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



[[Page 67111]]

_______________________________________________________________________

Part II





Environmental Protection Agency





_______________________________________________________________________



40 CFR Part 76



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

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

[[Page 67112]]



ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 76

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


Acid Rain Program; Nitrogen Oxides Emission Reduction Program

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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

SUMMARY: This action promulgates standards for the second phase of the 
Nitrogen Oxides Reduction Program under Title IV of the Clean Air Act 
(``CAA'' or ``the Act'') by establishing nitrogen oxides (NOX) 
emission limitations for certain coal-fired electric utility units and 
revising NOX emission limitations for others as specified in 
section 407(b)(2) of the Act. The emission limitations will reduce the 
serious adverse effects of NOX emissions on human health, 
visibility, ecosystems, and materials.

EFFECTIVE DATE: December 19, 1996.

ADDRESSES: Docket. Docket No. A-95-28, containing information 
considered during development of the promulgated standards, is 
available for public inspection and copying between 8:30 a.m. and 3:30 
p.m., Monday through Friday, at EPA's Air Docket Section (LE-131), 
Waterside Mall, Room M1500, 1st Floor, 401 M Street, SW, Washington, DC 
20460. A reasonable fee may be charged for copying.
    Background information document. The background information 
document containing responses to public comments on the proposed 
standards may be obtained from the docket. Please refer to ``Phase II 
Nitrogen Oxides Emission Reduction Program--Response to Comments 
Document''.

FOR FURTHER INFORMATION CONTACT: Peter Tsirigotis, Source Assessment 
Branch, Acid Rain Division (6204J), U.S. Environmental Protection 
Agency, 401 M Street S.W., Washington, DC 20460 (202-233-9620).

SUPPLEMENTARY INFORMATION:

Regulated Entities

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

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

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

    I. Rule Background
    A. Purpose of Acid Rain NOX Emission Reduction Program
    B. Summary of Final Rule
    1. NOX Standards Promulgated by this Rule
    2. Rationale for Revising Group 1 NOX Emission Limits and 
Environmental Impact of Group 2 NOX Emission Limits
    II. Public Participation
    III. Summary of Major Comments and Responses
    A. Phase II, Group 1 Boiler NOX Emission Limits
    1. Boiler Population Used to Assess NOX Emission Limits
    2. Time Period/Averaging Basis Used to Evaluate Performance of 
Low NOX Burner Technology
    3. Analysis Method Used to Establish Reasonably Achievable 
Emission Limitations for Phase II, Group 1 Boilers
    4. Percentile Used to Define Achievability
    B. Group 2 Boiler NOX Emission Limits
    1. Cost Comparability and Its Basis
    2. Cost Comparison Methodology
    3. Retrofit Nature of Group 2 Controls
    4. Group 2 Boiler Size Exemption
    5. Cyclone Boiler NOX Controls
    6. Wet Bottom Boiler NOX Controls
    7. Vertically Fired Boiler NOX Controls
    8. Cell Burner Boiler NOX Controls
    9. Revision of Proposed Group 2 Boiler NOX Emission Limits
    C. Compliance Issues
    D. Title IV NOX Program's Relationship to Title I and 
NOX Trading Issues
    IV. Administrative Requirements
    A. Docket
    B. Executive Order 12866
    C. Unfunded Mandates Act
    D. Paperwork Reduction Act
    E. Regulatory Flexibility Act
    F. Submission to Congress and the General Accounting Office
    G. Miscellaneous

I. Rule Background

A. Purpose of Acid Rain NOX Emission Reduction Program

    The primary purpose of the Acid Rain NOX Emission Reduction 
Program is to reduce the multiple adverse effects of the oxides of 
nitrogen, a family of highly reactive gaseous compounds that contribute 
to air and water pollution, by substantially reducing annual emissions 
from coal-fired power plants. Since the 1970 passage of the Clean Air 
Act, NOX has increased about 7%; it is the only conventional air 
pollutant to show an increase nationwide.
    Electric utilities are a major contributor to NOX emissions 
nationwide: in 1980, they accounted for 30 percent of total NOX 
emissions and, from 1980 to 1990, their contribution rose to 32 percent 
of total NOX emissions. In 1994, electric utility emissions 
represented about 33 percent of the total annual NOX emissions. 
Approximately 90 percent of estimated electric utility NOX 
emissions were attributed to coal combustion (see docket item IV-A-8 
(USEPA, National Air Pollution Emission Trends, 1900-1994 (EPA-454/R-
95-011) at 2-2, October 1995)).
    The NOX emissions discharged into the atmosphere from the 
burning of fossil fuels consists primarily of nitric oxide (NO). Much 
of the NO, however, reacts with organic radicals in the air to form 
nitrogen dioxide (NO2) and, over longer periods of time, reacts 
with and forms other pollutants, including ozone (O3), nitric acid 
(HNO3) and fine particles. These pollutants are harmful to public 
health and the environment.
    NO2 and airborne nitrate also degrade visibility, and when 
they return to the earth through rain, snow, or fog (``wet 
deposition'') or as gases (``dry deposition''), they contribute to 
acidification of lakes and streams and to excessive nitrogen loadings 
to estuaries and coastal water systems such as in the Chesapeake Bay 
(``eutrophication'').
    NO2 has been documented to cause eye irritation, either by 
itself or when oxidized photochemically into peroxyacetyl nitrate 
(PAN). Ozone, the most abundant of the photochemical oxidants, is a 
highly reactive chemical compound which can have serious adverse 
effects on human health, plants, animals, and materials. Fine particles 
at current ambient levels contribute adversely to morbidity and 
mortality.

[[Page 67113]]

B. Summary of Final Rule

1. NOX Standards Promulgated by This Rule
    EPA today is promulgating new emission limitations to be 
implemented for nitrogen oxides (NOX) emissions for wall-fired and 
tangentially fired boilers (Group 1 boilers) and establishing emission 
limitations for certain other boilers (Group 2 boilers). The final rule 
implements section 407 (b)(2) of the Act, which applies to NOX 
emission limitations for Group 1 and Group 2 boilers during Phase II of 
the Acid Rain Program (January 1, 2000 and beyond). Under section 
407(b)(2) the Administrator ``may revise'' the applicable NOX 
emission limitations for Group 1 boilers in Phase II if the 
Administrator determines that ``more effective low NOX burner 
technology is available,'' i.e., that data on the effectiveness of low 
NOX burner technology (LNB) installed after passage of the Clean 
Air Act Amendments of 1990 supports emission limitations more stringent 
than the limitations established for Group 1 boilers during Phase I of 
the Acid Rain Program pursuant to section 407(b)(1) of the Act. 42 
U.S.C. 7651f(b)(2). Also under section 407(b)(2) of the Act, the 
Administrator must establish NOX emission limitations (on a lb/
mmBtu annual average basis) for Group 2 boilers, which include wet 
bottom boilers, cyclone boilers, cell burner boilers, and all other 
types of utility boilers not classified as dry bottom wall-fired and 
tangentially fired boilers, and must meet certain requirements in 
establishing these limitations. In setting the final emission 
limitations for Group 1 and Group 2 boilers, as summarized below, the 
Administrator has met the requirements in section 407(b)(2) of the Act.

i. Revision of NOX Emission Limits for Phase II, Group 1 Boilers

    The Agency has developed a computerized database containing 
detailed information on the characteristics and emission rates of all 
coal-fired units with Group 1 boilers on which low NOX burners 
(LNBs) have been installed without any other NOX controls, and for 
which EPA has both quality assured long-term post-retrofit hourly 
NOX emission rate data, measured by continuous emission monitoring 
systems (CEMS), certified pursuant to 40 CFR part 75 (Acid Rain 
Continuous Emission Monitoring Rule), and quality assured short-term 
CEM or test data measurements of uncontrolled emission rates. This 
database, called the ``LNB Application Database,'' consists of 39 dry 
bottom wall-fired boilers and 14 tangentially fired boilers and forms 
the technical basis for EPA's evaluation of the effectiveness (percent 
NOX removal) of LNBs applied to Group 1 boilers.
    For the final rule, EPA has adopted a methodology that employs 
``load-weighted annual average NOX emission rates'' over the full 
``post-optimization period'' for evaluating the effectiveness of LNBs. 
The post-optimization period includes all available data beginning with 
the first hour of the low NOX period,1 when the LNBs were 
operating under optimized NOX removal conditions, and extending to 
the end of the entire data set, i.e., through June 30, 1996, the end of 
the latest available reporting period from the Acid Rain Emissions 
Tracking System (ETS). The post-optimization period contains quality 
assured CEM data spanning at least 4 calendar months for every boiler 
and at least 11 calendar months for most boilers (83%). In addition, 
EPA applied a NOX/load weighting scheme, using hourly load data 
reported for 1995, to develop ``load-weighted'' annual average NOX 
emission rates from the data set (see discussion in section III.A.2.iii 
of this preamble). Two advantages of using load-weighted annual average 
NOX emission rates over the post-optimization period are that the 
criteria used to define the ``post-optimization period'' take into 
account the site-specific nature of the LNB equipment optimization and 
operator training processes while the use of ``load weighting'' 
accounts for any potential impact of annual load dispatch patterns on 
NOX emissions.
---------------------------------------------------------------------------

    \1\ The ``low NOX period'' EPA used for assessing 
performance of LNBs applied to Group 1 boilers was defined by 
identifying the lowest average NOX emission rate each boiler 
has sustained for at least 52 days, i.e., over a period of 1,248 
hours when the boiler was operating and valid CEM data, measured by 
CEMS certified pursuant to 40 CFR part 75, were available. (Data for 
30 calendar days following estimated date boiler began operating 
after shutdown for LNB retrofit are not used when making this 
determination. See Table 1, DQO #4D).
---------------------------------------------------------------------------

    Following the identification of appropriate LNB applications and 
time period for analysis, EPA developed a two-part model to estimate: 
(1) Annual average emission rates that can be sustained by LNBs 
installed on Phase II units with Group 1 boilers and (2) percentile 
distributions of Phase II units that can comply with various 
performance standards. The first part of the model calculates the 
percent reduction achievable by LNBs as a function of uncontrolled 
emission rate, and the second part applies the estimated percent 
reduction to boiler-specific uncontrolled emission rates for the 
population of units that will be subject to any revised NOX 
emission limitations in Phase II. EPA used the percentile distributions 
to select reasonably achievable emission limits for the two types of 
Group 1 boilers, where ``reasonably achievable'' is defined as the 
controlled emission rate 85 to 90 percent of the affected population of 
units can meet or exceed on an annual average basis.

