natural sources (mostly vegetation).
---------------------------------------------------------------------------

Ozone at currently occurring levels also inhibits photosynthesis in
crops, trees, and plants, which leads to reduced agricultural crop
yields, increased susceptibility to pests and disease, and economic
losses associated with noticeable leaf damage in ornamental plants.
According to the National Acid Precipitation Assessment Program
(NAPAP), ozone has been responsible for significant reductions in the
annual yields of several domestically important crops: corn, 1%;
cotton, soybeans, 7%; and alfalfa, 30% (NAPAP, 1990). Other analyses of
five-year data from the National Crop Loss Assessment Network (NCLAN)
^{5 corroborate this assessment (Sommerville, 1989).

\5\ NCLAN was established by EPA during the 1980s for controlled
field tests to develop dose-response relationships between ozone
concentrations and crop yield.
---------------------------------------------------------------------------

A growing body of scientific evidence indicates that reducing
NOX emissions on a regional basis is a cost-effective approach to
achieving the ozone NAAQS the most seriously polluted ozone
nonattainment areas of the Eastern U.S.^{6 (60 FR 45583, August 31,
1995). These areas have consistently failed to achieve this health-
based standard despite up to 20 years of applying controls to sources
of VOCs, another ozone precursor, on a localized basis (NRC, 1991).
Recent studies of the South, the Northeast Corridor, and the states
bordering Lake Michigan conclude that ozone and NOX transported
from attainment areas both within the regions and outside of the
regions contribute significantly to ozone non-attainment within the
regions (see Southern Oxidants Study, 1995; 60 FR 4217; 60 FR 45580).
Modeling performed by EPA for the Ozone Transport Region (OTR), a 12-
state region spanning the Northeast Corridor from Northern Virginia to
Maine, shows that NOX emission controls on major sources outside
the OTR, primarily power plants in the Midwest, would provide
significant incremental reductions, ranging from 12-20%, to polluted
areas inside the OTR (US EPA, 1994b). Thirty-two states, as well as
areas of Canada, were included in EPA's modeling studies of ozone
transport in the Eastern U.S. Achievement of ozone attainment in these
regions and protection from ozone-related human health and other
effects depend, in part, on reducing NOX emissions in upwind areas
of these regions. EPA notes that 77% of the Group 1, Phase II boilers,
and 89% of the Group 2 boilers are located in areas adjacent to and
east of the Mississippi River.

\6\ See Regional Ozone Modeling for Northeast Transport
(ROMNET), EPA Doc. EPA-450/4-91-002a (June 1991), and Chu, S.H.,
E.L. Meyer, W.M. Cox, R.D. Scheffe, ``The Response of Regional Ozone
to VOC and NOX Emissions Reductions: An Analysis for the
Eastern United States Based on Regional Oxidant Modeling,''
Proceedings of U.S. EPA/AWMA International Specialty Conference on
Tropospheric Ozone: Nonattainment and Design Value Issues, AWMA TR-
23, 1993.
---------------------------------------------------------------------------

3. Benefits from Reducing Particulate Matter
NOX emissions can not only transform into ozone and other
photochemical oxidant gases, they can also react with ammonia, other
constituents, and moisture in the atmosphere to form acidic and other
nitrate fine particles. Exposure to current levels of fine particles in
the air has a wide range of health and other adverse effects, ranging
from higher cleaning expenses effects on morbidity and mortality (see
Schwartz, 1994; Fairday, 1990; and US EPA, 1995b). Nitrates are
considerably smaller than 10 microns and are part of the PM10
particulate matter subclass PM2.5, called ``fine particles.''
Documented illnesses caused by exposure to fine particles, particularly
over extended periods of time, include: various respiratory diseases,
eye irritation, aggravation of existing cardiovascular disease, and
lowering the body's resistance to carcinogenesis and foreign materials.
Adverse respiratory health effects can also occur when people,
particularly individuals in sensitive subpopulations, breathe aerosols
(Thurston, 1989). Acidic aerosols include solid particles and liquid
droplets suspended in the air that are generated when NOX
transforms into nitrates. One of the benefits of additional NOX
emission reductions would be health and economic benefits associated
with reductions in the formation of nitrate fine particles.
4. Benefits from Reducing NO2
NO2 is a brownish gas that has been documented to cause eye
irritation in people, either by itself or when oxidized photochemically
in the presence of VOCs and sunlight into PAN (Schwartz et al., 1988).
Elevated levels of NO2 have also been documented to cause lower
respiratory illness (LRI) in otherwise normal children, making them
suffer from chronic cough, persistent wheezing, and/or chronic phlegm
(Neas, 1991). Persons with pre-existing chronic obstructive pulmonary
disease (COPD), estimated to be 14 million in the U.S. (U.S. Department
of Health and Human

[[Page 1455]]
Services, 1990), and asthmatics are more likely to suffer from
respiratory ailments or chronic illness (decreased lung function and
increased risk of lung infection) caused by exposure to NO2 than
the general population.
5. Water Quality Benefits
Atmospheric deposition of nitrates can be a significant factor in
the degradation of water quality and its associated health risks and
damaging ecological effects. Various forms of nitrogen have been
measured as wet and dry deposition falling on the Chesapeake Bay and
its watershed. Eutrophication, which results from excessive nitrogen
loadings, can cause adverse ecological effects. Impacts range from
nuisance algae blooms to the depletion of oxygen with resultant fish
kills. Approximately 25-40% of total nitrogen entering the Bay and
other estuaries is a result of atmospheric deposition (US EPA, 1994a).
A study of the Chesapeake Bay, performed under a Congressionally
mandated program to evaluate the effects of atmospheric deposition to
pollutant loadings in the Great Water Bodies of the U.S., determined
that the majority of airborne nitrogen compounds over the Bay are
emitted by power plants and motor vehicles (US EPA, 1994a). Reductions
in NOX emissions from power plants are substantially less
expensive to implement than alternative controls for reducing nitrogen
loadings to the Bay from point (wastewater plants) and area (farms,
animal pastures) sources. Such alternatives are presently being
considered by the States of Maryland, Pennsylvania, and Virginia, and
the District of Columbia in order to achieve a 40%-reduction in
nutrient supplies to the Bay by the year 2000, to which these
jurisdictions have committed. The average cost-effectiveness of these
other controls are: chemical addition or biological removal of nitrogen
from wastewater processing ($4,000 to over $20,000/ton nitrogen
removed) and ``management practices'' to reduce nitrogen from
fertilizers, animal waste, and other nonpoint sources ($1,000 to over
$100,000/ton of nitrogen removed) (Camacho, 1993; Shuyler, 1992). By
comparison, the average cost-effectiveness of LNB applied to Group 1
coal-fired boilers in this proposal is estimated to be $250/ton of
NOX removed, which corresponds roughly to $500/ton of nitrogen
removed. (Similarly, NOX controls applied to Group 2 coal-fired
boilers have an average cost-effectiveness of $150/ton, or roughly
$300/ton of nitrogen removed.)
6. Visibility and Acidic Deposition Benefits
Nitrogen dioxide (NO2) and nitrate particulates also
contribute to pollutant haze, which impairs visibility and can reduce
residential property values as well as revenues generated by tourism,
national parks, etc.
Atmospheric deposition of nitrogen compounds is an important
component in the acidification of lakes and streams. Recent scientific
studies indicate the amount of nitrogen that can be sequestered in
certain watersheds by biological and other processes is limited (US
EPA, 1995). As these watersheds approach nitrogen saturation, nitrates
can begin to leach into surface waters, accelerating the process of
long-term chronic acidification. Further, according to EPA's Acid
Deposition Standard Feasibility Study Report to Congress, ``both
sulfates and nitrates originating from atmospheric deposition can
contribute significantly to episodic acidification events'' (US EPA,
1995:14). Episodic acidification occurs when highly acidic water, toxic
to fish, enter lakes and streams during storm flow or snowmelt runoff,
often during spawning season in the Spring. Acidified ecosystems can
show signs of recovery, however, following reductions in acidic
deposition rates. Environmental modeling performed for EPA's Acid
Deposition Standard Feasibility Study predicts benefits to varying
degrees in watersheds where atmospheric deposition of acidic compounds
has been and will continue to be reduced (US EPA, 1995). One study
conclusion is that additional limits on nitrogen deposition would
likely produce a two-fold potential benefit by reducing acidic
deposition rates and lengthening the average time for watersheds to
reach nitrogen saturation (US EPA, 1995:56).
Efforts are currently underway to further investigate the
mechanisms by which nitrogen deposition directly impacts or works with
other pollutants to damage structural and other materials (NAPAP,
1993).

E. Revised Emission Limits for Group 1 Boilers

EPA proposes, for the following reasons, that the Administrator
should exercise her discretion under section 407(b)(2) to revise the
emission limitations for Group 1 boilers to be more stringent. As
discussed above, analysis of the performance of LNBs on Group 1 boilers
shows that more effective low NOX burner technology is available.
Group 1 boilers subject to NOX emission limitations starting on or
after January 1, 2000 are capable of achieving, with LNBs: 0.45 lb/
mmBtu for dry bottom wall-fired boilers and 0.38 lb/mmBtu for
tangentially fired boilers. Further, revision of the limitations would
result in additional NOX reductions of about 200,000 tons
annually. In light of the significant, adverse impacts of NOX
emissions on human health and the environment, these additional
reductions would be beneficial. Finally, revision of Group 1 emission
limitations would be a cost-effective way of achieving these
reductions, relative to alternative pollution control strategies.
Therefore, EPA proposes to adopt the revised Group 1 emission
limitations.

F. Compliance Date

Industry has expressed concern about the regulated utility
community's ability to begin the Phase II program on January 1, 2000,
should EPA decide to revise the Group 1 emission limitations (see
docket A-92-15, item VIII-A-1, Brief of Petitioners, July 1, 1994). No
statutory provision exists for extension of the Phase II compliance
deadline analogous to the 15-month Phase I compliance extension
authorized by section 407(d) of the Act. Since four times as many Group
1 boilers are subject to NOX emission limitations in Phase II as
are in Phase I, industry spokespersons are concerned that utilities may
have barely enough time to procure LNB technology, schedule outages,
and install and test equipment, consistent with system reliability (see
docket A-92-15, item VIII-A-1, Brief of Petitioners, July 1, 1994).
Actual experience to date in preparing for Phase I, however,
indicates the anticipated technology shortage may not materialize. EPA
has received only 9 requests for the Phase I compliance extension.
Moreover, EPA has already received several inquiries about early
election for compliance with NOX emission limitations in Phase I
by units subject to NOX emission limitations starting in Phase II.
This suggests that an adequate supply of Group 1 LNB technology is
available.
EPA solicits comments from utilities and LNB technology vendors on
their ability to meet the statutory Phase II compliance date. Comments
advocating a compliance date extension should describe specific
problematic situations associated with the procurement and/or
installation of LNB technology and differentiate between site specific
and generic industry concerns.
EPA also requests comment on the need for a compliance extension
for boilers that must meet a more stringent title I NOX limit on a
date certain after the statutory title IV Phase II

[[Page 1456]]
compliance date, and on whether there is a legal basis for such
extension.

G. Definition of Coal-Fired Utility Unit

EPA proposes to revise the definition of ``coal-fired utility
unit'' as it applies to Phase II units. Under the current provision in
Sec. 76.2, any Phase II unit for which combustion of coal (or coal-
derived fuel) is more than 50.0 percent of the unit's annual heat input
in 1995 is a ``coal-fired utility unit'' and is therefore subject to
the Acid Rain NOX emission limitation for the unit's boiler type.
However, the current definition raises the question of whether the Acid
Rain NOX emission limitations apply to a unit that is designed to
combust, and has previously combusted, coal but is shutdown for all of
1995 and resumes operation thereafter. EPA sees no basis for treating
such a unit differently from another unit that is designed to combust
coal and operates during 1995 and thereafter.
Consequently, EPA proposes to revise the ``coal-fired utility
unit'' definition to include any Phase II unit that does not combust
any fuel that results in the generation of electricity during 1995 but
has combusted in any year during 1990-1995 fuel that comprised more
than 50 percent coal and that resulted in the generation of
electricity.

III. Control of NOX Emissions From Group 2 Boilers

A. Description of Group 2 Boilers

Under section 407(b)(2) of the Act, EPA is required to establish
NOX emission limitations (on a lb/mmBtu annual average basis) for
Group 2 boilers including wet bottom wall-fired boilers, cyclones,
units applying cell burner technology, and all other types of utility
boilers not classified as dry bottom wall fired and tangentially fired
boilers, by January 1, 1997. In the following sections, information is
presented on the basic design, population, and estimated uncontrolled
NOX emissions from each of these boiler types. For details
pertaining to this information, please refer to the Group 2 technical
support document (see docket item II-A-2, Investigation of Performance
and Cost of NOX Controls as Applied to Group 2 Boilers, pp. 2-1 to
2-4) and EPA's Regulatory Impact Analysis (see docket item II-F-2).
1. Basic Designs of Group 2 Boilers
Cell Burner Boilers. These boilers are dry bottom units that
consist of arrays of two or three closely-spaced circular burners in a
vertical assembly, i.e., the cell, mounted on opposed walls of the
furnace. Furnaces equipped with cell burners fire coal, oil, and
natural gas. Generally, in these furnaces, the close spacing of
circular burners results in hotter burner zones than those in dry
bottom wall-fired furnaces equipped with circular burners that are not
clustered. As a consequence, cell burner equipped boilers have high
combustion efficiencies but typically generate high levels of NOX
emissions.
Cyclone Boilers. Cyclone boilers are wet bottom units fired on
crushed coal. In these boilers, fuel and air are burned in horizontal
water-cooled cylinders, called cyclones. The arrangement of coal
burners and secondary air ports in a cyclone results in a spinning,
high temperature flame. Relatively high furnace temperatures in a
cyclone cause conversion of ash into a molten slag. This slag collects
on the cylinder walls and then flows down the furnace walls into a slag
tank located below the furnace. As a result of high furnace
temperatures, cyclone boilers are generally characterized by high
NOX emissions. Though cyclone boilers are wet bottom boilers, they
are not included in the wet bottom category due to their unique firing
pattern as explained above.
Wet Bottom Boilers. This type of boiler includes several firing
configurations (e.g., wall fired and vertically fired) and is
characterized by wall mounted burners, similar to those in dry bottom
units. However, the furnace temperatures in these boilers are generally
higher than those in corresponding dry bottom units, thereby resulting
in furnace zones hot enough to melt the ash. Slag produced by melting
of the ash flows down and is tapped off from the bottom of the furnace.
Vertically Fired Boilers. In these boilers, conventional circular
burners or coal and air pipes are oriented downward, rather than
horizontally as in wall-fired boilers. In general, these boilers have
more complex firing and operating characteristics than wall or
tangentially fired boilers. Several vertically fired furnace designs
are in operation today, including top-fired, roof-fired and arch-fired
configurations.
In top-fired and roof-fired boilers, burners are mounted on the
roof of the furnace and combustion gases flow downward and through a
superheater located at the bottom of the furnace. In arch-fired
boilers, burners mounted on lower furnace arches generate long, looping
flames and hot combustion gases discharge up through the center.
It should be noted that the vertically fired category consists of
only dry bottom boilers. Wet bottom vertically fired boilers are
included in the wet bottom boiler category, along with wet bottom wall-
fired boilers.
Stoker Boilers. Coal-fired stoker boilers range in size from 2,000
lb/hr to approximately 500,000 lb/hr steam generation capacity.
Practical design considerations limit stoker size and maximum steam
generation rates depending upon the type of fuel being fired. The major
types of stoker boilers include spreader stokers, underfed stokers, and
overfed stokers, which reflect the differences in the manner of coal
injection into the boiler. Additional stoker types or subcategories
(including traveling or chain grate, vibrating grate, and dumping
grate) reflect different methods of removing ash from the combustion
bed surface or grate.
FBC Boilers. Fluidized-bed combustors (FBC) range in size from
industrial boilers that produce less than 50,000 lb/hr of steam up to
utility-type boilers that generate hundreds of megawatts of power. In
these boilers, crushed coal in combination with some inert material
(e.g., silica, alumina, or ash) and air is maintained in a turbulent
suspended ``fluidized'' state and combusted at relatively low furnace
temperatures. FBC designs have been classified as either bubbling or
circulating, depending on the velocity of the solids moving through the
combustor. Additionally, these boilers can be designed to operate under
atmospheric or pressurized conditions, resulting in atmospheric FBC
(AFBC) or pressurized FBC (PFBC) systems.
2. Characterization of the Group 2 Boiler Population and Uncontrolled
NOX Emissions
Table 14, shown below, exhibits the differences in boiler types
with respect to population, nameplate capacity, size, and estimated
uncontrolled NOX emissions. This table has been developed using
the information presented in the EPA Group 2 Boiler Database found in
Appendix A of the Group 2 technical support document (see docket item
II-A-2, Investigation of Performance and Cost of NOX Controls as
Applied to Group 2 Boilers). Note, however, that this table excludes
certain units that are not expected to be in operation beyond the year
2000. A listing of these units can be found in EPA's RIA (docket item
II-F-2). EPA requests comment on the data presented in this table.

[[Page 1457]]

Table 14.--Characterization of Group 2 Boilers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Population Nameplate capacity Size mean range Estimated uncontrolled
------------------------------------------------------------------------------ NOX
Boiler type -------------------------
(Units) Percent (MWe) Percent (MWe) (MWe) (Tpy) Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cell-burner..................................... 35 16 24,060 36 690 38-1,300 668,000 38
Cyclone......................................... 88 41 27,495 41 310 33-1,150 732,000 41
Wet-bottom \7\.................................. 38 18 8,576 13 226 29-544 277,000 16
Vertically Fired \8\............................ 29 13 4,612 7 159 50-254 97,000 5
Stoker.......................................... 21 10 1,083 2 52 32-79 3,000 0
FBC............................................. 6 2 889 1 148 75-194 2,000 0
Total........................................... 217 100 66,715 100 ........... ........... 1,779,000 100
--------------------------------------------------------------------------------------------------------------------------------------------------------

B. NOX Control Technologies for Group 2 Boilers

1. Available Group 2 Boiler NOX Control Technology

\7\ NOX controls for wet bottom boilers of any firing
design have to be designed to not perturb furnace temperatures and
thereby not disturb slag tapping capability. Thus from the
standpoint of NOX control, wet bottom boilers of all firing
designs, including wall-fired and vertically fired boilers, are
grouped in one category: wet bottom boilers. The wet bottom category
in the above table includes several firing configurations, viz., 20
front wall fired, 5 opposed wall-fired, 4 arch fired, 3 turbo fired,
and 6 roof fired.
---------------------------------------------------------------------------

EPA considers a NOX combustion modification technology to be
available for a type of Group 2 boiler if there exists at least one
full-scale demonstration or commercial application of that technology
on that type of boiler. Further, if a utility has successfully applied
a combustion control technology on a full-scale boiler of that type,
then that technology is also considered to be available. EPA considers
a NOX post-combustion control technology to be available for each
type of boiler if it has been demonstrated on any full scale boiler.\9\
Because these latter controls are applied downstream of the combustion
process, they do not affect combustion and can be applied to any boiler
type.

\8\ The dry bottom, vertically fired category includes the
following designs: 5 arch fired, 12 roof fired, 3 top fired and 13
vertically fired.
\9\ The manufacturer of cyclone boilers, in a recent letter to
EPA dated October 27, 1995, stated that a significant portion of
cyclone boilers in the US cannot achieve 50% reduction in NOX
emissions using coal reburn.
---------------------------------------------------------------------------

Shown in Table 15 are full-scale NOX control retrofits that
have been installed or will be installed in the very near future in the
U.S. Using the information in this table, the following NOX
control technology and Group 2 boiler type combinations are considered
to be available.
Plug-in and non plug-in combustion controls on cell burner
boilers.
Coal reburning on cyclone boilers.
Gas reburning on cyclone boilers.
Selective non-catalytic reduction (SNCR) on all coal-fired
boilers.
Selective catalytic reduction (SCR) on all coal-fired
boilers.
Combustion controls on wet bottom and vertically fired
boilers.

Table 15.--Group 2 Boiler NOX Control Technology Demonstrations and Commercial Retrofits
----------------------------------------------------------------------------------------------------------------
Number of
full-scale Retrofit
NOX control technologies Boiler type or size range
commercial (MWe)
retrofits
----------------------------------------------------------------------------------------------------------------
Plug-In Retrofits (Low NOX Combustion Cell-Burner........................... 7 555-780
Controls).
Non Plug-In Retrofits (Combustion Controls and Cell-Burner........................... 3 630-760
Wall Replacements).
Coal Reburning................................ Cyclone............................... 1 110
Gas Reburning................................. Cyclone............................... 2 33-114
SNCR.......................................... Cyclone............................... 1 138
Wet Bottom............................ 1 321
Vertically Fired...................... 1 100
SCR........................................... Cyclone............................... 1 320
Wet Bottom............................ 1 \10\ 80
(321)
Combustion Controls........................... Wet Bottom............................ 1 217
FBC................................... 6 75-194
Vertically Fired...................... 4 100-152
----------------------------------------------------------------------------------------------------------------

Note that no NOX control demonstrations were found for stoker
boilers covered under title IV of the Act.

\10\ SCR system was installed only in one of four ducts of the
321 MWe boiler, and only one quarter of the total unit's flue gas
volume passes through the SCR system (equivalent to 80 MWe).
---------------------------------------------------------------------------

2. Description of Group 2 Boiler NOX Control Technologies
Basic descriptions of the NOX control technologies that EPA
considers available for Group 2 boilers are provided in this section.
For more details on these technologies and their applications on Group
2 boilers, please refer to the Group 2 technical support document (see
docket item II-A-2, Investigation of Performance and Cost of NOX
Controls as Applied to Group 2 Boilers, pp. 3-1 to 3-36) and 57 FR
55648-49 (November 22, 1992). Additional information can be found in
site reports written by EPA personnel who inspected certain Group 2
boilers applying NOX control technologies (see docket items II-B-1
through II-B-6).
Combustion Controls for Cell Burner Boilers. In plug-in combustion
control retrofits, all existing cells in a furnace are replaced by
either low NOX burners or by using the existing cell burner
openings to install low NOX burners in combination with overfire
air ports. To date, these controls have been applied to two-nozzle cell
burners, and their

[[Page 1458]]
installation requires no modifications to boiler pressure parts and
only minor modifications to burner piping. EPA believes that this
technology can be modified and adapted to three-nozzle cell burner
configurations.
Non plug-in combustion control retrofits have been applied to all
types of cell burner configurations. With this approach, portions of
the furnace walls containing cells are replaced by new walls containing
low NOX burners or low NOX burners with overfire air. This
technology has been applied to both two-nozzle and three-nozzle cell
burner configurations and essentially converts the cell-burner firing
arrangement to a conventional wall-fired arrangement.
Reburning. Reburning is a low NOX combustion technology in
which part of the main fuel heat input is diverted to a location above
the main burners, thus creating a secondary combustion zone called the
reburn zone. Completion or overfire air (OFA) is added above the reburn
zone to complete the burnout of the reburn fuel. The reburn fuel can be
natural gas, pulverized coal, or oil. The arrangement of injection of
reburn fuel and OFA causes the reburn zone conditions to be sub-
stoichiometric. As flue gas passes through this sub-stoichiometric
zone, part of the NOX formed in the main combustion zone is
reduced by radical fragments and converted to molecular nitrogen. The
source for these radical fragments is the combustion gas from the
secondary, or reburning, fuel fired in reburn injectors or burners.
Selective Non-catalytic Reduction (SNCR). SNCR is a post-combustion
NOX control technology that injects a reducing agent (urea,
ammonia, or cyanuric acid) into the boiler's flue gas for NOX
control. The reducing agent reacts with NOX in the flue gas to
form molecular nitrogen and water. The SNCR reactions take place in a
temperature range of 1600 to 2100 deg.F.
Selective Catalytic Reduction (SCR). SCR is a post-combustion
NOX reduction process in which ammonia is added to the flue gas,
which then passes through layers of a catalyst. The ammonia and the
NOX react on the surface of the catalyst, forming molecular
nitrogen and water. The temperature window for SCR reactions is between
575 and 750 deg.F.
Combustion Controls for Vertically Fired, Wet Bottom, and FBC
Boilers. Combustion staging concepts are currently being applied at
vertically fired boilers (see docket items II-A-2, Investigation of
Performance and Cost of NOX Controls as Applied to Group 2
Boilers, p. 3-18; II-B-4; and II-B-6). Specifically, these concepts
involve redistributing coal and primary air flows to establish a
primary fuel rich zone and redistributing secondary air flow to create
a secondary fuel rich zone. Burnout is completed by providing staged
burnout air. A combustion staging system using two levels of overfire
air is being installed in the Fall of 1995 by a utility on a wet bottom
boiler (see docket items II-A-2, Investigation of Performance and Cost
of NOX Controls as Applied to Group 2 Boilers, p. 3-18; and II-D-
30). All the FBC boilers subject to section 407(b)(2) already have
combustion controls.

C. Statutory Requirements

Section 407(b)(2) of the Act requires the Administrator to set, by
January 1, 1997, annual emission limitations for NOX for units
with Group 2 boilers, i.e., wet bottom wall-fired boilers, cyclones,
units applying cell burner technology, and ``all other types of utility
boilers''. 42 U.S.C. 7651f(b)(2). The Administrator must base these
emission limitations on

the degree of 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 oxides
controls set pursuant to [section 407] (b)(1). Id.

Section 407(b)(2) thus provides instruction to the Administrator
for setting Group 2 emission limitations based on what reductions can
be achieved by the best continuous control technologies. First, the
costs of the control technologies on which the Administrator bases
Group 2 emission limitations must be ``comparable'' to the costs of low
NOX burner technology as applied to Group 1 boilers. The statute
does not explain what is meant by ``comparable'' costs or how ``costs''
are to be measured. These matters are left to interpretation by the
Administrator in applying section 407(b)(2). See Chevron, U.S.A. v.
NRDC, 467 U.S. 837, ____ (1984). However, the legislative history
provides some assistance in the interpretation of the comparable-cost
requirement.