    EPA concludes that more effective low NOX burner technology 
is available for dry bottom wall-fired and tangentially fired 
boilers. Further, EPA concludes that for dry bottom wall-fired 
boilers, 0.46 lb/mmBtu is a reasonable emission limitation that is 
achievable using such technology. EPA estimates that 85 to 90% of 
the Phase II dry bottom wall-fired boilers can achieve this emission 
rate. The implementation of this standard, will result in an 
additional NOX emissions reduction of approximately 90,000 tons 
per year, beginning in 2000, below the emission levels anticipated 
under the Phase I Acid Rain NOX Emission Reduction Rule (60 FR 
18751, April 13, 1995).
    Finally, EPA concludes that for tangentially fired boilers, 0.40 
lb/mmBtu is a reasonable emission limitation that is achievable 
using such technology. EPA estimates that 85 to 90% of the Phase II 
tangentially fired boilers can achieve this emission rate. The 
implementation of this standard will result in an additional 
NOX emissions reduction of approximately 30,000 tons per year, 
beginning in 2000, below the emission levels anticipated under the 
Phase I Acid Rain NOX Emission Reduction Rule. As discussed 
below, EPA exercises its discretion under section 407(b)(1) to adopt 
these revised Group 1 NOX emission limitations because the 
resulting additional reductions are a reasonable step toward 
achieving necessary, significant NOX reductions and are 
consistent with the guideline in section 401(b) concerning the level 
of NOX reductions to be achieved.

ii. Establishment of Group 2 Emission Limitations

    In order to meet the requirements of section 407(b)(2), EPA is 
using the following methodology for establishing Group 2 emission 
limitations:
    First, EPA determines what NOX control technologies are the 
best systems of continuous emission reduction available for each 
category of Group 2 boilers. Further, EPA considers only technologies 
for which there is reliable cost information on which to base a 
determination of whether they are of comparable cost to LNBs, applied 
to Group 1 boilers.
    Second, EPA evaluates each such NOX control technology and 
estimates the dollar cost per ton of NOX removed using the control 
technology on each boiler in the Group 2 population that is in the 
appropriate Group 2 boiler category. EPA then compares the dollar cost 
per ton of NOX removed for each

[[Page 67114]]

NOX control technology applied to the Group 2 boiler category to 
the dollar cost per ton of NOX removed for low NOX burners 
applied to dry bottom wall-fired and tangentially fired boilers. Based 
on this comparison, EPA determines whether the NOX control 
technology applied to the Group 2 boiler category has a cost-
effectiveness comparable to that of LNBs applied to Group 1 boilers.
    Third, EPA estimates the percent change in electricity rates for 
consumers resulting from costs (in mills per kilowatt-hour) associated 
with the application of emission limitations on Group 2 boilers. This 
value is then compared to the percent change in nationwide electricity 
rates due to the establishment of emission limitations for LNBs on 
Group 1 boilers. EPA also estimates the emission reductions that are 
likely to be achieved and considers any other environmental impacts 
likely to result from application of each NOX control technology.
    Fourth, EPA assesses the performance (percent NOX reduction) 
of each cost-comparable Group 2 control technology and applies that 
reduction percentage to data on the uncontrolled emissions of each 
boiler that is in the particular category of Group 2 boilers and that 
will be subject to the Group 2 emission limitation. The emission 
limitation that will be achievable by 85 to 90% of the boiler 
population is generally selected, after taking account of energy and 
environmental impacts, as the emission limitation for that category of 
Group 2 boiler.
    EPA concludes that for cell-burner fired boilers, 0.68 lb/mmBtu is 
a reasonable emission limitation that meets the requirements of section 
407(b)(2). For cell burner boilers, plug-in retrofits and non-plug in 
retrofits are the best continuous control systems that are available 
and meet the cost comparability requirement. EPA bases the emission 
limitation on the use of these control technologies and estimates that 
80% of the cell burner population can achieve the limitation. The 
energy impact, i.e., impact of mills/kWh cost on electricity consumers, 
of using these technologies to meet the emission limitation is small 
and similar in magnitude to the energy impact of using LNBs on Group 1 
boilers. The emission limitation will result in a total NOX 
emissions reduction of approximately 420,000 tons per year, beginning 
in 2000, without significant increases in other air pollutants or solid 
waste. As discussed below, the resulting NOX reductions are a 
reasonable step toward achieving necessary, significant NOX 
reductions and are consistent with section 401(b).
    EPA concludes that for cyclone fired boilers larger than 155 MWe, 
0.86 lb/mmBtu is a reasonable emission limitation that meets the 
requirements of section 407(b)(2). For cyclone fired boilers, gas 
reburning, and SCR are the best continuous control systems that are 
available and meet the cost comparability criteria. The energy impact, 
i.e., impact of mills/kWh cost on electricity consumers, of using these 
technologies to meet the emission limitation is small and similar in 
magnitude to the energy impact of using LNBs on Group 1 boilers. EPA 
bases the emission limitation on the use of these technologies and 
estimates that 85 to 90% of the cyclone fired boiler population can 
achieve the emission limitation. The emission limit will result in a 
total NOX emissions reduction of approximately 225,000 tons per 
year, beginning in 2000, without significant increases in other air 
pollutants or solid waste. As discussed below, the resulting NOX 
reductions are a reasonable step toward achieving necessary, 
significant NOX reductions and are consistent with section 401(b). 
EPA has decided not to set a NOX emission limitation for cyclone 
boilers of 155 MWe or less.
    EPA concludes that for wet bottom boilers larger than 65 MWe, 0.84 
lb/mmBtu is a reasonable emission limitation that meets the 
requirements of section 407(b)(2). For wet bottom boilers, gas 
reburning, and SCR are the best continuous control systems that are 
available and meet the cost comparability requirement. EPA bases the 
emission limitation on the use of these technologies and estimates that 
85 to 90% of the wet bottom boiler population can achieve the emission 
limitation. The energy impact, i.e., impact of mills/kWh cost on 
electricity consumers, of using these technologies to meet the emission 
limitation is small and similar in magnitude to the energy impact of 
using LNBs on Group 1 boilers. The emission limitation will result in a 
total NOX emissions reduction of approximately 80,000 tons per 
year, beginning in 2000, without significant increases in other air 
pollutants or solid waste. As discussed below, the resulting NOX 
reductions are a reasonable step toward achieving necessary, 
significant NOX reductions and are consistent with section 401(b). 
EPA has decided not to set a NOX emission limitation for wet 
bottom boilers of 65 MWe or less.
    EPA concludes that for vertically fired boilers 0.80 lb/mmBtu is a 
reasonable emission limitation that meets the requirements of section 
407(b)(2). For vertically fired boilers, combustion controls are the 
best continuous control system available and meet the cost 
comparability requirement. EPA bases the emission limitation on the use 
of these technologies and estimates that 85 to 90% of the vertically 
fired boiler population can achieve this emission limitation. The 
energy impact, i.e., impact of mills/kWh cost on electricity consumers, 
of using these technologies to meet the emission limitation is small 
and similar in magnitude to the energy impact of using LNBs on Group 1 
boilers. The emission limitation will result in a total NOX 
emissions reduction of approximately 45,000 tons per year, beginning in 
2000, without significant increases in other air pollutants or solid 
waste. As discussed below, the resulting NOX reductions are a 
reasonable step toward achieving necessary, significant NOX 
reductions and are consistent with section 401(b). EPA has decided not 
to set a NOX emission limitation for arch-fired boilers, a subset 
of the vertically fired boiler category.
    Finally, EPA has decided not to set a NOX emission limitation 
for FBC boilers. Because these units are already low NOX emitters 
by design, the NOX emissions reduction achieved by installing any 
additional control technology, would not meet the cost-comparability 
requirement of section 407(b)(2). Moreover, setting an emission 
limitation that can be achieved by every existing FBC boiler without 
installing any additional control technology would have an adverse 
environmental impact. Some existing boilers emit at rates considerably 
below the highest annual rate observed among FBC boilers and these 
boilers could offset the emission reductions otherwise required of 
other affected boilers through emissions averaging under Sec. 76.10.
    EPA has also decided not to set a NOX emission limitation for 
stoker boilers. EPA has not found any continuous control technology for 
stoker boilers that meets the cost-comparability requirement.
2. Rationale for Revising Group 1 NOX Emission Limits and 
Environmental Impact of Group 2 NOX Emission Limits
    EPA is exercising its discretion to revise the Phase II, Group 1 
NOX emission limitations because: (1) NOX emissions have 
significant adverse effects on human health and the environment; (2) 
significant, additional regional NOX reductions from current 
levels are likely to be necessary; (3) without additional actions 
NOX emissions are projected to increase