As explained by the Conference Report to the Clean Air Act
Amendments of 1990,
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).

The relevant portion of the Senate Report, which is referenced in
the Conference Report, discusses the cost-effectiveness and difficulty
of reducing NOX emissions, explaining that the Senate bill
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 metholology
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).

In short, the legislative history explains that comparability of
costs is to be determined by comparing the cost-effectiveness, measured
as costs per ton of NOX removed, of NOX control technologies
on Group 2 boilers with that of low NOX burner technology on Group
1 boilers. In addition, the Senate Report, which was expressly relied
on in the Conference Report, indicates that a control technology (SCR)
with a cost-effectiveness of $600 per ton of NOX removed was
regarded as having a cost comparable to that of low NOX burner
technology. At the time the Senate Report was issued, the cost of low
NOX burner technology was thought to be about $150 to $200 per ton
of NOX removed. Id. at 470.
In addition to the cost-comparability requirement, section
407(b)(2) requires that, in setting Group 2 emission limitations, the
Administrator must ``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

[[Page 1459]]
balance and apply these factors. In particular, the Administrator must
decide how to evaluate the factors and what relative weight to give
each factor.

D. Methodology for Establishing 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, as detailed in Section III.B, EPA has taken the approach of
determining what NOX control technologies are available for each
category of Group 2 boilers and basing Group 2 emission limitations
only on such technologies. EPA has considered a combustion control
technology available for a Group 2 boiler category only if the
technology has been demonstrated on a full-scale boiler in that
category. Because post-combustion technology is applied downstream of
combustion hardware, a post-combustion technology was considered
available for any boiler type if it has been demonstrated on any full-
scale boiler.^{11 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.

\11\ See footnote 9.
---------------------------------------------------------------------------

Second, as detailed in Section III.E, EPA evaluated each
demonstrated control technology and estimated 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 compared the dollar cost per ton of NOX removed for the
entire Group 2 population to the dollar cost per ton of NOX
removed for low NOX burners applied to the entire Group 1
population. In addition, EPA compared the dollar cost per ton of
NOX removed for each Group 2 boiler category (using the
appropriate control technology) with the dollar cost of NOX
removed with low NOX burners on Group 1 boilers. For technical
reasons discussed below, EPA chose to adopt a somewhat different cost
comparison methodology than the methodology outlined in Appendix B of
the March 22, 1994 Acid Rain NOX regulations (59 FR 13538, 13578
(March 22, 1994)).
Section 407(b)(1) requires the Administrator to set emission
limitations for Group 1 boilers (i.e., dry bottom wall-fired and
tangentially fired boilers) for Phase I and Phase II based on what
emission limitations can be achieved ``using low NOX burner
technology.'' 42 U.S.C. 7651(b)(1). Only if the Administrator
determines that ``more effective low NOX burner technology is
available'' may the Group 1 emission limitations under section
407(b)(1) be revised for boilers that first become subject to Acid Rain
SO2 and NOX emission limitations in Phase II. 42 U.S.C.
7651(b)(2).
In short, the NOX emission limitations set in section
407(b)(1) based on low NOX burner technology apply to all Group 1
boilers, whether they are first subject to limitations in Phase I or
Phase II. Any revisions to these emission limitations must also be
based on low NOX burner technology. EPA concludes that the
``nitrogen oxides controls set pursuant to section 407(b)(1)'' are low
NOX burner technology applied to all Group 1 boilers. Id. EPA
therefore believes that section 407(b)(2) requires that the costs of
the control technologies used to set emission limitations for Group 2
boilers be comparable to the costs of low NOX burner technology
applied to all Group 1 boilers.
By considering only Group 1, Phase I boilers that have reported low
NOX burner technology cost information, the methodology originally
specified in Appendix B eliminates over 90% of the Group 1 boilers from
the comparative analysis. This limitation, together with other
constraints in the methodology, results in a dataset only marginally
adequate for estimating NOX control costs in a manner consistent
with the intent of section 407(b)(2). The population pertinent to the
determination, under section 407(b)(2), of Group 1 boiler NOX
control costs is all Group 1 boilers employing or projected to employ
low NOX burner technology ^{12 to meet the section 407(b)(1)
emission limitations. That is the population EPA has used in the
proposed rule for establishing emission limitations for Group 2
boilers.

\12\ Consistent with the Appendix B methodology, boilers
employing low NOX burner technology installed prior to passage
of the Act were not considered.
---------------------------------------------------------------------------

The Appendix B methodology also specifies using the ``average cost-
effectiveness (in annualized $/ton NOX removed) of installed low
NOX burner technology applied to Group 1, Phase I boilers'' (60 FR
18776) as the basis for identifying comparably cost-effective Group 2
control technologies for the purposes of setting emission limitations
for Group 2 boilers. EPA discovered that, for distributions with broad
ranges, an analysis based solely on measures of central tendency (e.g.,
mean, median, mode, or ``average'') always neglects important
information about the spread and shape of the distribution. Based on
the actual data that became available in late 1995, EPA has determined
that the projected cost-effectiveness of low NOX burner technology
applied to Group 1 boilers, and the projected cost-effectiveness of
NOX control technologies applied to Group 2 boilers are such
distributions. The values range from $50/ton to over $1600/ton. Thus,
restricting the comparative analysis to the comparison of a single
measure of central tendency, such as the average value of the cost-
effectiveness of low NOX burner technology applied to Group 1
boilers, results in a substantial loss of information. Therefore,
rather than simply comparing averages, a more illuminating and
statistically defensible evaluation would be based on a comparison of
ranges of cost-effectiveness and percentages of boilers in each
distribution projected to experience similar cost-effectiveness.
EPA has adopted Appendix B when determining the capital cost (in $/
kW) of low NOX burners. However, considering the serious,
unanticipated limitations in the Appendix B methodology for estimating
and comparing NOX control cost-effectiveness (in $/ton) for Group
1 and Group 2 boilers, EPA has decided to include all Group 1 boilers
in the analysis and to broaden the original concept of ``average'' to
include ranges of cost-effectiveness and percentages of boilers in each
population projected to experience similar cost-effectiveness. As a
result, EPA proposes to delete Section 3 of Appendix B from part 76 and
make limited modifications to the remaining portions of Appendix B
consistent with the approach taken in today's proposal. EPA requests
comment on whether it should delete Section 3 of Appendix B from part
76 or follow Appendix B or otherwise modify Appendix B. Further details
on the rationale for expanding the original concept of ``averaging'' to
include ranges of cost-effectiveness and percentages of boilers
projected to experience similar cost-effectiveness can be seen in the
docket item II-A-7, Draft Report, Costs of Low NOX Burner
Technology Applied to Dry Bottom Wall-Fired and Tangentially Fired
Boilers, EPA Acid Rain Division, November 30, 1995.
EPA also seeks comment on the proper interpretation of the term
``comparable to the cost'' as used in section 407(b)(2). Specifically,
EPA is seeking comment on the appropriate approach for comparing
control technology costs for Group 1 boilers and Group 2 boilers,
pursuant to this section of the Act. Such comments should include both
the format of the cost which should be addressed (e.g., capital cost,
cost per unit of power, cost-effectiveness) and the procedure for

[[Page 1460]]
calculating the cost (e.g., data sources, mathematics, unit size
constraints etc.).
Based on the above-discussed statutory language and legislative
history, EPA maintains that it is reasonable to interpret the cost-
comparability provision to require that the distribution of costs per
ton of NOX removed for the Group 2 control technologies be
similar, but not necessarily equal, to the distribution of costs per
ton of NOX removed for low NOX burners as applied to Group 1
boilers.
Third, in Section III.E, EPA estimated the change in electricity
rates for consumers resulting from cost (in mills per kilowatt-hour)
associated with application of NOX controls on Group 2 boilers.
The Agency maintains that it is reasonable to interpret the required
consideration of ``costs and energy * * * impacts'' under section
407(b)(2) to involve the determination of the resulting effect of Group
2 boiler NOX controls on electricity consumers. 42 U.S.C. 7651f
(b)(2). In order to put the energy impact in perspective, EPA
determined the average percent change in electricity rates experienced
by consumers being served by utilities using Group 2 boilers due to the
establishment of emission limitations on Group 2 boilers. This value
was then compared to the percent change in nationwide electricity rates
due to the establishment of emission limitations for LNBs on Group 1
boilers.
Fourth, in Section III.F, EPA assessed the performance of each
cost-comparable Group 2 control technology. The assessment was based on
data from industry and government sources on the size of NOX
emission reductions achievable using the control technology on the
appropriate type of Group 2 boiler. Based on this data, EPA determined
the percentage NOX emission reduction that is reasonably expected
to be achieved.
The expected performance of the control technologies was considered
in setting an emission limitation for the relevant boiler type unless
EPA determined that, where a technology's performance was expected to
be significantly inferior to that of another appropriate technology,
the less effective technology was not ``the best system of continuous
emission reduction.'' 42 U.S.C. 7651f (b)(2). EPA applied each
technology's expected 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. It
was then determined what percentages of that boiler population will be
able to achieve, on an individual boiler basis, a given set of possible
NOX emission limitations. The emission limitation that will be
achievable by approximately 90 to 95% of the boiler population was
selected as the emission limitation for that category of Group 2
boiler.
EPA chose to base the emission limitation on the emission rate that
a target of about 95% of the population will be able to meet. This
approach is more relaxed than that used in revising the Group 1
emission limitations because there is less data available on Group 2
boiler NOX controls. The approach, however, is analogous to the
approach used in setting NOX emission limitations under section
407(b)(1) for Phase I, Group 1 boilers. The same options (averaging and
alternative emission limitations) providing compliance flexibility for
Phase I, Group 1 boilers unable to meet emission limitations on an
individual boiler basis are available for all boilers under today's
rule. EPA, however, solicits comment whether the approach being used
for setting emission limitations for Group 2 boilers should be
consistent with that being used in revising Group 1 emission
limitations.
The Agency also assessed the total amount of NOX emission
reductions that may potentially be achieved through use of each
available, cost-comparable Group 2 control technology. The change in
levels of other pollutants that may result from such reductions were
also evaluated. This is a reasonable implementation of the requirement
under section 407(b)(2) that the Administrator take account of the
environmental impact of Group 2 control technologies.
Finally, after weighing the projected performance and energy and
environmental impacts of each available cost-comparable Group 2 control
technology, EPA established NOX emission limitations for Group 2
boiler types based on the appropriate control technologies.

E. Characterization of Costs

1. Low NOX Burners Applied to Group 1 Boilers
Determination of the cost per ton of NOX removed for the Phase
I low NOX burners was based on the cost data reported to EPA by 30
Group 1 units \13\ (22 wall-fired and 8 tangentially fired boilers).
The reported capital costs ($/kW) were analyzed incorporating cost
savings due to multiple retrofits at one plant. The resulting cost
functions ($/kW vs. MWe) were then levelized and added to estimated
annual operating and maintenance costs to arrive at total levelized
costs functions (mills/kWh vs. MWe). In arriving at these total costs,
the following assumptions were used: (1) a standard capital carrying
charge of 11.5%, (2) plant life of 20 years, and (3) a standard
operation and maintenance (O&M) cost, including fixed O&M cost of 1.5%
\14\ of the installed capital cost for annual maintenance and a
variable O&M cost accounting for a 0.27% loss in thermal efficiency for
retrofit of LNB on wall-fired boilers only. Further, tons of NOX
removed were calculated for each boiler using the correlation between
NOX reduction (percent) and uncontrolled NOX emission rate
(lb/mmBtu). Finally, a cost-effectiveness equation, as a function of
uncontrolled NOX emission rate and capacity factor, was derived
for the Group 1 LNBs. Note that all cost functions were computed in
1990 dollars in order to allow comparison of Group 1 and Group 2
control costs using dollars as of the enactment of the Clean Air Act
Amendments of 1990. Details of obtaining cost-effectiveness functions
for Group 1 LNBs can be found in (see docket items II-A-11, Capital and
Annualized Costs of Low NOX Burner Technology Applied to Phase I,
Group 1 Boilers; and II-A-12, Distributions of Cost Effectiveness by
Technology) and in EPA's Regulatory Impact Analysis (see docket item
II-F-2 ) of this proposed regulation.

\13\ A utility that wishes to submit cost information to augment
EPA's analysis should use EPA Form 76B-26, titled NOX Control
Costs for Group 1, Phase I Boilers.
\14\ EPA seeks comment on its use of assuming fixed O&M cost of
1.5% or using actual data as reported.
---------------------------------------------------------------------------

The cost-effectiveness function was then applied to each boiler in
the Group 1 population that was above 0.45 lb/mmBtu, for tangentially
fired boilers, or above 0.50 lb/mmBtu, for wall-fired boilers, taking
into account each boiler's actual usage and uncontrolled NOX
emission rate. Figure 3 shows the distribution of costs that the Group
1 boiler population experiences when applying LNBs.

BILLING CODE 6560-50-P

[[Page 1461]]
[GRAPHIC][TIFF OMITTED]TP19JA96.002

BILLING CODE 6560-50-C

[[Page 1462]]

2. NOX Controls Applied to Group 2 Boilers
With regard to the cost per ton of NOX removed for each Group
2 control technology, EPA used the following procedure. Models for
Group 2 boiler type/available NOX control technology combinations
were created using information obtained from site visits to Group 2
boilers applying NOX controls, a major A&E firm's boiler database,
commercial applications, and published literature. EPA seeks comment on
the accuracy of this data and requests additional data. Using
information from the above sources, capital costs were estimated for
these models. Subsequently, using the same approach and assumptions
used in the levelization of Group 1 LNB costs, cost-effectiveness
equations as a function of uncontrolled NOX emission rate and
capacity factor were obtained for each Group 2 boiler type/available
NOX control technology combination. This cost analysis used a
modified EPRI class II approach (see docket item II-A-2, Investigation
of Performance and Cost of NOX Controls as Applied to Group 2
Boilers, p. 4-3). The details of estimates of costs of Group 2 boiler
NOX controls can be found in (see docket item II-A-2,
Investigation of Performance and Cost of NOX Controls as Applied
to Group 2 Boilers, p. 4-1 to 4-40) and in EPA's RIA (see docket item
II-F-2).
The capital costs developed for each technology case reflect costs
of retrofitting these technologies under expected site conditions at
typical Group 2 boiler installations. \15\ The following steps were
taken to ensure that the retrofit nature of these costs are properly
represented:

\15\ For example, in the SCR analysis EPA assumed a catalyst
space velocity equal to 4,900 hr^{-1 for achieving a 50% NOX
reduction.
---------------------------------------------------------------------------

A detailed equipment list was developed for each
technology application. This list identified all major new equipment as
well as modifications required to the existing plant equipment.
In developing the various cost estimates, allowances were
made for dismantling and removal of unwanted equipment.
Contingency allowances were provided to cover cost
increases associated with uncertain site factors and to cover any
unexpected costs associated with retrofitting of large equipment.
In developing cost estimates for each technology, costs
associated with non-standard (i.e., non-essential, or special case)
modifications to the existing plant equipment were also accounted for.
As a check, the costs thus developed were also compared and ensured
to be consistent with those incurred at existing demonstration or
commercial retrofits. It is important to note that retrofits at
demonstration projects are not necessarily the easiest possible ones.
For example, as noted in docket items II-D-28: Response to questions
regarding application of selective catalytic reduction (SCR) to wet-
bottom boilers, and to Public Service of New Hampshire's Merrimack 2
unit and II-B-6: Trip Report: visit to Merrimack Unit 2, SCR Retrofit,
Merrimack Generating Station, Bow, New Hampshire, June 14, 1995, the
SCR application at Merrimack 2 required significant ductwork.
The cost-effectiveness equations for Group 2 boiler/ available
NOX control technology combinations were then applied to each
boiler of the appropriate boiler population to arrive at cost-
effectiveness distributions for Group 2 boiler NOX controls. In
performing these computations, EPA assumed that only those boilers with
NOX emission rates above the applicable emission limits would
install technology. This assumption was made in order to provide a more
realistic picture of the cost-effectiveness distributions. The details
on the procedure for obtaining cost-effectiveness distributions can be
found in EPA's RIA.
3. Comparison of Group 2 Boiler NOX Control Costs to Low NOX
Burner Costs
As discussed above, in order to determine whether NOX control
technologies as applied to Group 2 boilers are comparable in cost to
low NOX burners as applied to Group 1 boilers, EPA determined the
cost-effectiveness of each of the NOX control technologies applied
to each boiler in the respective boiler populations. In determining
each boiler/control technology cost-effectiveness distribution, EPA
used each boiler's actual usage and uncontrolled NOX emissions.
Additionally, since in today's proposal EPA is exempting cyclone
boilers below 80 MWe, the exempted boilers are excluded from the cost
effectiveness distributions. Next, the distribution of overall cost-
effectiveness for Group 2 boiler NOX controls was compared to the
distribution of overall cost-effectiveness for Group 1 LNBs (see Figure
3). Figure 4 illustrates this comparison.

BILLING CODE 6560-50-P

[[Page 1463]]
[GRAPHIC][TIFF OMITTED]TP19JA96.003

BILLING CODE 6560-50-C

[[Page 1464]]

The upper and lower 10 percent of each distribution shown in Figure
4 were then excluded in order to compare each distribution without the
influence of outliers. EPA determined that the costs for LNBs applied
to Group 1 boilers (with outliers removed) ranged from $121/ton to
$1,264/ton. The Group 2 NOX control costs (with outliers removed)
ranged from $71/ton to $710/ton. These ranges, tabulated in Table 16,
indicate that, excluding outlier, Group 2 boilers applying NOX
controls will experience costs within the range of costs experienced by
Group 1 boilers applying LNBs.
Further, EPA determined the range in costs resulting from the
application of each available NOX control technology on each Group
2 boiler type and LNB application on each Group 1 boiler type
separately. Subsequently, to provide additional support for cost
comparisons, the individual Group 2 boiler/NOX control technology
cost distributions were compared to the Group 1 boilers cost
distribution. Table 16 characterizes these cost distributions and the
percentage of each Group 2 boiler type population that are expected to
experience costs within the range of costs experienced by Group 1
boilers applying LNBs.

Table 16.--Distribution of Cost-Effectiveness of NOX Controls ($/Ton NOX Removed)
----------------------------------------------------------------------------------------------------------------
Percent
boilers
10th 90th below group
Boiler/NOX control technology percentile percentile Median 1 90th
percentile
cost
----------------------------------------------------------------------------------------------------------------
Group 1/LNBs................................................ 121 1264 403 NA
Group 2/NOX Controls........................................ 71 710 207 100
Cell Burners/Plug-ins....................................... 57 179 103 100
Cell Burners/Non Plug-ins................................... 75 228 129 100
Cyclones/Coal Reburning..................................... 311 897 492 100
Cyclones/Gas Reburning...................................... 371 728 555 100
Cyclones/SCR................................................ 379 895 574 100
Cyclones/SNCR............................................... 426 854 635 100
Wet Bottoms/Combustion Controls............................. 51 148 73 100
Wet Bottoms/SNCR............................................ 356 779 458 100
Verticals/Combustion Controls............................... 126 688 196 100
Verticals/SNCR.............................................. 651 1,400 831 79
FBCs/Combustion Controls.................................... 0 0 0 100
----------------------------------------------------------------------------------------------------------------

With one exception, each Group 2 boiler/NOX control technology
combination experienced costs within the range of costs for Group 1
boilers applying LNBs. After examining the cost comparisons presented
in this section, EPA determined that the following Group 2 boiler/
NOX control technology combinations are comparable in cost to
Group 1 LNBs:
Cell burner boilers applying either plug-in or non-plug-in
combustion controls.
Cyclone boilers applying coal reburning, gas reburning,
SCR, or SNCR.
Wet bottom boilers applying combustion controls or SNCR.
Vertically fired boilers applying combustion controls.
FBC boilers applying combustion controls.
As discussed below, DOE prepared an independent analysis concerning
cyclone boilers, based on different assumptions and data than those
used by EPA (see docket item II-D-62, Analysis of Proposed Section
407(b)(2) NOX Rule, Department of Energy, Staff Paper, December
14, 1995). In this analysis, DOE data for existing applications of LNBs
were used to project compliance costs for Group 1 boilers and the
results were compared to DOE's projections of cost and performance
estimates for SCR and other technologies for controlling NOX
emissions from cyclone boilers. Based on these comparisons, DOE
concluded that both cost per unit of electricity generated and cost-
effectiveness of controls for cyclone boilers appear to be several
times that of LNBs for Group 1 boilers (see docket item II-D-62,
Analysis of Proposed Section 407(b)(2) NOX Rule, Department of
Energy, Staff Paper, December 14, 1995). EPA requests comment on this
analysis.
In its development of costs for the application of gas reburning on
cyclone boilers, EPA used a gas-coal price differential of Sec. 1.23/
mmBtu (1990 dollars). EPA believes that this price differential is
similar to recent projections for the year 2010. However, the cost of
gas reburning is very sensitive to the gas-coal price differential
assumed in the analysis. If a differential of $1.00/mmBtu were assumed,
the cost-effectiveness would range from $295 to $588 per ton NOX
removed. Similarly, if a differential of $2.00/mmBtu were assumed, the
cost-effectiveness would range from $617 to $1,200 per ton NOX
removed. EPA solicits comment on the gas-coal price differential used
in the cost analysis of gas reburning.
Although EPA has not presented gas reburning applied to wet bottom
boilers, other than cyclones, in the above analysis, EPA is soliciting
comment on whether this NOX control technology as applied to this
boiler type is comparable in cost to low NOX burner technology and
meets the requirements under section 407 (b)(2).
EPA also assessed the energy impacts of Group 2 NOX controls
by determining the average percent change in electricity rates
experienced by consumers that are served by utilities operating Group 2
boilers due to the establishment of emission limitations for Group 2
boilers. The energy impact was an estimated 0.35 % increase in
electricity rates. EPA then determined the percent change in
electricity rates that the same consumers would experience due to the
establishment of emission limitations for LNBs on Group 1 boilers. The
energy impact due to the Group 1 controls was an estimated 0.36 %
increase in electricity rates. Comparing these two values, the energy
impacts of Group 2 controls are slightly less than the energy impacts
of Group 1 LNBs. (Values were derived assuming an average cost of
generating electricity equal to 40 mills/kWh.) This factor was weighed,
along with the other factors required to be considered used section
407(b)(2), in deciding what emission limitation to establish for each
Group 2 boiler category.

[[Page 1465]]

F. Emission Limits for Group 2 Boilers

1. Cell Burner Boilers
Performance of NOX Controls. Because plug-in and non plug-in
NOX combustion controls, applied to cell-burner boilers, meet the
cost-comparability requirement, the performance of these controls is
assessed to determine what performance standards are achievable. Table
17 shows various measurements and estimates of the percentage reduction
and controlled emission rates for plug-in and non plug-in NOX
controls on cell burner boilers.

Table 17.--NOX Reduction Performance for Available NOX Controls
--------------------------------------------------------------------------------------------------------------------------------------------------------
NOX control for cell-burner boilers
---------------------------------------------------------------------------------------------------------------------
Plug-in Non plug-in
Source ---------------------------------------------------------------------------------------------------------------------
Controlled emission Controlled emission
Percent reduction rate (lb/mmBtu) Percent reduction rate (lb/mmBtu)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ETS Data:
J.M. Stuart #4................ 52.............................. 0.523 ^{16
Muskingum #5.................. 52.............................. 0.541 ^{16
Retrofit Applications:
Muskingum #5 (585 MWe)........ >50............................. 0.59 ^{17
Stuart #4 (605 MWe)........... >50............................. <0.58>^{17
Hatfield's Ferry #2 (555 MWe). 50.............................. 0.58 ^{17
Monroe #1 (780 MWe)........... 44.............................. 0.52 ^{17
Sammis #6 (630 MWe)........... ................................ ...................... 65 (long term)..................... 0.32-0.47
Four Corners #4 (760 MWe)..... ................................ ...................... 40-58 (>70 of MCR ^{18).............. 0.49 (MCR)
Brayton Point #3 (500 MWe).... ................................ ...................... 70 (target)........................ NA
DOE............................... 50.............................. NA.................... 35-70 (LNB + OFA).................. NA
EPRI.............................. 40-53........................... NA.................... NA................................. NA
UARG.............................. 44-50 (short term).............. NA.................... NA................................. NA
50 (long term)..................
--------------------------------------------------------------------------------------------------------------------------------------------------------

ETS data shown in the above table suggest that plug-in controls on
cell burner boilers can achieve 52% NOX reduction from full-load,
over the long term. Non-plug-in burners, which essentially convert the
cell burner boiler to a conventional wall-fired boiler, are expected to
reduce NOX by over 50%, as illustrated in the above table. Boilers
that retrofit this NOX control technology become conventional
wall-fired boilers and can therefore emit at NOX levels below 0.45
lb/mmBtu (see section II). However, EPA has chosen to base the NOX
emission limitations on 50% NOX reduction. This conservative
approach is taken because there are only two boilers for which ETS data
are available and because, as shown in the above table, data from all
but one of the commercial applications and the bulk of information from
industry representatives and DOE suggest that overall, 50% NOX
reduction is attainable by plug-in burners.

\16\ Best 52-day controlled NOX emission rate, determined
per methodology outlined in Section II.
\17\ Full load short-term test.
\18\ MCR is the maximum continuous rating of a boiler
---------------------------------------------------------------------------

As shown in Table 17, the controlled emission rates obtained from
ETS are lower than the rates reported in literature for Stuart Unit #4
and Muskingum River Unit #5. This is a result of ETS data being long-
term as opposed to short-term full-load data that is the source of the
values reported in literature.
Industry commenters were concerned that cell burner boilers
retrofit with plug-in burners would have problems sustaining a certain
NOX emission rate over the course of a year. EPA has been informed
by the owner/operator of Muskingum River #5 that since the beginning of
1995, the boiler switched to firing low sulfur compliance coal without
re-optimizing the coal/air feed system. This caused flame detachment at
the burner, thereby increasing the NOX emissions to
0.7 lb/mmBtu. EPA believes that once this boiler is re-
optimized for the new coal, the NOX emissions will decrease to
previous levels. The owner/operator of Stuart #4 informed EPA that this
unit's NOX emissions increased in the Fall of 1994 and decreased
again to original levels after the Winter of 1994. EPA believes this
may be a result of coal composition temporarily influencing the
NOX emissions; this condition may therefore be corrected with
boiler re-optimization.
Achievable Emission Limit. Applying the projected 50% emission
reduction to the uncontrolled emissions of each boiler in the cell-
burner population for which NOX limits are to be set under section
407(b)(2), EPA determined how many of the boilers could achieve various
NOX performance standards. The following table shows the NOX
performance standards levels achievable by between 88.9% and 100% of
that cell-burner population.