[[Page 67115]]

nationwide starting in 2002; (4) the revision of Phase II, Group 1 
emission limitations is one of the most cost-effective means of 
achieving additional NOX reductions; and (5) the additional 
reductions from the revision represent a reasonable step toward 
achieving necessary NOX reductions. In addition, the resulting 
NOX reductions are consistent with section 401(b). The adverse 
health and environmental effects of NOX emissions are discussed in 
the proposed rule on Phase II NOX emission limitations. 61 FR 
1442, 1453-55, January 19, 1996. EPA reaffirms that discussion, which 
summarizes the adverse impact of NOX emissions through: The 
formation of ozone, particulate matter, and nitrogen oxides; and 
atmospheric deposition resulting in eutrophication of water bodies and 
acidification of lakes and streams. For the same reasons, EPA also 
concludes that the adoption of the Group 2 emission limitations set 
forth in today's rule is supported by the environmental impact of the 
emission reductions that will result.
    The contribution of nitrogen oxides to the formation of ozone, acid 
deposition and eutrophication of water bodies is substantial. 
Consequently, in order to address these problems, significant NOX 
emission reductions are likely to be needed on a regional scale, 
particularly in the eastern half of the U.S. This is the portion of the 
nation in which most of the boilers subject to NOX emission 
limitations under the Acid Rain Program are located; 87% of Phase II, 
Group 1 boilers and 89% of Group 2 boilers covered by today's final 
rule are in the eastern U.S.

i. Ozone

    With regard to ozone, additional regional NOX reductions of at 
least 50% from current levels are likely to be needed over large 
portions of the nation to attain and maintain the national ambient air 
quality standard for ozone. Modeling results using EPA's Regional 
Oxidant Model (ROM) estimated that NOX reductions of about 75% 
will be needed over large portions of the nation to reduce ozone 
concentrations to levels at or below the NAAQS (see docket item IV-J-8 
(EXISTMOD.TXT, OTAG Modeling and Assessment Subgroup Files on EPA's TTN 
Bulletin Board, February 7, 1996)). The ROM modeling results were among 
the reasons for the formation of the Ozone Transport Assessment Group 
(OTAG), comprised of the 37 eastern-most States and tasked with 
developing a consensus approach for reducing regional NOX 
emissions. OTAG recently completed atmospheric modeling simulations 
using SAI's Urban Airshed Model (UAM-V) (see docket item IV-J-21 (OTAG 
Air Quality Analysis Workgroup, 1996)). The results indicate that: 
broad NOX emission reductions will decrease regional ozone, high 
ozone, and ozone in non-attainment areas; and NOX emission 
reductions in each OTAG sub-region will be needed to both lower ozone 
in that same sub-region, as well as other sub-regions.
    Further, necessary NOX reductions to achieve or maintain the 
ozone standard have been estimated for several other areas of the 
country: 50-75% from 1990 levels throughout the Northeast Ozone 
Transport Region (OTR) (60 FR 4712, 4722, January 24, 1995); up to 90% 
reductions in the Southeast (see docket item II-I-98 (State of the 
Southern Oxidants Study, 1995)); and a combination of 75% reductions 
for NOX and 25% for VOCs regionally, combined with 25% for 
NOX and 75% for VOCs locally in the New York region (60 FR 4721); 
and significant NOX reductions in the Lake Michigan area, not yet 
quantified. The results of a study analyzing ozone non-attainment in 
the eastern U.S. found that nationwide NOX emission reductions of 
about 50% from 1990 levels will be needed to approach achievement of 
the necessary ozone standards (see docket item IV-J-9 (Rao, S.T., 
et.al., Dealing with the Ozone Non-Attainment Problem in the Eastern 
United States, AWMA journal, January 1996)).

ii. Acid Deposition

    Similarly, additional, regional NOX reductions of at least 40% 
are likely to be necessary in order to mitigate the effects of acid 
deposition. In particular, it is estimated that between 40-50% 
reductions of NOX in the Eastern U.S. beyond those already 
required in the Clean Air Act may be necessary simply to keep the 
number of acidified lakes in the Adirondacks in New York at 1984 
levels. (See docket item IV-A-6 (Acid Deposition Standard Feasibility 
Study (EPA 430-R-95-001a) at xvi).) Without additional reductions, the 
number of acidic lakes in the Adirondacks are projected to increase by 
almost 40% by 2040. Id. at 47. Significant, additional reductions may 
also be necessary with regard to the Mid-Appalachian region (see docket 
item IV-A-6 (Acid Deposition Standard Feasibility Study at xvi)).

iii. Eutrophication

    NOX emissions also contribute significantly to eutrophication, 
i.e., an overabundance of nitrogen to water bodies that leads to 
problems of nutrient enrichment. Regional NOX emission reductions 
of up to 40% are likely to be needed. The signatories to the Chesapeake 
Bay Agreement, (Maryland, Pennsylvania, Virginia, the District of 
Columbia, the Chesapeake Bay Commission, and the federal government) 
have agreed on a goal of a 40% reduction in nitrogen loadings to the 
Bay by 2000 (relative to a 1985 baseline), representing a reduction of 
34 million kilograms of nitrogen (see docket item IV-J-11 (Hicks et 
al., 1995:6)). In addition, they agreed to maintain, after 2000, a cap 
on nitrogen loadings at 60% of baseline loadings. Present estimates are 
that approximately 27% of total nitrogen loading to the Bay system 
comes from atmospheric sources in the form of NOX emissions (see 
docket items IV-J-26 (Linker et al., 1993) and IV-J-19 (Valigura et 
al., 1995)). Since reducing nitrogen loading through the control of 
NOX emissions can be as cost-effective as controlling non-
atmospheric sources of nitrogen loading (e.g., point sources such as 
waste water treatment and non-point sources such as farms), up to a 40% 
reduction of the contribution in NOX emissions to the Bay in areas 
contributing to the eutrophication of the Bay is likely to be 
necessary.
    Although the watershed of the Chesapeake Bay encompasses 
approximately 64,000 square miles, the Chesapeake Bay ``airshed,'' 
which is the contiguous area providing 70% of the atmospheric 
deposition loads to the watershed (see docket item IV-J-18 (Dennis, 
1996)), covers up to 600,000 square miles in area (see docket item IV-
J-3 (Valigura et al., 1996:23)). The airshed extends upwind of, as well 
as bordering the water body itself: south to South Carolina, north to 
Ontario, Canada, and westward up to 500 miles (see docket item IV-J-11 
(Hicks et al., 1995:6)). NOX emissions from outside this area not 
only contribute to eutrophication in the Bay but also to the entire 
coastline, such as from the Carolinas to New York (see docket item IV-
J-3 (Valigura et al., 1996:23)).

iv. Utility Contribution to Atmospheric NOX Emissions

    Electric utilities contributed approximately 33% of total 
atmospheric NOX emissions in 1994, thus substantially contributing 
to ozone formation, acid deposition, and eutrophication.
    Table 1 summarizes the reductions in atmospheric NOX emissions 
likely needed and the additional reductions provided by today's final 
rule. Although the additional reductions from coal-fired utility 
boilers under the final rule are substantial, they represent only

[[Page 67116]]

about 5% of all atmospheric NOX emissions from all sources of 
NOX emissions. The additional reductions under the final rule 
represent about a 15% reduction in total utility emissions. Since 
utilities presently contribute about 33% of total NOX emissions, 
the final rule provides reductions of about 5% of total NOX 
emissions. This reduction level is significantly less than the 
reduction level likely to be needed to mitigate ozone, acid deposition, 
and eutrophication (see docket item IV-A-8 (EPA, ``National Air 
Pollution Emission Trends, 1900-1994'' at 2-2, October, 1995, EPA-454/
R-95-011)).