Table 18
------------------------------------------------------------------------
Number Percent
of of
boilers boilers
NOX level (lb/mmBtu) meeting meeting
NOX NOX
level level
------------------------------------------------------------------------
0.79................................................. 35 100
0.73................................................. 34 97.1
0.68................................................. 33 94.3
0.67................................................. 32 91.4
0.65................................................. 31 88.6
------------------------------------------------------------------------

Table 18 indicates that 94% of the 36 cell burner boilers can
achieve a NOX controlled emission rate of 0.68 lb/mmBtu.

BILLING CODE 6560-50-P

[[Page 1466]]
[GRAPHIC][TIFF OMITTED]TP19JA96.004

BILLING CODE 6560-50-C

[[Page 1467]]

Note that the proposed emission limit is greater than the
controlled emission rates shown in Table 17. EPA has calculated the
uncontrolled emission rates of cell burner boilers to be as high as
1.57 lb/mmBtu and on average 1.02 lb/mmBtu. The boilers shown in Table
17 (JM Stuart #4 at 1.11 lb/mmBtu and Muskingum River #5 at 1.12 lb/
mmBtu), though having uncontrolled emissions above the mean emission
rate of the cell burner population, are significantly lower than the
uncontrolled emission rates of some boilers. Since, as illustrated in
Figure 5, the emission limit is based on approximately 95% of the
population meeting it, the effect of the higher emitting boilers drives
the emission limit towards the high end of the controlled emissions
distribution.
Environmental Impacts. According to EPA's Regulatory Impact
Analysis, the establishment of 0.68 lb/mmBtu as the emission limit for
cell burner boilers will result in a total NOX emissions reduction
of 284,000 tons per year. As shown in the EPA's technical support
document, these reductions will be achieved without increases in other
air pollutants such as CO or SO2. In fact, applications to date
show a decrease in particulates by as much as 50% as a result of plug-
in and non-plug-in retrofits on cell burner boilers.
Additionally, in applications to date, there have been no increases
in unburned carbon (UBC) with the application of plug-ins on cell
burner boilers. For boilers with non plug-in retrofits, an increase in
UBC has been observed. This increase is similar to, or lower than,
increases in UBC observed in dry bottom wall-fired boilers retrofitting
LNBs. Additionally, the EPA has identified vendors of technology that
lowers unburned carbon levels from boilers by optimizing the combustion
process (see docket item II-D-15). Further, one vendor provides
technology that removes unburned carbon from the flyash (see docket
item II-D-13). This process splits the flyash into two parts, one high
in carbon and one very low in carbon. The high carbon flyash can be re-
combusted in the boiler, while the low carbon flyash can be sold to
cement companies. The economic impact of installing such technologies
is negligible, compared to the benefits of selling flyash and not
needing to dispose of it.
Issues Raised. Applicable Emission Limit. EPA investigated whether
boiler operating conditions after January 1, 1995 affected the
controlled NOX emission rate, using CEM measured data submitted to
EPA's Emissions Tracking System (ETS). To date, no substantial
differences between NOX emission rates before and after January 1,
1995, have been observed. EPA believes that the utilities can receive
NOX emission guarantees for various coal types from manufacturers
of NOX control equipment. The manufacturers of control equipment
appear to design for a certain controlled NOX emission rate taking
into account various coal types.
Increased Boiler Corrosion. EPA also investigated whether the
application of combustion NOX controls on cell burner boilers
would cause corrosion or erosion of furnace walls. These impacts could
affect costs associated with such retrofits. However, major vendors of
plug-in and non plug-in combustion controls on cell burners (Babcock &
Wilcox and Riley Stoker), as well as utilities, have not found
significant corrosion and erosion problems associated with applications
of this technology to date.
Conclusions. For the following reasons, EPA concludes that 0.68 lb/
mmBtu is a reasonable emission limitation that meets the requirements
of section 407(b)(2). First, plug-in burners applied to cell burner
boilers are an available control technology that meets the cost-
comparability requirement. Second, a second available control
technology, non plug-in retrofits, also meets the cost-comparability
requirement. This technology can be applied to 3-cell configurations if
plug-ins are not effective. Because it is capable of greater NOX
reduction efficiency than plug-ins, it can meet the 0.68 lb/mmBtu
emission limit. Third, an emission limit of 0.68 lb/mmBtu is achievable
in that it can be met by 94% of the cell burner population with the
application of plug-in or non plug-in burners at a 50% NOX removal
efficiency. ETS data for two cell-burner boilers that have already
installed such controls were at or below this limit 94% of the time
they were operated. Fourth, as shown in section III.E, the energy
impact, i.e. the cost impact on electricity consumers, of using the
available control technologies to meet the recommended emission limit
is small and similar in magnitude to the energy impact of using LNBs on
Group 1 boilers. Finally, the recommended emission limit results in a
reduction of NOX emissions by approximately 284,000 tons per year
(see Regulatory Impact Analysis, docket item II-F-2) without increases
in CO, CO2, SO2, or solid waste and with potentially a 50%
decrease in particulates. As discussed in section II.D, there are
substantial human health and environmental benefits associated with the
additional NOX reductions and meeting the proposed emission
limitation is a cost-effective means of achieving such reductions.
2. Cyclone Boilers
Performance of NOX Controls. Four NOX control
technologies that are available for application to cyclone boilers meet
the cost comparability requirement: (1) Coal reburning, (2) gas
reburning, (3) SCR, and (4) SNCR. Since EPA must base the emission
limitation on the ``best system of continuous emission reduction'' per
section 407(b)(1), and as shown in the Technical Support Document, the
expected NOX removal capability of SNCR is approximately 35%,
lower than the percent reduction of the other technologies available
for cyclone boilers, EPA is not considering SNCR in establishing the
emission limitation for cyclone boilers.
Table 19 shows measurements and various estimates of the percent
reduction and controlled emission rates for coal reburning, gas
reburning, and SCR on cyclone boilers. EPA also believes that
combustion control and combustion optimization approaches may also
achieve cost-effective, significant NOX reductions. However, these
control approaches have not yet been thoroughly investigated by the
utility community.

[[Page 1468]]

Table 19.--NOX Reduction Performance for Available NOX Controls
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
NOX Control for cyclone boilers
----------------------------------------------------------------------------------------------------------------------------------------------------------------
Coal reburning SCR Gas reburning
Source ----------------------------------------------------------------------------------------------------------------------------------------------------------------
Controlled
Percent reduction Controlled emission Percent reduction emission rate Percent reduction Controlled emission rate (lb/
rate (lb/mmBtu) (lb/mmBtu) mmBtu)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Retrofit Applications:
Nelson Dewey 2 (110 MWe)... 52.4-55.4 (MCR).............. 0.34-0.39.......... ............................. ............... ............................. ............................
Merrimack 2 (320 MWe)...... ............................. ................... 65 (target).................. NA............. ............................. ............................
Niles 1 (108 MWe).......... ............................. ................... ............................. ............... 50 (long term)............... 0.58-0.67 (approx.)
Lakeside 7 (33 MWe)........ ............................. ................... ............................. ............... 66 (long term)............... 0.344
DOE........................ 40-60 \19\................... NA................. 80-90........................ NA............. 55-65........................ NA
EPRI (based on retrofits)...... 50-55 (MCR).................. NA................. 65 (MCR, target)............. NA............. 50-60 (MCR).................. NA
UARG (based on retrofits)...... 55-60 (MCR), 33-50 (loads NA................. 65 (target).................. NA............. 40 (long term, >75% MCR), 47% NA
down to 35% MCR). (MCR).52-77 (short term,
>70% MCR).
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

EPA believes that 50% NOX reduction from full-load values can
be achieved by coal reburning and SCR ^{20 controls over the long
term. This represents the average of the range in performance expected
by DOE. A 50% NOX reduction is also on the conservative end of the
performance range achieved over the long term at the only demonstration
project, and is on the lower end of performance projections by utility
groups.

\19\ This range reflects use of different coal types,
specifically at Nelson Dewey 2, 55.4% NOX reduction at 110 MWe
using subbituminous coal and 35.8% NOX reduction at 60 MWe
using bituminous coal.
\20\ Of the three technologies, SCR allows the user to design
for various levels of performance ranging as high as 90% NOX
reduction. However, increases in performance are directly
proportional to increases in cost. For the purposes of this rule,
and to more accurately compare SCR with coal and gas reburning, the
NOX reduction performance of SCR is set at 50%.
---------------------------------------------------------------------------

Gas reburning is expected to reduce NOX emissions by 60%. This
value is about the average of the range of performance at the two
existing gas reburning projects and the overall range of DOE and EPRI
performance estimates. The lower reduction percentages suggested by
UARG reflect boiler operation at lower than full loads.
Some industry commenters have expressed concerns that applications
of coal or gas reburning on some cyclone boilers may not achieve 50% or
60% NOX reductions, respectively. EPA solicits comment from
vendors and utilities on the performance of these NOX control
technologies.
Additionally, information recently obtained by EPA from a utility
that attempted to optimize the combustion process in cyclone boilers,
shows that reductions in the order of 10%-20% can be achieved by
optimizing fuel and air flows to cyclones. EPA solicits comment from
vendors and utilities on the applicability of combustion modification
and optimization techniques that lower NOX emissions from cyclone
boilers.
Achievable Emission Limit. For the purposes of applying a NOX
emission limitation to cyclone boilers, EPA chose 50%, a conservative
reduction percentage considering the performance level of the three
qualifying technologies. Applying the projected 50% emission reduction
to the uncontrolled emissions of each boiler over 80 MWe in the cyclone
population for which NOX limits are to be set under section
407(b)(2), EPA determined how many of the boilers could achieve various
NOX emission levels. The following table shows the NOX
emission levels achievable by between 89.3% and 100% of the cyclone
boiler population.

Table 20
------------------------------------------------------------------------
Number Percent
of of
boilers boilers
NOX level (lb/mmBtu) meeting meeting
NOX NOX
level level
------------------------------------------------------------------------
0.98................................................. 75 100
0.97................................................. 73 97.3
0.94................................................. 70 93.3
0.86................................................. 68 90.7
0.85................................................. 67 89.3
------------------------------------------------------------------------

Table 20 indicates that 93% of the 75 cyclone boilers can achieve a
NOX controlled emissions rate of 0.94 lb/mmBtu.

BILLING CODE 6560-50-P

[[Page 1469]]
[GRAPHIC][TIFF OMITTED]TP19JA96.005

BILLING CODE 6560-50-C

[[Page 1470]]

Note that the proposed emission limit is greater than the
controlled emission rates shown in Table 19. The boilers shown in Table
19 have uncontrolled emissions significantly lower than the
uncontrolled emission rates of some boilers. Since, as illustrated in
Figure 6, the emission limit is based on approximately 95% of the
population meeting it, the effect of the higher emitting boilers drives
the emission limit towards the high end of the controlled emissions
distribution.
Environmental Impacts. According to EPA's Regulatory Impact
Analysis, the establishment of 0.94 lb/mmBtu as the emission limitation
for cyclone boilers will result in additional NOX emissions
reductions of approximately 167,000 tons per year. These reductions are
achieved with little or no increases in other air pollutants or solid
waste. In fact, when applying gas reburning, significant SO2 and
CO2 emission reductions are also achieved.
Issues Raised. Applicability of Reburning. Some concern has been
expressed regarding the ability of some cyclone boilers to retrofit gas
or coal reburning; of particular concern are smaller boilers. EPA
investigated whether the retrofit of both coal and gas reburning may be
infeasible for some small boilers. According to Babcock & Wilcox, the
only vendor for both cyclone boilers and coal reburning, many boilers
less than 80 MWe may not be able to effectively retrofit reburning.
Since there appears to be great concern regarding the reburning
retrofitability of small boilers and since their combined NOX
emissions (in tons) account for only about 10,000 tons out of about 1.8
million tons of total annual uncontrolled NOX emissions from units
with Group 2 boilers, today's proposal exempts cyclones less than 80
MWe from this rulemaking.
EPA is also asked to exempt large cyclone boilers due to
uncertainties concerning the ``scaling up'' of reburning technology
from small to large boilers. Some utilities are concerned that since
large boilers have greater furnace volumes, the reburning fuel will not
be able to mix adequately with the flue gas and therefore, the NOX
reduction will be significantly less than the expected 50%.
The feasibility of reburning on any boiler depends on the following
requirements: (1) The availability of adequate residence time in the
reburn and burnout zones; (2) the mixing of reburn fuel and overfire
air; and (3) the ability to achieve penetration of reburn fuel into
combustion gas across the distances associated with large units.
It has been shown in a survey (see docket item II-I-22, Final
Report, Demonstration of Coal Reburning for Cyclone Boiler NOX
Control, prepared by Babcock and Wilcox for the Department of Energy,
DOE/PC/89659-T16, February 1994, pp. 2-7 and 2-8 ) that majority of the
boilers had the requisite residence time available for coal reburning.
Further, gas reburning applications require less residence times than
corresponding coal reburning applications. Thus, in general, most of
the cyclones have adequate residence times available for applications
of either coal or gas reburning. However, natural gas may not be
available at all cyclone boiler locations. EPA solicits comment on what
cyclone boilers do not have access to natural gas.
Combustion gas flow patterns in relatively larger boilers are
expected to be less complex than those found in smaller units. Thus
general mixing of reburn fuel and combustion gas would be expected to
be better in larger boilers.
Penetration of reburn fuel into combustion gas does depend on the
distance between the front and rear walls of a boiler. However, with
proper design of reburn fuel burners/injectors, the requisite
penetration can be achieved.
Additionally, EPA believes that though all reburn demonstrations in
the U.S. have been on relatively small boilers (about 100 MWe), a 300
MWe boiler in the Ukraine has been successfully retrofitted and
operated with gas reburn by a large U.S. manufacturer and is achieving
50% of NOX reduction over the load range. Since no retrofit of
reburning to date (including this 300 MWe boiler) has shown a long-term
NOX reduction lower than 50% from full-load values and NOX
emissions from large cyclone boilers are clearly not de minimis, EPA
adopts 50% as the minimum removal capability of reburning. EPA also
notes that SCR is available as an alternative NOX control
technology for cyclone boilers.
Applicability of Reburning at Low Loads. EPA has investigated the
concern about the application of reburning at reduced boiler loads
because this could affect slagging and NOX reduction efficiency in
the cyclone.
Utility representatives project that reburning will be inoperable
at low boiler loads (less than 40% of full load) (see docket item II-E-
10). EPA has investigated the actual hourly loads of 22 Phase I cyclone
boilers and found that, collectively, they were at less than 40% of
full load only 5% of the time in 1994. Further, the retrofit of coal
reburning to Nelson Dewey Unit 2 achieved long-term NOX reductions
greater than 50% even though the reburning was stopped during periods
when the cyclone was operating at loads lower than 40% of full load.
According to the manufacturer (see docket item II-I-90, Babcock &
Wilcox, Steam: Its Generation and Use), individual cyclone furnaces
cannot be operated below half load without causing freezing of slag. On
smaller cyclone boilers, equipped with only a few cyclone furnaces,
load reduction is achieved by turning down each of the individual
furnaces. On these boilers, typical minimum operational load, in the
absence of reburning, would be about 50 percent of the rated boiler
capacity. With reburning providing 15-20 percent of total heat input,
the minimum operational load for some small boilers could be about 58-
60 percent of rated capacity. However, the situation is different for
relatively larger cyclone boilers. Typically, these boilers are
equipped with many cyclone furnaces. Load reduction on these cyclone
boilers is achieved by removing individual cyclone furnaces from
service. Depending on the number of individual cyclone furnaces taken
out of service and the level of load reduction on each of the remaining
furnaces, such a boiler could be operated over a wide range of loads.
Hence, based on the proposed 80 MWe size cut-off, application of
reburning on cyclone boilers should not be restricted by load
considerations. Further, for those few units where load considerations
restrict use of reburning, SCR is available as a cost effective
NOX control measure.
It is worth noting that gas reburning has been applied successfully
at a small cyclone boiler (Lakeside Unit 7, 33 MWe). Long term NOX
reduction at this unit has been reported to be over 65 percent.
Applicability of Combustion Controls on Cyclone Boilers. EPA has
identified two U.S. manufacturers that have combustion control
approaches to controlling NOX from cyclone boilers, and the
performance and cost of such approaches appear to be very promising.
Although these staged combustion systems appear promising, they have
not yet been demonstrated. In addition, cyclones may be able to be
``optimized'' for NOX emission reduction without the addition of
controls. A major utility has done such work in the past achieving 10-
20% reductions by changing the air/fuel ratios. The same utility also
intends to examine combustion modification controls. Modeling will be
completed this year, and demonstration projects will be underway in
1996. Combined with emission reductions from fuel

[[Page 1471]]
changes, total emission reductions of 20 to 40% from 1990 baseline
levels are anticipated. EPA calculates that if cyclone owners
successfully apply combustion optimization techniques, more than 50% of
the affected units would meet the 0.94 lb/mmBtu emission limit at
dramatically reduced costs. EPA is not basing its proposed emission
limitation for cyclone boilers on combustion optimization because there
is currently inadequate information to conclude that it is an available
technology under section 407 (b)(2) for cyclone boilers.
Cost Comparability of Available Cyclone Boiler NOX Controls.
EPA recognizes that some industry commenters believe that the available
NOX control technologies for cyclone boilers are not comparable in
cost, on a dollars per ton of NOX removed basis, to low NOX
burners applied to Group 1 boilers. Although EPA is proposing that
there are NOX control technologies available for cyclone boilers
that are comparable in cost to low NOX burners applied to Group 1
boilers, the Agency stresses that it will welcome, and fully consider
in the final rule, any additional data or other information relevant to
the issue of cost comparability. For the same reasons (discussed above)
that EPA is not delaying the proposed revised limitations for Phase II,
Group 1 units, EPA is today proposing emission limitations for cyclone
and other Group 2 boilers, based on what it believes is a sufficient
record. An analysis by DOE, based on different assumptions and data
than those used by EPA and including information which has not been
verified by EPA, concludes that the average cost-effectiveness of LNB
technology for Group 1 boilers is $260 per ton, and that the
corresponding cost effectiveness for SCR applied to cyclone boilers is
$830 per ton ^{21 (see docket item II-D-62, Analysis of Proposed
Section 407(b)(2) NOX Rule, Department of Energy, Staff Paper,
December 14, 1995. pp. 2-12). If EPA determines that this analysis is
appropriate and this degree of difference is deemed to not be
``comparable'' for purposes of setting a Group 2 standard, and if coal
or gas reburning also do not meet the cost comparability requirements,
then no standard would be promulgated for cyclone boilers, unless more
cost-effective control technology is identified during the comment
period for this rule.

\21\ Additionally, DOE determined the average annualized cost of
LNB controls for Group 1 boilers to be 0.34 mills/kWh; and of
cyclone boiler controls to be 2.83 mills/kWh.
---------------------------------------------------------------------------

EPA is specifically requesting comment on the adequacy of the data
as to its accuracy and completeness to (1) support an emission
limitation of 0.94 lb/mmBtu for cyclone boilers or (2) to support not
establishing an emission limit for cyclone boilers at this time. EPA
requests (a) data and analysis on the cost and performance of Group 1
low-NOX burner control technologies and (b) cost and performance
data for demonstrated NOX control technologies for cyclone boilers
including but not limited to coal reburn, gas reburn, SCR, SNCR or
other NOX control technologies. EPA also seeks information which
might suggest a size cutoff or groupings for cyclone boilers to be
controlled by each of these technologies and analysis supporting this
recommendation. As noted below, EPA's view of available information
indicates that technology to reduce NOX emissions from cyclone
boilers is comparable to the cost of low NOX burners for Group 1
boilers. However, analysis provided by DOE, based on different
assumptions and data, indicates that the cost of control technology for
cyclone boilers is several times higher than the cost of LNB for Group
1 boilers (see docket item II-D-62, Analysis of Proposed Section
407(b)(2) NOX Rule, Department of Energy, Staff Paper, December
14, 1995.). EPA also requests comments and recommendations on these two
analytical approaches.
Conclusions. For the following reasons, EPA concludes that 0.94 lb/
mmBtu is a reasonable emission limitation that meets the requirements
of section 407(b)(2). First, coal reburning, gas reburning and SCR
applied to cyclone boilers are available technologies that meet the
cost-comparability requirement. Second, the proposed emission limit of
0.94 lb/mmBtu is an achievable emission level that 93% of the cyclone
boiler population will be able to meet with the application of coal
reburning, gas reburning, or SCR. Third, as shown in section III.E, the
cost impact on electricity consumers of using these control
technologies to meet recommended emission limit is small and similar in
magnitude to the energy impact of using LNBs on Group 1 boilers.
Finally, the recommended emission limit results in a reduction of
NOX emissions by approximately 167,000 tons per year with little
or no increases in other air pollutants or solid waste disposal. As
discussed in section II.D, there are substantial human health and
environmental benefits associated with the additional NOX
reductions and meeting the proposed emission limitation is a cost-
effective means of achieving such reductions.
3. Wet Bottom Boilers
Performance. Because combustion NOX controls meet the cost-
comparability requirement, the performance of these controls is
assessed to determine what performance standards are achievable. Though
SNCR also meets the comparability criteria, at a typical 35% NOX
reduction it is not the ``best system of continuous emission
reduction'' per section 407(b)(2) available for wet bottom boilers, and
as such, is not considered when setting emission limits for wet bottom
boilers.
Combustion controls have not yet been applied to wet bottom boilers
in the U.S. However, a major utility has announced plans to retrofit a
wet bottom wall-fired boiler in the fall of 1995 with combustion
controls, specifically a two-level overfire air (OFA) system. According
to the utility's engineering estimates, the two-level OFA system will
achieve an overall 50% reduction from uncontrolled levels and will
allow the wet bottom boiler to have a NOX emission rate of 0.71
lb/mmBtu (see docket items II-D-30: J.M. McManus, American Electric
Power Service Corporation, to L. Kertcher, EPA: Acid Rain Division, May
26, 1995, Enclosing information relating to Kyger Creek Unit 5 low
NOX System Design; II-B-7: Trip Report: visit to Kyger Creek Unit
5 Low NOX Combustion Modification Retrofit; and II-A-2:
Investigation of Performance and Cost of NOX Controls as Applied
to Group 2 Boilers at p. 3-18 & 3-19).
Based on the above project's projected performance, EPA projects
that combustion controls applied to wet bottom boilers can achieve a
50% reduction of NOX emissions from uncontrolled levels. EPA notes
the control technology on which it is based, OFA, has been widely used
in the electric utility industry as a NOX control technology for
other types of boilers for many years (57 FR 55640).
Achievable Emission Limit. Applying the projected 50% emission
reduction to the uncontrolled NOX emissions of each boiler in the
wet-bottom burner population for which NOX limits are to be set
under section 407(b)(2), EPA determined how many of the boilers could
achieve various NOX performance standards. The following table
shows the NOX performance standards achievable by between 89.7%
and 100% of the wet bottom boiler population.

[[Page 1472]]

Table 21
------------------------------------------------------------------------
Number
of Percent
boilers boilers
NOX level (lb/mmBtu) meeting meeting
NOX NOX
level level
------------------------------------------------------------------------
0.95................................................. 38 100
0.86................................................. 37 97.4
0.84................................................. 34 89.5
------------------------------------------------------------------------

Table 21 indicates that 97% of the 39 wet bottom boilers can
achieve a controlled NOX emission rate of 0.86 lb/mmBtu.

BILLING CODE 6560-50-P

[[Page 1473]]
[GRAPHIC][TIFF OMITTED]TP19JA96.006

BILLING CODE 6560-50-C

[[Page 1474]]

Note that the proposed emission limit is greater than the
controlled emission rate expected from Kyger Creek #5 (0.71 lb/mmBtu).
EPA has calculated the uncontrolled emission rates of wet bottom
boilers to be as high as 1.90 lb/mmBtu and on average 1.12 lb/mmBtu.
Kyger Creek #5 (at 1.41 lb/mmBtu), though having uncontrolled emissions
above the mean emission rate of the wet bottom boiler population, is
lower than the uncontrolled emission rates of some boilers. Since, as
illustrated in Figure 7, the emission limit is based on approximately
95% of the population meeting it, the effect of the higher emitting
boilers drives the emission limit towards the high end of the
controlled emissions distribution.
Environmental Impacts. According to the EPA's Regulatory Impact
Analysis, the establishment of 0.86 lb/mmBtu as the emission limit for
wet bottom boilers will result in a total NOX emissions reduction
of approximately 112,000 tons per year. These reductions will be
achieved through the use of OFA, a form of combustion NOX control
technology. Since LNBs are also a form of combustion control
technology, EPA expects the environmental and solid waste impacts of
OFA on wet bottom boilers to be similar to the impacts of LNBs or OFA
Group 1 boilers. The application of LNBs or OFA on Group 1 boilers does
not increase levels of CO, SO2, or CO2 but may increase the
unburned carbon (UBC) level in the flyash. For boilers that do
experience increases in UBC from uncontrolled levels, technologies that
lower UBC to below uncontrolled levels at very little or no cost are
available (see section IV.D.1).
Conclusions. For the following reasons, EPA concludes that 0.86 lb/
mmBtu is a reasonable emission limitation that meets the requirements
of section 407(b)(2). First, combustion NOX controls applied to
wet bottom boilers are an available technology that meets the cost-
comparability requirements. Second, an emission limit of 0.86 lb/mmBtu
is a level that 97.4% of wet bottom boiler population should be able to
meet with the application of combustion controls at 50% NOX
removal efficiency. Third, as shown in section III.E, the cost impact
on electricity consumers of using this control technology to meet the
recommended emission limit is small and similar in magnitude to the
energy impact of using LNBs on Group 1 boilers. Finally, the
recommended emission limit results in a reduction of NOX emissions
by approximately 112,000 tons per year without significant increases in
CO, CO2, SO2, or solid waste disposal. As discussed in
section II.D, there are substantial human health and environmental
benefits associated with the additional NOX reductions and meeting
the proposed emission limitation is a cost-effective means of achieving
such reductions.
We note that earlier in the preamble we requested comment on
whether gas reburning as applied to wet bottom boilers is comparable in
cost to low NOX burner technology and meets the requirements of
Section 407(b)(2). Commenters believing that gas reburning meets the
necessary requirements should also comment on what percent reduction is
achievable and what effect, if any, there would be on the emission
limit set for wet bottom boilers.
4. Vertically Fired Boilers
Performance. Because the combustion controls applied to vertically
fired boilers meet the cost comparability requirements, the performance
of these controls is assessed to determine what performance standards
are achievable. Table 22 shows various measurements of the percent
reduction and controlled emission rates for combustion controls on
vertically fired boilers (see docket items II-A-2 at p. 3-18 & 3-19,
II-B-4, and II-B-5).