           Table 1.--Estimated Regional Reductions Necessary to Mitigate Various Environmental Effects          
----------------------------------------------------------------------------------------------------------------
                                              Environmental effect                                              
-----------------------------------------------------------------------------------------------------------------
                                                Ozone               Acid deposition           Eutrophication    
----------------------------------------------------------------------------------------------------------------
Regional NOX Reductions Necessary....  More than 50%..........  More than 40%..........  Up to 40%              
NOX Reductions Achieved from the       5%.....................  5%.....................  5%                     
 Final Rule as Percentage of Total                                                                              
 NOX Emissions.                                                                                                 
----------------------------------------------------------------------------------------------------------------

v. NOX Reductions Not Sustained

    Although national NOX emissions are expected to decrease up to 
the year 2000, (see docket item IV-A-8 (EPA, ``National Air Pollution 
Emission Trends, 1900-1994'' at 5-5, October, 1995, EPA-454/R-95-011)), 
emissions are projected to begin increasing after 2000 (id. at 5-2 and 
6-8 2). The existing NOX control programs under the Clean Air 
Act (including the Mobile Source Program under title II and the Acid 
Rain NOX Program under title IV) limit NOX emission rates 
(e.g., the pounds of NOX emissions per amount of fuel consumed 
(under title IV)) for emission sources. The programs do not cap the 
total tonnage of nationwide emissions. As the number of emission 
sources and the use of emission sources increases, reductions due to 
emission rate limitations are offset to an increasing extent. For this 
reason, after 2002, when implementation of these NOX control 
programs is largely completed and growth in sources and source use 
continues, NOX emissions will gradually increase for the 
foreseeable future (id. at 5-5). Section 401(b) of the Act suggested, 
as a guideline, that NOX emissions should be reduced nationwide by 
2 million tons from the 1980 level. By about 2006, total NOX 
emissions will surpass that guideline unless additional efforts are 
made (e.g., under title IV) to reduce NOX emissions (See figure 1, 
below). The projected increase in total NOX emissions is well 
within the time frame considered by Congress in title IV. EPA notes 
that the nationwide annual cap for SO2 emissions, also established 
under section 402, begins to apply in the year 2010. Until 2010, total 
annual allocated SO2 allowances will exceed the cap, because of 
additional allowances allocated under section 409 for repowered units 
and bonus allowances under section 405. Additional NOX reductions, 
such as these under today's final rule, are necessary both in light of 
the likely need to reduce NOX to address ozone, acid deposition, 
and eutrophication, and in light of the NOX reduction guideline in 
section 401(b) of the Act. In short, new initiatives are needed to 
reduce NOX emissions on a regional scale in order to improve 
environmental quality and health beyond 2000.

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

BILLING CODE 6560-50-P

[[Page 67117]]

[GRAPHIC] [TIFF OMITTED] TR19DE96.000


BILLING CODE 6560-50-C

vi. Cost-Effectiveness

    The revision of Phase II, Group 1 emission limitations and 
establishment of Group 2 emission limitations is a cost-effective means 
of achieving the likely necessary, additional regional NOX 
reductions. The control technologies on which the revised Group 1 
limits and the Group 2 limits are based are more cost-effective (i.e., 
have a lower cost per ton of NOX removed) when applied to the 
respective Group 1 and Group 2 boiler types than most other control 
technologies applied to these boiler types or to non-utility sources. 
As shown below, the dollar cost per ton of NOX removed for 
reductions under the final rule is less than, or at the lower end of, 
the range of dollar cost per ton of NOX removed for most 
alternative reductions. In short, the NOX reductions achievable 
under this final rule are among the less expensive that can be made.

[[Page 67118]]

    Utility Sources: For coal-fired utility boilers using higher level 
control technologies, (e.g., SCR with higher NOX reduction 
capability) than the technologies on which the title IV limits are 
based, the average cost-effectiveness for typical wall-fired boilers 
ranges from $1,226/ton to $1,670/ton with percent reductions ranging 
from 60-90%. For typical tangentially fired boilers, the cost-
effectiveness ranges from $1,439/ton to $1,935/ton with percent 
reductions ranging from 60-90%. For typical cyclone boilers, the cost-
effectiveness ranges from $440/ton to $880/ton with percent reductions 
ranging from 60-90%. For typical cell-burner boilers, the cost-
effectiveness ranges from $624/ton to $801/ton with percent reductions 
ranging from 60-80%. For typical wet bottom boilers, the cost-
effectiveness ranges from $572/ton to $733/ton with percent reductions 
ranging from 60-90%. For typical roof-fired (vertically-fired) boilers, 
the cost-effectiveness ranges from $750/ton to $907/ton with percent 
reductions ranging from 60 to 90%. For typical oil and gas utility 
boilers, the average cost-effectiveness for wall-fired dual-fired 
boilers under various NOX reduction technologies ranges from $748/
ton to $2,263/ton with percent reductions ranging from 40-90%. For 
typical tangentially fired dual-fired boilers, the cost-effectiveness 
ranges from $507/ton to $1,573/ton with percent reductions ranging from 
30-90% (see docket item IV-J-4 (Ozone Transport Assessment Group, 
Control Technologies and Options Workgroup, Final Report, April 11, 
1996)).
    As compared to the cost-effectiveness ranges for higher level 
control technologies applied to typical utility boilers, the average 
cost-effectiveness for meeting the Group 1 and Group 2 emission limits 
under today's final rule, using the control technologies on which the 
limits are based, is approximately $229/ton of NOX removed.
    Non-Utility Point Sources: Non-utility point sources NOX 
reductions are less cost effective, on average, than NOX 
reductions under today's final rule. For example, the average cost-
effectiveness for process heaters ranges from $290-50,000/ton at an 
average reduction of 5-90%. For cement manufacturing, the average cost-
effectiveness ranges from $470-4,870/ton at an average reduction of 20-
90%. For wood manufacturing, the average cost-effectiveness ranges from 
$1,000 to over $10,000/ton at an average reduction of 0-60% (see docket 
item IV-J-4 (Ozone Transport Assessment Group, Control Technologies and 
Options Workgroup, Final Report, April 11, 1996)).
    Mobile Sources: For mobile sources, the cost-effectiveness under 
various NOX control options is also high, on average, as compared 
to reductions under today's final rule. For example, the average cost-
effectiveness for light-duty on highway vehicles ranges from $1,100-
$260,000/ton, with percent reductions ranging from 0.2-21%. For heavy-
duty on highway vehicles, the average cost-effectiveness ranges from 
$1,000/ton to $40,000/ton, with percent reductions ranging from 0.02-
5.6%. For non-road sources, the average cost-effectiveness ranges from 
$119/ton to $23,000/ton, with percent reductions ranging from 0.4-3.4% 
(see docket item IV-J-6 (Mobile Sources Assessment: NOX and VOC 
Reduction Technologies for Application by the Ozone Transport 
Assessment Group, Final Report, March 4, 1996)).
    Table 2 summarizes the cost-effectiveness ranges of NOX 
controls for the three major NOX emitting sources, as compared to 
the cost-effectiveness of reductions under the revised Group 1 limits 
and Group 2 limits.
    Other: The reductions from applying control technologies to coal-
fired power plants under today's final rule can be as cost-effective to 
achieve as reductions from other point sources (e.g., wastewater 
plants) and area sources (e.g., farms, animal pastures). Studies 
concerning eutrophication in the Chesapeake Bay estimate the following 
average cost-effectiveness of control technologies applied to non-
utility sources: chemical addition or biological removal of nitrogen 
from wastewater processing, $4,000 to over $20,000/ton of nitrogen 
removed; and management practices to reduce nitrogen from fertilizers, 
animal waste, and other non-point sources, $1,000 to over $100,000/ton 
of nitrogen removed (see docket items IV-J-25 (Camacho, 1993:97-98) and 
IV-J-27 (Shulyer, 1995:6)).

       Table 2.--Average Cost-Effective of NOX Controls by Source       
                  [Utility, other point source, mobile]                 
------------------------------------------------------------------------
                                            Range in typical            
                                                 cost-          Percent 
                                           effectiveness ($/   reduction
                                                  ton)                  
------------------------------------------------------------------------
Utility sources (Coal w/advanced NOX                                    
 controls):                                                             
    Wall-fired...........................       $1,226-1,670       60-90
    Tangentially-fired...................        1,439-1,935       60-90
    Cyclones.............................            440-880       60-90
    Cell burners.........................            624-801       60-80
    Wet bottoms..........................            572-733       60-90
    Roof (vertically-fired)..............            750-907       60-90
Utility sources (Oil and Gas):                                          
    Wall dual-fired......................          748-2,263       40-90
    Tangential dual-fired................          507-1,573       30-90
------------------------------------------------------------------------
Source: Ozone Transport Assessment Group, Control Technologies and      
  Options Workgroup, Final Report, April 11, 1996.                      


------------------------------------------------------------------------
                                           Average cost-                
                                           effectiveness      Percent   
       Title IV phase II NOX rule             of Sec.        reduction  
                                           407(b)(2) ($/    under Sec.  
                                               ton)          407(b)(2)  
------------------------------------------------------------------------
Group 1 and group 2.....................          $229              20  
------------------------------------------------------------------------
See section IV.B (Table 17) of this preamble.                           