Table 22.--NOX Reduction Performance for Available NOX Controls
------------------------------------------------------------------------
NOX control for vertically fired
boilers
----------------------------------------
Source Combustion controls
----------------------------------------
Controlled
Percent reduction emission rate
------------------------------------------------------------------------
AEP Tanner's Creek 1 (152 MWe). 40................. 0.57
(estimated)........ (estimated)
Duquesne Light Elrama Unit 1 42................. 0.45
(100 MWe).
Duquesne Light Elrama Unit 2 40...... 0.45
(100 MWe).
Duquesne Light Elrama Unit 3 40...... 0.45
(125 MWe).
------------------------------------------------------------------------

Based on the above NOX reduction performance, EPA is
projecting a 40% percentage reduction in NOX emissions using
combustion controls on vertically fired boilers. Every project in Table
22 achieved or is expected to achieve 40% or higher NOX
reductions. These projects achieve NOX reductions by using two
different combustion air staging systems: one that redistributes the
combustion air within the burners and the second that accomplishes
redistribution through OFA ports. EPA notes that this approach to
controlling NOX has been used by many vendors of technology and
utilities for many years to control NOX emissions from other types
of boilers, e.g., dry bottom wall-fired and tangentially fired boilers
(57 FR 55640).
Achievable Emission Limit. Applying the projected 40% emission
reduction to the uncontrolled emissions of each boiler in the
vertically fired population for which NOX limits are to be set
under section 407(b)(2), EPA determined how many of the boilers could
achieve various NOX performance standards. The following table
shows the NOX performance standards achievable by between 84.8%
and 100% of the vertically fired boiler population.

Table 23
------------------------------------------------------------------------
Number Percent
of of
boilers boilers
NOX level (lb/mmBtu) meeting meeting
NOX NOX
level level
------------------------------------------------------------------------
0.85................................................. 29 100
0.80................................................. 28 96.6
0.74................................................. 26 89.7
0.72................................................. 24 82.8
------------------------------------------------------------------------

Table 23 indicates that 97% of the 33 vertically fired boilers can
achieve a NOX controlled emissions rate of 0.80 lb/mmBtu

BILLING CODE 6560-50-P

[[Page 1475]]
[GRAPHIC][TIFF OMITTED]TP19JA96.007

BILLING CODE 6560-50-C

[[Page 1476]]

Note that the proposed emission limit is greater than the
controlled emission rates shown in Table 22. EPA has calculated the
uncontrolled emission rates of vertically fired boilers to be as high
as 1.42 lb/mmBtu and on average 1.06 lb/mmBtu. The boilers shown in
Table 22 have uncontrolled emissions below the mean emission rate of
the vertically fired population and, thus, are significantly lower than
the uncontrolled emission rates of more than half of the boilers. Since
as illustrated in Figure 8, the emission limit is based on
approximately 95% of the population meeting it, the effect of the
higher emitting boilers drives the emission limit toward the high end
of the controlled emissions distribution.
Environmental Impacts. According to the EPA's Regulatory Impact
Analysis, the establishment of 0.80 lb/mmBtu as the emission limit for
vertically fired boilers will result in a total NOX emissions
reduction of approximately 57,000 tons per year. These reductions will
be achieved through the use of combustion NOX control technology.
Since LNBs are also a form of combustion control technology, EPA
estimates that the environmental and solid waste impacts of combustion
controls on vertically fired boilers will be similar to the impacts of
LNBs or OFA on Group 1 boilers. The application of LNBs or OFA on Group
1 boilers does not increase levels of CO, SO2, or CO2 but may
increase the unburned carbon (UBC) level in the flyash. For boilers
that do experience increases in UBC from uncontrolled levels,
technologies that lower UBC to below uncontrolled levels at very little
or no cost are available.
Conclusions. For the following reasons, EPA concludes that 0.80 lb/
mmBtu is a reasonable emission limitation that meets the requirements
of section 407(b)(2). First, combustion controls applied to vertically
fired boilers are an available technology that meets the cost-
comparability requirement. Second, an emission limit of 0.80 lb/mmBtu
is a level that 97.0% of vertically fired boiler population should be
able to meet with the application of combustion controls at 40%
NOX removal efficiency. Third, the cost impact on electricity
consumers of using this control technology to meet the recommended
emission limit is small and similar in magnitude to the energy impact
of using LNBs on Group 1 boilers. Finally, the recommended emission
limit results in a reduction of NOX emissions by approximately
57,000 tons per year without increases in CO, CO2, SO2, or
solid waste disposal. As discussed in section II.D, there are
substantial human health and environmental benefits associated with the
additional NOX reductions and meeting the proposed emission
limitation is a cost-effective means of achieving such reductions.
5. FBC Boilers
The FBC boilers affected by the Title IV are inherently low
NOX emitters. Table 24 shows the CEM-measured emission rates of
all Title IV-affected FBC boilers.

Table 24.--NOX Emission Rates for Title IV-affected FBC Boilers
------------------------------------------------------------------------
NOX
emission
Plant name Boiler I.D. rate (lb/
mmBtu)
------------------------------------------------------------------------
Nucla................................ 1 0.170
Shawnee.............................. 10 0.230
Black Dog............................ 2 0.258
R M Heskett.......................... B2 0.286
TNP One.............................. U1 0.169
TNP One.............................. U2 0.153
------------------------------------------------------------------------

Combustion controls are inherently included in the design of FBCs.
Therefore, there is no additional cost involved with controlling
NOX from these boilers. EPA determined that applying a NOX
emission limitation to FBC boilers would result in no additional
NOX reductions since all these boilers are currently controlled.
Observing the uncontrolled emissions of each boiler in the FBC boiler
population for which NOX limits are to be set under section
407(b)(2), EPA determined how many of the boilers could achieve various
NOX emission levels. The following table shows the NOX
emission levels achievable by between 50% and 100% of the FBC boiler
population.

Table 25
------------------------------------------------------------------------
Number Percent
of of
boilers boilers
NOX level (lb/mmBtu) meeting meeting
NOX NOX
level level
------------------------------------------------------------------------
0.29................................................. 6 100
0.26................................................. 5 83.3
0.23................................................. 4 66.7
0.17................................................. 3 50.0
------------------------------------------------------------------------

Table 25 indicates that 100% of the 6 FBC boilers can achieve a
NOX controlled emissions rate of 0.29 lb/mmBtu.
Conclusions. For the following reasons, EPA concludes that 0.29 lb/
mmBtu is a reasonable emission limitation that meets the requirements
of section 407(b)(2). First, combustion controls applied to FBC boilers
are an available technology that meets the cost-comparability
requirement. Second, an emission limit of 0.29 lb/mmBtu is a level that
100% of FBC boiler population should be able to meet with the
application of combustion controls. Third, while the recommended limit
will not result in any additional NOX emission reductions (or in
any increases in other pollutants or solid waste), the use of this
control technology to meet the recommended emission limit imposes no
additional cost on electricity consumers.

G. General Issues Raised

The Agency has received some public comment that, for some boiler
types, some additional time should be provided for further
demonstration of NOX control technologies. Some commenters have
suggested that EPA extend the Phase II NOX compliance date for
certain boiler types beyond January 1, 2000 and encourage, in the
meantime, demonstration projects for such boiler types utilizing
various control technologies. While EPA believes that the record
supports establishment of the NOX emission limitations, discussed
above, for Group II boiler types in accordance with section 407(b)(2)
of the Act, the Agency wants to ensure that the broadest range of
constructive comment is elicited during the public comment period. For
this reason, the Agency requests comment on, but does not propose, an
alternative regulatory approach for specified boiler types that would
incorporate the elements of postponement of compliance and
encouragement of demonstration projects. Commenters should address the
merits of the alternative approach with regard to specific Group II
boiler types and whether such an approach would be consistent with the
legal requirements of section 407(b)(2) and environmental goals of
title IV.
Under this alternative regulatory approach, the compliance deadline
for the specified boiler types for meeting Phase II NOX emission
limitations would be postponed for a short period (perhaps 2 years).
Starting on the new compliance date, the applicable NOX emission
limitation for affected units of such boiler types would be the
limitation set forth in today's proposed rule. However, a limited
number of such units (perhaps 10 units), encompassing a range of annual
operating capabilities, would be allowed to elect to comply early
(i.e., on January 1, 2000) with a slightly higher NOX emission
limitation, which would become their applicable emission limitation for
Phase II.

[[Page 1477]]

Each early-election unit would have to implement either: combustion
controls designed to achieve a specified minimum percent reduction
(perhaps 20 to 30 percent) in the uncontrolled NOX emission rate;
or an alternative NOX control technology designed to achieve a
specified minimum percent reduction (perhaps 40-50 percent). The unit
could be incorporated in a NOX averaging plan in accordance with
Sec. 76.11 during Phase II, using its applicable emission limitation.
If the unit was unable to meet its applicable emission limitation, it
could apply for an AEL in accordance with Sec. 76.10.
EPA has also received comment concerning the desirability of
allowing trading of NOX emission reductions. EPA notes that it has
previously considered and rejected, as outside the statutory scheme of
section 407, the suggestion that banking of NOX reductions be
allowed as part of NOX averaging plans 59 FR 13538, 13562 (March
22, 1994). The Agency seeks further comment on the legal basis and
workability of a NOX trading system. EPA has supported NOX
emissions trading for several years through a variety of programs
developed by States under EPA's Economic Incentive Program. Examples
include Massachusetts' Innovative Market Program for Air Credit Trading
(IMPACT) for NOX, VOC and CO, and Texas' Emissions Credit Banking
and Trading Program for NOX and VOC. In Los Angeles, NOX
emissions trading has been underway for more than a year through the
South Coast Air Quality Management District's Regional Clean Air
Incentive Market (RECLAIM).
Regional emissions trading is currently being considered for the
eastern region of the US to address the persistent ozone non-attainment
problems of many eastern States, due in part to the interstate
transport of NOX emissions. The Ozone Transport Commission (OTC),
with support from EPA, is developing a model NOX trading rule to
be adopted by each of its twelve member States and the District of
Columbia. Under a program similar to the Acid Rain Program for SO2
emissions, NOX emissions from utility boilers and large industrial
boilers would be reduced significantly during the five-month ozone
season under an emissions cap, but would allow for trades of NOX
emission allowances across State lines. The Ozone Transport Assessment
Group (OTAG), with support from EPA, is considering a corresponding
program for NOX emissions from utilities and large industrial
boilers for the 37 States in its region, including the States of the
Ozone Transport Region. The possibility of including other sources of
NOX emissions, such as heavy-duty diesel engines and car fleets,
through other types of emissions credit trading programs, is currently
being examined.
The promulgation of EPA's Open Market Trading Rule will offer
another option for States to consider in developing market incentive
programs to reduce NOX emissions. States will receive automatic
EPA approval provided they adopt an identical version of EPA's model
rule; variations on the model rule will also be readily approved as
long as its implementation would not interfere with the State's
attainment or maintenance strategies. Under EPA's Open Market Trading
Rule, sources will be able to generate tradeable Discrete Emission
Reduction (DER) credits for voluntarily reducing their NOX or
other emissions, provided the reduction is real and verifiable, and
which, in turn, may be used by a purchaser to obtain flexibility in
complying with an emissions limitation requirement. The open market
trading program will enable States to offer both stationary and mobile
sources the opportunity to achieve cost savings and emissions reduction
flexibility, while providing an incentive for the development of new
emissions reduction technologies.