[[Page 67119]]


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


------------------------------------------------------------------------
                                            Range in typical            
                                                 cost-          Percent 
              Mobile sources               effectiveness  ($/  reduction
                                                  ton)                  
------------------------------------------------------------------------
Light-duty (on highway)..................     $1,100-260,000      0.2-21
Heavy-duty (on highway)..................       1,000-40,000    0.02-5.6
Non-road.................................         119-23,000     0.4-3.4
------------------------------------------------------------------------
Source: Mobile Sources Assessment: NOX and VOC Reduction Technologies   
  for Application by the Ozone Transport Assessment Group, Final Report,
  March 4, 1996.                                                        


------------------------------------------------------------------------
                                           Average cost-                
                                           effectiveness      Percent   
       Title IV phase II NOX rule             of Sec.        reduction  
                                           407(b)(2) ($/    under Sec.  
                                               ton)          407(b)(2)  
------------------------------------------------------------------------
Group 1 and Group 2.....................          $229              20  
------------------------------------------------------------------------

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

    As discussed above, in order to mitigate adverse effects on health 
and the environment due to NOX emissions, significant, additional 
reductions in regional atmospheric NOX emissions from current 
levels are likely to be necessary. Further, the contribution of the 
final rule toward the overall NOX reduction goal is approximately 
5%. The NOX reductions under the rule represent only a portion of 
the much larger NOX reductions likely to be needed and are among 
the most cost-effective reductions available. EPA concludes that the 
reductions under the final rule represent a reasonable step toward 
achieving necessary NOX reductions.
    Some commenters suggested that, because the authority to revise the 
Phase II, Group 1 emission limitations and to issue Group 2 emission 
limitations arises under title IV of the Clean Air Act, EPA must 
consider only the acidification impacts of NOX emissions in 
deciding whether to revise or issue limitations. Allegedly, all other 
impacts must be addressed only under other provisions of the Act. EPA 
rejects this crabbed view of its authority under section 407(b)(2) as 
having no basis in statutory language or logic. In granting EPA the 
authority to decide to revise the Phase II, Group 1 emission 
limitations, section 407(b)(2) only requires a determination of the 
availability of more effective LNB technology and does not bar 
consideration of non-acidic deposition impacts. Similarly, in requiring 
EPA to issue Group 2 emission limitations, section 407(b)(2) sets forth 
several criteria for setting the limitations but none of the criteria 
bars consideration of non-acidic deposition impacts. On the contrary, 
section 407(b)(2) has a general requirement that EPA take account of 
``environmental impacts'' in setting Group 2 emission limitations. 42 
U.S.C. 7651f(b)(2).
    In the absence of a statutory bar on considering all environmental 
impacts of NOX emissions and in light of the general purpose of 
the Clean Air Act to, inter alia, ``protect and enhance the quality of 
the Nation's air resources so as to promote the public health and 
welfare and the productive capacity of its population'', it would be 
illogical for EPA to focus exclusively on acid deposition.3 42 
U.S.C. 7401(b)(1). The latter approach would require EPA to regulate on 
a piecemeal basis and to blindly ignore a major part of the harmful 
effects of NOX emissions when setting nationwide NOX emission 
limits under title IV. In any event, EPA maintains that, even if the 
Agency were confined to considering only the acidic deposition effects, 
referred to above, of NOX emissions, it would still conclude that 
additional NOX reductions are necessary and that the emission 
limitations set forth in today's rule should be adopted.
---------------------------------------------------------------------------

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

    Some commenters also noted that section 401(b) states that the 
purpose of title IV is to reduce acidic deposition through reduction of 
annual SO2 emissions of ten million tons from 1980 levels ``and, 
in combination with other provisions of this Act, of nitrogen oxides 
emissions of approximately two million tons from 1980 emission levels, 
in the forty-eight contiguous States and the District of Columbia.'' 42 
U.S.C. 7651(b). According to such commenters, because this goal is 
already met by the existing Phase II, Group 1 emission limitations (as 
well as by regulations under other parts of the Clean Air Act), there 
is no basis for revising the limitations. However, section 401(b) 
provides only general guidance concerning implementation of title IV 
and, in light of the imprecision of its language, does not--and was not 
intended to--impose an absolute limit on the amount of NOX 
reductions that can be required under emission limitations promulgated 
under section 407.
    In contrast to the SO2 provisions of title IV, which set a 
nationwide cap on total tonnage of SO2 emissions (i.e., 8.95 
million tons starting in 2010), the NOX provisions of title IV 
provide only for limits on the NOX emitted per mmBtu of fuel 
burned. Even if the NOX emission limitations are met, increased 
use of existing coal-fired and other

[[Page 67120]]

utility boilers in the future in response to growth in demand for 
electricity can result in increased tonnage of NOX emissions. The 
NOX emissions reductions projected to be achieved through adoption 
of any given set of NOX emission limitations under title IV are 
therefore not permanent. For this reason, when EPA estimates NOX 
reductions resulting from title IV emission limitations, the estimates 
are tied to a specific year, in this case the year 2000. Regulatory 
Impact Analysis of NOX Regulations at 1-7 and 1-8, December 8, 
1995. Moreover, as discussed above, total NOX emissions are 
projected to decline through 2000, increase thereafter, and exceed the 
two million guideline by around 2006. In short, the commenters' claim 
that a two-million-ton emission reduction ``goal'' is ``satisfied'' by 
the existing Group 1 emission limitations is inaccurate because a two-
million-ton level of reductions from 1980 achieved for a given year 
(e.g., for 2000) through these limitations is unlikely to be 
maintained, in the near future without further reductions.
    Although EPA maintains that the 2 million ton guideline in Section 
401(b) aims at total NOX emissions of 2 million tons below the 
1980 levels, EPA notes that the final rule will result in total Group 1 
and Group 2 boiler NOX emissions around 2 million tons less than 
what they otherwise would have been in 2000. The annual NOX 
reductions anticipated from the existing Group 1 emission limitations 
under the April 13, 1995 rule and additional annual reductions 
anticipated from the Phase II, Group 1 and Group 2 emission limitations 
under today's final rule are about 1,170,000 tons and 890,000 tons 
respectively for the year 2000, for a total of about 2,060,000 tons. 
EPA's current estimate of reductions from the April 13, 1995 rule is 
lower than the reductions originally estimated (i.e., about 1,890,000 
tons for the year 2000) for that rule. 59 FR 13538, 13562-63 (March 22, 
1994); see also 59 FR 18760 (adopting for April 13, 1995 rule the 
Regulatory Impact Analysis originally promulgated for the March 22, 
1994 rule).
    In making the original estimates of reductions, EPA used emissions 
factors (i.e., estimated uncontrolled emission rates based on coal type 
and boiler type) to determine the uncontrolled emissions of boilers to 
which the existing Group 1 emission limitations were to be applied. In 
response to comment in today's rulemaking concerning the inaccuracy of 
emission factors, EPA has minimized its use of emission factors and 
instead relied almost exclusively on actual, short-term, uncontrolled 
emissions data from continuous emissions monitoring obtained during 
annual monitor certification testing (i.e., CREV data) or submissions 
of CEM, EPA reference method, or other test data by utilities. This 
data was not generally available to EPA when the April 13, 1995 rule 
was published.4 As a result of using more accurate uncontrolled 
emissions data, EPA's estimates of anticipated reductions under the 
existing Group 1 emission limitations are now more accurate and are 
lower. Even if section 401(b) were viewed as imposing a ``ceiling'' of 
``approximately two million tons'' of NOX reductions under section 
407, the reductions anticipated under the emission limitations adopted 
in the April 13, 1995 rule and today's final rule are consistent with 
that ``ceiling.''
---------------------------------------------------------------------------

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

    For the reasons discussed above, EPA concludes that it should 
exercise its discretion under section 407(b)(2) to revise the Phase II, 
Group 1 emission limitations. The revised Group 1 limits represent a 
reasonable step toward achieving the significant NOX reductions 
that are likely to be necessary, and are consistent with the 2 million 
ton guideline for NOX reductions. The revision of the Group 1 
emission limitations will result in about 120,000 tons of additional 
annual NOX reductions. Actions to achieve NOX reductions 
beyond those realized under title IV are being considered, or will be 
considered in the future, under other titles of the Clean Air Act.
    Unlike the Group 1 limitation revisions, which are discretionary 
under section 407(b)(2), the issuance of Group 2 emission limitations 
is mandatory under that section so long as the requirements of the 
section (e.g., cost comparability) are met. However, as noted above, 
EPA is required, when setting Group 2 emission limitations under 
section 407(b)(2), to consider environmental impacts. EPA's application 
of the section 407(b)(2) requirements for setting Group 2 emission 
limitations--including the consideration of environmental impacts--is 
set forth in detail below in section III.B of this preamble. EPA 
concludes that, like the Group 1 revisions, the Group 2 emission 
limitations supported and adopted in that section of the preamble 
represent a reasonable step toward achievement of necessary, 
significant NOX reductions and are consistent with the 2 million 
ton guideline for NOX reductions.

II. Public Participation

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

III. Summary of Major Comments and Responses

    EPA received approximately 100 comment letters regarding the 
proposed regulations, presenting more than 200 issues. Commenters 
included public and municipal utilities, utility associations, state/
local agencies and Attorneys General, environmental organizations, 
vendors, general industry, research/trade groups, and private citizens. 
A copy of each comment letter received is included in the rulemaking 
docket. A list of commenters, their affiliations, and the EPA docket 
item number assigned to their correspondence is included in the 
background information document.
    All of the comments have been carefully considered, and where 
determined to be appropriate by the Administrator, changes have been 
made in the final regulations. The background information document 
includes a summary of all the comments and EPA's response on each of 
the relevant issues. The following sections of the preamble provide a 
summary of the major comments received and the Agency's response to 
those major comments.