IV. References

Abbey, D.E. et al. 1993. Long Term Ambient Concentrations of Total
Suspended Particulates, Ozone and Sulfur Dioxide and Respiratory
Symptoms in a Non-Smoking Population. Archives of Environmental
Health.
Benson V., MA Moranno. 1994. Vital and Health Statistics: Current
Estimates from the National Health Interview Survey, 1992.
Washington, DC: Public Health Service, National Center for Health
Statistics; DHHS publication no. (PHS)94-1517, Series 10, No. 189.
Fairley, D. 1990. The Relationship of Daily Mortality to Suspended
Particulates in Santa Clara County, 1980-1986. Environmental Health
Perspectives 89: 159-168
Krupnick, A. 1988. An Analysis of Selected Health Benefits from
Reductions in Photochemical Oxidants in the Northeastern United
States: Final Report. Prepared for U.S. Environmental Protection
Agency, Office of Air Quality Planning and Standards. Washington,
D.C., : Resources for the Future. September.
National Acid Precipitation Assessment Program (NAPAP). 1990. Acid
Deposition: State of Science and Technology, Volumes 9, 13, 16, and
21. Washington, D.C.: Office of the Director.
National Acid Precipitation Assessment Program (NAPAP). 1993. 1992
NAPAP Report to Congress. Washington, D.C.: Office of the Director.
June.
National Research Council. 1991. Rethinking of Ozone Problem in
Urban and Regional Air Pollution. Washington, D.C.: National Academy
Press.
Neas, L. Et al. 1991. Association of Indoor Nitrogen Dioxide With
Respiratory Symptoms and Pulmonary Function in Children. American
Journal of Epidemiology 134(2): 204-219.
Schwartz, J., et al. 1988. Air Pollution and Morbidity: A Further
Analysis of the Los Angeles Student Nurses Data. Journal of the air
Pollution control association 38(2):158-162.
Schwartz, J. 1994. Particulate Air Pollution and Daily Mortality: A
Synthesis. Environmental Research. January 5.
Sommerville, M.C. et al. 1989. Impact of Ozone and Sulfur Dioxide on
the Yield of Agricultural Crops. Technical Bulletin 292. North
Carolina Agricultural Research Service, North Carolina State
University. November.
The State of the Southern Oxidants Study (SOS). 1995. Policy-
Relevant Findings in Ozone Pollution Research, 1988-1994. April
U.S. Department of Health and Human Services. 1990. Vital and Health
Statistics: Current Estimates from the Nation Health Interview
Survey, 1989. Hyattsville, MD: Public Health Service, National
Center for Health Statistics; DHHS Publication no. (PHS)90-1504,
Series 10, No. 176.
U.S. Environmental Protection Agency. 1994a. Deposition of Air
Pollutants to the Great Waters. First Report to Congress, EPA-453/R-
93-055. May.
U.S. Environmental Protection Agency. 1994b. EPA Regional Oxidant
Model Analyses of Various Regional Ozone Control Strategies.
November 28.
U.S. Environmental Protection Agency. 1995. Acid Deposition Standard
Feasibility Study, Report To Congress, Draft for Public Comment,
EPA-430-R-95-001. February.
Whittmore, A. And E. Korn. 1980. Asthma and Air Pollution in the Los
Angeles Area. American Journal of Public Health 70:687-696.

V. Regulatory 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 contents
of the docket, except for interagency review materials, will serve as
the record in case of judicial review (section 307(d)(7)(A)).

B. Executive Order 12866

Under Executive Order 12866 (58 Fed. Reg. 51735, October 4, 1993),
the Agency must determine whether the regulatory action is
``significant'' and therefore subject to Office of

[[Page 1478]]
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
$143 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.
The EPA does not anticipate major increases in prices, costs, or
other significant adverse effects on competition, investment,
productivity, or innovation or on the ability of U.S. enterprises to
compete with foreign enterprises in domestic or foreign markets due to
the final regulations.
In assessing the impacts of a regulation, it is important to
examine (1) the costs to the regulated community, (2) the costs that
are passed on to customers of the regulated community, and (3) the
impact of these cost increases on the financial health and
competitiveness of both the regulated community and their customers.
The costs of this regulation to electric utilities are generally very
small relative to their annual revenues. (However, the relative amount
of the costs will definitely vary in individual cases.) Moreover, EPA
expects that most or all utility expenses from meeting NOX
requirements will be passed along to ratepayers. When fully implemented
in the year 2000, consumer electric utility rates are expected to rise
by 0.07 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'') (signed into law on March 22, 1995) 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: (i) Identification of the Federal law
under which the rule is promulgated; (ii) 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; (iii) if feasible, estimates of the future compliance costs
and any disproportionate budgetary effects of the mandate; (iv) if
feasible, estimates of the effect on the national economy; and (v) 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.
In examining the impacts of this proposed regulation, EPA analyzed
the following three regulatory scenarios:
1. Revising the existing Group 1 boiler emission limits for
application to Phase II, Group 1 boilers and not establishing any
emission limits for Group 2 boilers (resulting in the control of
approximately 212,000 tons of NOX per year at an annual total cost
of approximately $56 million).
2. Revising the existing Group 1 boiler emission limits for
application to Phase II, Group 1 boilers and establishing emission
limits for Group 2 boilers (resulting in the control of approximately
831,000 tons of NOX per year at an annual total cost of
approximately $143 million).
3. Revising the existing Group 1 boiler emission limits for
application to Phase II, Group 1 boilers and not establishing any
emission limits for Group 2 boilers, however exempting cyclones less
than 80 MWe (resulting in the control of approximately 830,000 tons of
NOX per year at an annual total cost of approximately $143
million).
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 this proposal, the Agency discusses several regulatory
options and their associated costs. In addition, the Agency has
initiated but not completed consideration of other regulatory options
beyond the options discussed in the proposal. The Agency believes that,
among the options considered thus far and based on the current record,
the proposal is the least costly, most effective, and least burdensome
alternative that achieves the objectives of title IV and section 407 in
particular. As discussed above, the Agency is soliciting comment on,
not only the regulatory options discussed in the proposal, but also on
any additional regulatory options. Commenters should also address what
options are the least costly and least burdensome. After completion of
the comment period, during which the Agency anticipates receiving
comments on the full range of potential regulatory options and their
related costs, EPA will make a final determination of what option is
the least costly, most effective, and least burdensome, consistent with
title IV.
Because this proposed 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 proposed rule is promulgated under section 407(b)(2) of the
Clean Air Act. Total expenditures resulting from the rule are estimated
at: $143 million per year starting in 2000. There are no federal funds
available to assist State, local, and tribal governments in meeting
these costs. There are important benefits from NOX emission
reductions because atmospheric emissions of NOX have adverse
impacts on human health and welfare and on the environment.
The proposed 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.^{22
On the contrary, the rule

[[Page 1479]]
will result in only a minimal increase in average electricity rates.
Moreover, the rule will not have a material effect on the national
economy.

\22\ 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 0.110 mills/kWh while the
national average control costs are 0.109 mills/kWh.
---------------------------------------------------------------------------

In developing the proposed rule, EPA provided numerous
opportunities for consultation with interested parties, including
State, local, and tribal governments, at public conferences and
meetings. EPA evaluated the comments and concerns expressed, and the
proposed rule reflects, to the extent consistent with section 407 of
the Clean Air Act, those comments and concerns. These procedures will
ensure State and local governments an opportunity to give meaningful
and timely input and obtain information, education, and advice on
compliance. Additionally, the EPA will initiate consultations with the
affected State and local governments. The 25 State and municipality
owned utilities will be provided by EPA with a brief summary of the
proposal and the estimated impacts.
As described in EPA's analysis (see docket item II-F-4, 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 municipality or State owned utilities, are 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

The information collection requirements in this proposed rule have
been submitted for approval to the Office of Management and Budget
(OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. An
Information Collection Request (ICR) document will be prepared by EPA
and a copy may be obtained from Sandy Farmer, OPPE Regulatory
Information Division; U.S. Environmental Protection Agency (2136), 401
M St. SW., Washington, DC 20460, or by calling (202) 260-2740.
The annual public reporting and recordkeeping burden for this
collection of information is estimated to average 9 hours per response.
This estimate includes the time needed to review instructions; develop,
acquire, install, and utilize technology and systems for the purposes
of collecting, validating, and verifying information, processing and
maintaining information, and disclosing and providing information;
adjust the existing ways to comply with any previously applicable
instructions and requirements; train personnel to respond to a
collection of information; search existing data sources; complete and
review the collection of information; and transmit or otherwise
disclose the information.
No person is required to respond to a collection of information
unless it displays a currently valid OMB control number. The OMB
control numbers for EPA's regulations are displayed in 40 CFR Part 9.
Send comments regarding the burden estimate or any other aspect of
this collection of information, including suggestions for reducing this
burden to Chief, OPPE Regulatory Information Division; U.S.
Environmental Protection Agency (2136), 401 M St., SW., Washington, DC
20460; and to the Office of Information and Regulatory Affairs, Office
of Management and Budget, Washington, DC 20503, marked ``Attention:
Desk Officer for EPA.'' Include the ICR number in any correspondence.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.

E. Regulatory Flexibility Act

The Regulatory Flexibility Act (5 U.S.C. Sec. 601, et seq.)
requires EPA to consider potential impacts of proposed regulations on
small business ``entities.'' If a preliminary analysis indicates that a
proposed regulation would have a significant economic impact on 20
percent or more of small entities, then a regulatory flexibility
analysis must be prepared.
Current Regulatory Flexibility Act guidelines indicate that an
economic impact should be considered significant if it meets one of the
following criteria: (1) Compliance increases annual production costs by
more than 5 percent, assuming costs are passed onto consumers; (2)
compliance costs as a percentage of sales for small entities are at
least 10 percent more than compliance costs as a percentage of sales
for large entities; (3) capital costs of compliance represent a
``significant'' portion of capital available to small entities,
considering internal cash flow plus external financial capabilities; or
(4) regulatory requirements are likely to result in closures of small
entities.
Under the 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. EPA's initial estimates are that the burden on small
utilities under Phase II is minimal.
Pursuant to the provisions of 5 U.S.C. Sec. 605(b), I hereby
certify that this rule, if promulgated, will not have a significant
adverse impact on a substantial number of small entities.

F. 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 18, 1995.
Carol M. Browner,
Administrator.

For the reasons set out in the preamble, 40 CFR part 76 is amended
as follows:

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 definitions for
``combustion controls'', ``fluidized bed combustor boiler'', ``non-
plug-in combustion controls'', ``plug-in combustion controls'', and
``vertically fired boiler'', to read as follows:

Sec. 76.2 Definitions.

* * * * *
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.
* * * * *

[[Page 1480]]

Fluidized bed combustor boiler means a boiler in which crushed
coal, in combination with inert material (e.g., silica, alumina, or
ash) and air, is maintained in a turbulent, suspended state and is
combusted at relatively low temperatures.
* * * * *
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 arch-fired boilers, dry bottom roof-fired boilers,
and dry bottom top-fired boilers and shall exclude 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 removing paragraph (g).
4. Section 76.6 is added 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, a vertically fired boiler,
or a fluidized bed combustor 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. 76.11 or 76.12:
(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 prior to January 1, 2000 shall comply
with the emission limitation applicable to cell burner boilers.
(2) 0.94 lb/mmBtu of heat input on an annual average basis for
cyclone boilers. The NOX emission control technology on which the
emission limitation is based is coal reburning, natural gas reburning,
or selective catalytic reduction.
(3) 0.86 lb/mmBtu of heat input on an annual average basis for wet
bottom boilers. The NOX emission control technology on which the
emission limitation is based is combustion controls.
(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.
(5) 0.29 lb/mmBtu of heat input on an annual average basis for
fluidized bed combustor boilers. The NOX emission control
technology on which the emission limitation is based is fluid bed
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 added 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, 76.11, or 76.12:
(1) 0.38 lb/mmBtu of heat input on an annual average basis for
tangentially fired boilers.
(2) 0.45 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.

Sec. 76.8 [Amended]

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 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 ``Sec. 76.5(g) or 76.6'' and adding, in their place, the
words ``Secs. 76.6 or 76.7''.

Appendix B [Amended]

8. Appendix B is amended by: removing from the heading of Appendix
B 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 words ``distribution of costs''; removing
from section 1 the words ``average capital costs and cost-
effectiveness'' and adding, in their place, the words ``average capital
costs and distribution of cost effectiveness''; removing from section
1, the introductory text of section 2, and section 2.4 the words
``Group 1, Phase I'' in each place that the words appear and adding, in
their place, the words ``Group 1''; and removing and reserving section
3.

[FR Doc. 96-494 Filed 1-18-96; 8:45 am]
BILLING CODE 6560-50-P}}}}}}}}}}}}}}}}}

Visit the Official Version

Document Information

Published:: 01/19/1996
Department:: Environmental Protection Agency
Entry Type:: Proposed Rule
Action:: Proposed rule and notice of public hearing.
Document Number:: 96-494
Dates:: Comments. Comments must be received on or before March 4, 1996.
Pages:: 1442-1480 (39 pages)
Docket Numbers:: AD-FRL-5400-2
RINs:: 2060-AF48: Acid Rain Phase II Nitrogen Oxides Reduction Program
RIN Links:: https://www.federalregister.gov/regulations/2060-AF48/acid-rain-phase-ii-nitrogen-oxides-reduction-program
PDF File:: 96-494.pdf
CFR: (7): 40 CFR 76.2; 40 CFR 76.5; 40 CFR 76.6; 40 CFR 76.7; 40 CFR 76.8; More ...