[[Page 67121]]

A. Phase II, Group 1 Boiler NOX Emission Limits

1. Boiler Population Used To Assess NOX Emission Limits
    Background. For the proposed rule, EPA developed a computerized 
boiler database containing detailed information on the characteristics 
and pre-retrofit and post-retrofit emission rates of coal-fired units 
with Group 1 boilers on which low NOX burners (LNBs) had been 
installed without any other NOX controls (``the LNB Application 
Database''). This database contained all known applications of LNBs to 
Group 1 boilers that were installed subsequent to 11/15/90 (the date of 
enactment of the 1990 amendments to the CAA) and for which EPA had at 
least 52 days of quality assured post-retrofit data measured by 
continuous emission monitors (CEMs) certified according to 40 CFR part 
75. The 24 wall-fired boilers and 9 tangentially fired boilers in this 
database formed the empirical basis for EPA's assessment of the 
effectiveness of low NOX burner technology and the revised annual 
NOX emission limitations provisions for Group 1 boilers in the 
proposed rule.
    Comment/Analyses: EPA received approximately 25 comment letters 
(from 19 utilities, 3 utility associations, 2 states, and an 
environmental organization) on the appropriateness of including or 
excluding certain boilers and the selection criteria used to define 
eligibility for the LNB Application Database.
    Several commenters suggested that EPA include specific boilers to 
increase the size and improve the representativeness of the 
tangentially fired subset in the LNB Application Database: Riverbend 7 
and 8, Allen 1 and 3, J.H. Campbell 3, Gallatin 4, and Lansing Smith 2 
(see, for example, docket items IV-D-22, p. 1; IV-D-21, pp. 2-3; IV-D-
20, pp. 7-9, and IV-D-65, p. 22). The commenters acknowledged that many 
of these retrofit cases did not satisfy the quality assurance criteria 
that EPA had established for inclusion in the LNB Application Database. 
They believed, however, that the general benefits of broadening the 
experiential basis for tangentially fired boilers outweighed specific 
data quality concerns. As one commenter said, ``Although not [based on] 
CEM data, Gallatin Unit 4's performance test result of 0.47 lb/10 
6 Btu is reliable, relevant evidence * * * and should be 
considered by EPA.'' (See docket item IV-D-20, p. 9.)
    Commenters also suggested that EPA include specific boilers to 
improve the representativeness of the wall-fired subset in the LNB 
Application Database, particularly with respect to boilers with high 
uncontrolled emission rates: Hammond 4, Watson 4 and 5, Valley 1 and 2 
(see, for example, docket items IV-D-65, p.22). Several commenters 
cited additional wall-fired retrofit cases within the context of the 
related issue of the dependence of NOX emissions on boiler load: 
Conesville 3, Picway 9, Amos 1 and 2, Big Sandy 2, Glen Lyn 6, Colbert 
5, Valley 1-4; Presque Isle 5 and 6 (see docket items IV-D-73, p.1; IV-
D-20, p.5; IV-D-26, p.2).
    On the other hand, several commenters fully endorsed the quality 
assurance criteria EPA has used to determine eligibility for the LNB 
Application Database (see, for example, docket items IV-D-063, p.12; 
IV-D-046, p.3-4). They said that EPA properly excluded older LNB 
installations (such as Gallatin 4, Lansing Smith 2, and Hammond 4) for 
which quality assured long-term post-retrofit CEM data did not exist. 
(EPA notes that this criterion generally excludes experimental or 
otherwise short-lived LNB installations such as those used for 
technology demonstrations, and the Allen units.5) These commenters 
also recommended that EPA should attach greater significance to (or 
rely exclusively on) LNB applications in the 13-state Northeast Ozone 
Transport Region (OTR) for the evaluation of LNB technology 
effectiveness because these applications have been required to meet a 
NOX emission limit beginning May 31, 1995, whereas most other 
applications have not had to comply with a recently established 
NOX standard.
---------------------------------------------------------------------------

    \5\ The Allen plant is located in Gaston County, NC, which, 
until July 1995, was considered in non-attainment for ozone. The 
utility installed LNBs on two Allen boilers, the vendor is reported 
to have optimized in mid 1995. In July 1995, Gaston County was 
redesignated to ozone attainment and low NOX operation was 
discontinued on Allen 1 and 3 on September 1, 1995 (see docket item 
IV-D-22, p. 1). As a result, Allen units 1 and 3 each have less than 
52 days of emissions data after optimization of their respective 
LNBs.
---------------------------------------------------------------------------

    Some commenters correctly noted that one wall-fired boiler in the 
LNB Application Database used for the proposed rule analysis, North 
Valmy 1, should be excluded because this boiler had pre-existing 
NOX controls (i.e., Babcock and Wilcox (B&W) DRB version LNBs) so 
its baseline measurement does not represent an uncontrolled emission 
rate. EPA notes that this NSPS boiler, when retrofitted with modern 
LNBs (i.e., B&W XCL version), has sustained an average post-retrofit 
controlled emission rate of 0.264 for calendar year 1995 (see docket 
item II-A-9). ``NSPS boilers'' are new coal-fired utility units on 
which construction commenced after August 17, 1971, which are subject 
to New Source Performance Standards (NSPS) (40 CFR part 60, subparts D 
or Da). Some NSPS boilers had early versions of LNBs and/or some other 
type of NOX combustion control installed as original equipment. 
EPA has excluded these ``controlled NSPS boilers'' from the LNB 
Application Database and regression models because their measured 
baseline emission rates do not generally represent uncontrolled 
emissions. EPA has included all NSPS boilers, both controlled and those 
without built-in NOX combustion control equipment, in the Phase 
II, Group 1 boiler set to which the models are applied since NSPS 
boilers represent approximately one third of the units affected by this 
rulemaking.
    One commenter recommended that EPA exclude two boilers, Coleman C1 
and Pulliam 7, because, according to this commenter, these boilers have 
low NOX combustion controls beyond the LNB definition in 40 CFR 
76.2. EPA disagrees with this commenter's opinion that these two 
retrofits include auxiliary combustion air outside the waterwall hole 
which are `` `staging' combustion on active burners analogous to 
overfire air'' (see docket item IV-D-51, p. 9). EPA also notes that 
another commenter, who represents 67 utilities, included both units in 
their regression analyses on the performance of LNBs applied to wall-
fired Group 1 boilers (see docket item IV-D-65, p. 58 and Enclosure 8, 
Table 4-1). DOE included Coleman C1 in its regression analyses, but 
excluded Pulliam 8 (probably because, as EPA learned after the rule 
proposal, the utility switched to Powder River Basin coal for both 
Pulliam 7 and 8) (see docket item II-D-62).
    Some commenters recommended that EPA include Group 1 boilers that 
installed both LNB and overfire air (OFA) in the LNB Application 
Database, primarily because they believe units with high uncontrolled 
emission rates were under-represented in the proposed rule analysis 
(see, for example, docket item IV-D-58, p. 4). These commenters 
provided supporting data for certain boilers, including: Eastlake 1, 3, 
and 4; and Ashtabula 7 (see docket item IV-D-23, p. 5). As discussed 
later in this section of the preamble, EPA disagrees with this 
recommendation. First, OFA cannot be considered in determining whether 
to revise the Group 1 limits and the assessment of the achievable 
performance of LNBs alone is problematic when LNBs are used in 
combination with other technologies. Further, the addition of 20 units 
to the LNB Application Database has

[[Page 67122]]

significantly improved the robustness of EPA's regression models for 
units with high uncontrolled emission rates.
    Several commenters agreed with EPA's decision to exclude boilers 
using Powder River Basin or other subbituminous coal from the LNB 
Application Database (see, for example, docket items IV-D-15, p. 3; IV-
D-65, p. 20). For such boilers, measured post-retrofit NOX 
emission reductions reflect the combined effects of switching to a coal 
with inherently lower NOX emissions plus the application of LNBs.
    Response: In light of the comments requesting the inclusion and/or 
exclusion of specific boilers from the LNB Application Database, EPA 
has formalized and expanded the data quality assurance criteria used in 
the rule proposal into Data Quality Objectives (DQOs). The DQOs are 
rigorous and precisely defined rule tables which were used to screen 
all candidate boiler retrofit cases and hourly CEM data observations. 
The DQOs are designed to ensure that the LNB Application Database 
satisfies objective and consistent data quality assurance standards. 
Table 3 presents EPA's DQOs for evaluating candidate boiler retrofit 
cases (DQOs Applied to Boilers) and for quality assuring hourly post-
retrofit CEM data (DQOs Applied to Data).

    Table 3.--Data Quality Objectives Applied to Boilers and Data to Screen Boilers for Inclusion in the LNB    
                                              Application Database                                              
----------------------------------------------------------------------------------------------------------------
       DQO#                    DQOs applied to boilers                               Rationale                  
----------------------------------------------------------------------------------------------------------------
1B                  Only dry bottom wall-fired and tangentially    NOX emission rates for Group 1 boilers affect
                     fired boilers will be included in the          dry bottom wall-fired and tangentially fired
                     database.                                      boilers only.                               
2B                  Boilers must have an installed LNB control     Consistent with Alabama Power v. EPA, 40 F.3d
                     technology only. Boilers with LNB plus         450 (D.C. Cir. 1994), EPA cannot consider   
                     overfire air (OFA) or other controls will      LNB+OFA installations when setting Group 1  
                     not be included in the database. This          limits.                                     
                     determination is made by either (1)                                                        
                     information in EPA's Program Tracking System                                               
                     Database or (2) direct contact with                                                        
                     individual utilities.                                                                      
3B                  Any boiler with an LNB installation date       Revised Group 1 limits are to be based on    
                     prior to November 15, 1990 will not be         improved performance of LNBs installed after
                     included in the database. LNB installation     passage of 1990 Clean Air Act Amendments    
                     dates are determined from (1) EPA's Program    (CAAA).                                     
                     Tracking System Database, (2) estimation of                                                
                     the dates from visual interpretation of                                                    
                     hourly emissions plots, or (3) direct                                                      
                     contact with the utilities.                                                                
4B                  Only boilers with at least 52 days of post-    52 days is generally accepted as the minimum 
                     retrofit data, following an equipment          time period for assessing long-term         
                     ``break-in'' period of 30 calendar days,       performance of NOX combustion control       
                     will be included in the database.              technology (see preamble section            
                                                                    III.A.2.ii). Vendors and utilities          
                                                                    acknowledge existence of ``break-in''       
                                                                    period, lasting about 30 calendar days,     
                                                                    during which boiler operations are often    
                                                                    highly irregular.                           
5B                  Boilers for which LNB design, installation     Boilers with serious and persistent LNB      
                     and/or operations are known to be seriously    design, installation, and operational flaws 
                     flawed will be excluded from the database.     do not reflect the true NOX emission        
                     This determination will be made on the basis   reduction associated with LNB retrofit.     
                     of published utility papers or information     (This DQO is a logical extension of a       
                     submitted to EPA for a rulemaking docket.      pertinent statutory concept. Section 407(d) 
                     (This DQO, however, was never used as the      requires selection of appropriate control   
                     sole basis for rejecting any candidate         equipment ``designed to meet the applicable 
                     boiler retrofit cases from current             emission rate'' as well as proper           
                     database.).                                    installation and operation of such equipment
                                                                    for determining eligibility, and an         
                                                                    appropriate emission rate, for an           
                                                                    alternative emission limitation).           
6B                  Boilers must have a pre-retrofit uncontrolled  Quality assured short-term uncontrolled      
                     emission rate based on quality assured short-  emission rate data are needed to perform    
                     term CEM or test data that is verifiable in    consistent analysis and projections using   
                     the CREV database, the Acid Rain Cost Form     first and second parts of model (see        
                     for NOX Control Costs, or another source       preamble, section III.A.3.ii.).             
                     available to EPA.                                                                          
7B                  Quarterly report submissions for boilers must  Quarterly report submissions that do not     
                     pass the quality assurance (QA) criteria in    satisfy the CEM and other QA criteria in 40 
                     40 CFR part 75.                                CFR part 75 contain insufficient information
                                                                    to verify the accuracy of reported NOX      
                                                                    emission rate data.                         
8B                  NSPS boilers are excluded from the database..  Pre-NSPS boilers differ from NSPS boilers    
                                                                    with regard to furnace volume and heat      
                                                                    release rates and, as a result, NSPS units  
                                                                    can more easily meet a NOX reduction target 
                                                                    by retrofitting LNBs. This makes NSPS units 
                                                                    unrepresentative for establishing overall   
                                                                    LNB NOX reduction efficiency.               
9B                  Only boilers not using Powder River Basin      Powder River Basin coal has been identified  
                     coal will be included in the database.         by utilities as a subbituminous coal which  
                                                                    produces very low NOX emission rates. Its   
                                                                    performance cannot necessarily be reproduced
                                                                    by any other type of coal for LNB           
                                                                    applications.                               
                                                                                                                
----------------------------------------------------------------------------------------------------------------
       DQO#                      DQOs applied to data              Rationale                                    
                                                                                                                
----------------------------------------------------------------------------------------------------------------
1D                  Data generated using EPA's missing data        The missing data routines include a penalty  
                     substitution procedures will not be used (40   for not properly maintaining CEM equipment. 
                     CFR part 75).                                  In order to assess actual LNB performance,  
                                                                    only measured NOX emission rate data will be
                                                                    used.                                       
2D                  Hourly emission rate data will be adjusted     Using bias adjusted NOX emission rates will  
                     using the appropriate bias adjustment factor   ensure compatibility of CEM NOX emission    
                     for the boiler.                                rate measurements obtained from different   
                                                                    monitors.                                   

[[Page 67123]]

                                                                                                                
3D                  NOX emission rates greater than 10 lb/mmBtu    Such reported data values are clearly        
                     and less than or equal to 0 lb/mmBtu will be   erroneous (i.e., physically impossible) and,
                     discarded.                                     thus, should not be included when estimating
                                                                    achievable emission rates.                  
4D                  Hourly emission rate data for ``break-in''     Vendors and utilities acknowledge existence  
                     period, defined as the 30 calendar days        of ``break-in'' period, lasting about 30    
                     following estimated date the boiler began      calendar days, during which boiler          
                     operating after shutdown for LNB retrofit      operations are atypical due to vendor       
                     (denoted on tables as ``LNB retrofit           performance guarantee testing. Discarding   
                     date''), will be discarded.                    hourly emissions data for ``break-in''      
                                                                    period also allows for any uncertainty      
                                                                    associated with exact date of beginning of  
                                                                    post-retrofit period.                       
----------------------------------------------------------------------------------------------------------------

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

                          Table 4.--Wall-fired Boilers in the LNB Application Database                          
----------------------------------------------------------------------------------------------------------------
                                                                                   Load weighted                
                                                                   Uncontrolled        post-                    
    Obs. No.           ORISPL       Unit name/unit ID    Phase     NoX rate (ln/   optimization     Percent NoX 
                                                                      mmBtu)       NoX rate (ln/      removal   
                                                                                      mmBtu)                    
----------------------------------------------------------------------------------------------------------------
1.                26               Gaston unit 1.....          1           0.900           0.384            57.3
2.                26               Gaston unit 2.....          1           0.780           0.384            50.8
3.                26               Gaston unit 3.....          1           0.800           0.413            48.4
4.                26               Gaston unit 4.....          1           0.800           0.413            48.4
5.                47               Colbert unit 1....          1           0.800           0.421            47.4
6.                47               Colbert unit 2....          1           0.670           0.421            37.2
7.                47               Colbert unit 3....          1           0.830           0.421            49.3
8.                47               Colbert unit 4....          1           0.860           0.421            51.0
9.                47               Colbert unit 5....          1           0.780           0.434            44.4
10.               641              Crist unit 6......          1           1.040           0.492            52.7
11.               641              Crist unit 7......          1           1.160           0.517            55.4
12.               856              Edwards unit 2....          2           1.000           0.514            48.6
13.               1043             Ratts unit 1SG1...          1           1.080           0.508            53.0
14.               1043             Ratts unit 2SG1...          1           1.090           0.468            57.1
15.               1295             Quindaro unit 2...          1           0.635           0.405            36.2
16.               1355             Brown unit 1......          1           1.000           0.495            50.5
17.               1357             Green River unit 5          1           0.836           0.400            52.2
18.               1381             Coleman unit 1....          1           1.410           0.489            65.3
19.               1381             Coleman unit 2....          1           1.290           0.466            63.9
20.               1384             Cooper unit 1.....          1           0.900           0.419            53.4
21.               1384             Cooper unit 2.....          1           0.900           0.419            53.4
22.               2049             Watson unit 4.....          1           1.100           0.413            62.5
23.               2049             Watson unit 5.....          1           1.220           0.431            64.7
24.               2629             Lovett unit 4.....          2           0.570           0.349            38.8
25.               2629             Lovett unit 5.....          2           0.585           0.329            43.8
26.               2840             Conesville unit 3.          1           0.852           0.412            51.6
27.               2843             Picway unit 9.....          1           0.866           0.415            52.1
28.               3131             Shawville unit 1..          1           0.990           0.486            50.9
29.               3131             Shawville unit 2..          1           1.020           0.483            52.6
30.               3159             Cromby unit 1.....          2           0.600           0.378            37.0
31.               3178             Armstrong unit 2..          1           1.042           0.420            59.7
32.               3948             Mitchell unit 1...          1           0.999           0.500            50.0
33.               3948             Mitchell unit 2...          1           0.999           0.500            50.0
34.               4042             Valley unit 1.....          1           1.100           0.477            56.6
35.               4042             Valley unit 2.....          1           1.100           0.477            56.6
36.               4042             Valley unit 3.....          1           1.050           0.473            55.0
37.               4042             Valley unit 4.....          1           0.925           0.473            48.9
38.               6041             Spurlock unit 1...          1           0.900           0.414            54.0
39.               6085             RM Schahfer unit            2           0.420           0.228            45.7
                                    15.                                                                         
----------------------------------------------------------------------------------------------------------------


[[Page 67124]]


                                          Table 5.--Tangentially Fired Boilers in the LNB Application Database                                          
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                           Uncontrolled    Load weighted                
                                                                                                             NOX rate          post-                    
                                                                                                         ----------------  optimization     Percent NOX 
        Obs. No.                   ORISPL                       Unit name/unit ID                Phase                       NOX rate         removal   
                                                                                                            (ln/mmBtu)   ----------------               
                                                                                                                            (ln/mmBtu)                  
--------------------------------------------------------------------------------------------------------------------------------------------------------
1.                        710                       McDonough unit 1.........................          1           0.657           0.388            40.9
2.                        710                       McDonough unit 2.........................          1           0.600           0.388            35.3
3.                        728                       Yates unit Y4BR..........................          1           0.561           0.421            25.0
4.                        728                       Yates unit Y5BR..........................          1           0.650           0.421            35.2
5.                        1374                      Elmer Smith unit 2.......................          1           0.859           0.419            51.2
6.                        1710                      Campbell unit 1..........................          1           0.690           0.456            33.9
7.                        2554                      Dunkirk unit 1...........................          2           0.478           0.343            28.2
8.                        2554                      Dunkirk unit 2...........................          2           0.478           0.331            30.8
9.                        2642                      Rochester 7 unit 4.......................          2           0.587           0.365            37.8
10.                       2732                      Riverbend unit 7.........................          2           0.580           0.421            27.4
11.                       2732                      Riverbend unit 8.........................          2           0.640           0.383            40.2
12.                       2732                      Riverbend unit 10........................          2           0.772           0.357            53.8
13.                       4041                      S. Oak Creek unit 7......................          1           0.661           0.377            43.0
14.                       4041                      S. Oak Creek unit 8......................          1           0.665           0.377            43.3
--------------------------------------------------------------------------------------------------------------------------------------------------------

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

i. Background

    Because the Acid Rain Phase I NOX Emission Reduction Program 
did not go into effect until January 1, 1996, EPA did not have, at the 
time the proposed rule was issued, CEM data on the performance of LNBs 
applied to Group 1 boilers during a period when affected boilers were 
required to meet the annual Phase I NOX emission limitations. 
Further, for the reasons discussed below, it could not be assumed that 
all the CEM data available, some of which had been recorded as early as 
January 1, 1994, reflected LNB performance during optimized NOX 
removal conditions.
    As discussed in the Regulatory Impact Analysis (RIA) for the 
proposed rule (see docket item II-F-2), plants incur both fixed and 
variable operation and maintenance (O & M) costs when operating LNBs to 
reduce NOX emissions to the lowest practicable level consistent 
with prudent boiler operations to comply with regulatory emission 
limitations. Therefore, even though LNB controls are installed, 
utilities have a financial incentive not to operate units throughout an 
extended period of pre-compliance to sustain the emission reductions 
the controls were designed to achieve, since this would increase O & M 
costs when the NOX emission reductions are not yet required. Thus, 
the average NOX emission rate measured over an extended pre-
compliance period may not be a good predictor of LNB performance under 
actual compliance conditions. On the other hand, it is reasonable to 
expect that utilities operated their newly installed NOX controls 
for some period of time following optimization of the equipment to 
simulate compliance conditions, perhaps as a dry run or for training 
purposes.
    EPA's objective, then, was to identify the time period in the 
stream of post-retrofit hourly CEM data that corresponds to operation 
under optimized NOX removal conditions. EPA believed this time 
period should contain 52 days of valid CEM data since, in publications 
and in past rulemakings, the Department of Energy (DOE) and the utility 
industry have stated that acceptable results of long-term performance 
require data sets of at least 51 days with each day containing at least 
18 valid hourly averages (see docket items II-I-99, Advanced 
Tangentially-Fired Combustion Techniques for the Reduction of Nitrogen 
Oxide (NOX) Emissions from Coal-Fired Boilers, and II-I-100, 
Demonstration of Advanced Wall-Fired Combustion Modifications for the 
Reduction of Nitrogen Oxide (NOX) Emissions from Coal-Fired 
Boilers). EPA defined a 52-day ``low NOX period'' for the purposes 
of assessing performance of LNBs applied to Group 1 boilers in the 
proposed rule. The ``low NOX period'' was determined by 
identifying the lowest average NOX emission rate each boiler has 
sustained for at least 52 days, i.e., over a period of 1,248 hours when 
the boiler was operating and valid CEM data (measured by CEMS certified 
pursuant to 40 CFR part 75) were available. The low NOX period for 
most boilers is considerably longer than 52 calendar days since hours 
during which the boiler did not operate or hours for which valid CEM 
data were not recorded are ignored and do not count

[[Page 67125]]

towards the required total of 1,248 hours.
    Even prior to the proposed rule, utility commenters and DOE had 
expressed the concern that by not using essentially all the recorded by 
post-retrofit CEM data, EPA was not accurately assessing the long-term 
performance capabilities of LNBs (61 FR 1442).\6\ Further, these 
commenters believed that using a fixed-length shakedown period of 30 to 
90 days, applied universally to all installations, to allow for 
optimizing LNBs and operator training was more objective than using the 
variable-length and site-specific shakedown periods implicit in EPA's 
low NOX period methodology. Accordingly, for the proposed rule, 
EPA also developed estimates of post-retrofit average NOX emission 
rates for another time period beginning 30 calendar days after the 
estimated date the boiler began operating after shutdown for LNB 
installation and continuing to the end of the CEM data set. This period 
is referred to as the ``overall post-retrofit period'' in the proposed 
rule (61 FR 1447 (Tables 4 and 5); also see docket item II-A-9, Table 2 
) and as the ``post-retrofit minus 30 days period'' (abbreviated as 
``30-day post-retrofit period'' in tabular column headings) in the 
technical support document for the final rule (see docket item IV-A-6).
---------------------------------------------------------------------------

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

    For the proposed rule, EPA developed estimates of post-retrofit 
average NOX emission rates for a third period which, like the 
overall post-retrofit period, uses most of the recorded post-retrofit 
CEM data and, like the low NOX period, allows for a variable-
length shakedown period to accommodate the site-specific nature of LNB 
equipment optimization and operator training processes. This time 
period begins with the first hour of the low NOX period and 
continues to the end of the CEM data set. It is referred to as the 
``post-optimization period'' in both the proposed rule and final rule 
analyses. As mentioned previously in section B of this preamble, the 
post-optimization period forms the basis for EPA's final assessment of 
the effectiveness of LNBs applied to Group 1 boilers.
    Another concern, which was raised prior to the proposed rule by 
utility commenters and DOE, is that limited time periods such as the 
low NOX period may not adequately capture annual dispatch patterns 
and seasonal variations in demand for electrical power generation. 
Accordingly, for the proposed rule, EPA also investigated the 
representativeness of load dispatch during the low NOX period by 
comparing it to the load dispatch during calendar year 1994 for each 
boiler or common stack in the LNB Application Database. EPA developed 
two histograms using ``load bins'' for the horizontal axis: (1) Average 
hourly NOX emission rate as a function of load during the low 
NOX period; and (2) frequency of various boiler operating loads 
throughout 1994 (for which EPA had actual performance data from the CEM 
data set ). Then, EPA used these histograms to estimate ``load-weighted 
annual average NOX emission rates'' based on weighted averages of 
the average emission rate during the low NOX period for each load 
bin times the number of hours the boiler operated in that load bin 
during 1994 (61 FR 1448 (Tables 6 and 7)). To test the 
representativeness of boiler operations during the low NOX period, 
EPA also created bar charts comparing the percentage of time a boiler 
operated in each load bin during the low NOX period to the 
percentage of time it operated in that load bin during calendar year 
1994 (see docket item II-A-9, Appendix B). Using these graphical 
analyses, EPA concluded that most boilers in the LNB Application 
Database had a load dispatch pattern during their low NOX period 
similar to their annual dispatch pattern in 1994.
    When analyzing long-term post-retrofit CEM data for the proposed 
rule, EPA found no strong correlation between boiler operating loads 
and hourly average NOX emission rates for either wall-fired 
boilers or tangentially fired boilers in the LNB Application Database. 
While earlier technical analyses performed for EPA in support of other 
utility NOX emission rulemakings had generally adopted the 
industry accepted presumption of a NOX vs. boiler load 
relationship for many uncontrolled Group 1 boilers, they also showed 
the direction, magnitude, and form of this correlation to be both 
highly boiler-specific and difficult to predict (see, for example, 
docket item IV-J-20).
    Nevertheless, EPA recognized that a predictable systematic 
correlation between hourly average NOX emission rates and boiler 
load for all or some boilers could have significant ramifications for 
proper application of a 52-day low NOX period methodology. 
Accordingly, EPA developed the ``load-weighted annual average NOX 
emission rates,'' defined above, to account for the potential existence 
of a NOX vs. boiler load relationship. Because the load-weighted 
annual average NOX emission rates were essentially the same as or 
lower than the average NOX emission rates for the low NOX 
period for these boilers (see 61 FR 1446 (Tables 5 and 6)) EPA selected 
the simpler form, a straight average over the low NOX period, as 
the basis for the proposed rule.
    The Agency received many detailed comments and supporting data 
about the appropriateness of using a limited low NOX period for 
assessing LNB performance, the merits of site-specific variable-length 
vs. universal fixed-length shakedown periods to reflect LNB equipment 
optimization and operator training, the advantages and disadvantages of 
the alternative time periods EPA had considered for the proposed rule 
analysis, and the technical issue of the existence of a NOX vs. 
load relationship and its relevance for assessing LNB performance 
applied to Group 1 boilers. The first three issues are discussed in the 
next section within the context of the low NOX period methodology 
whereas the last issue, for which EPA received approximately 25 site-
specific data submissions from utility boiler owners or operators, is 
treated separately in the subsequent section.

ii. Use of 52-Day Low NOX Period

    Comment/Analyses: EPA received approximately 29 comment letters 
(from 22 utilities, 2 utility associations, 3 states, a gas industry 
representative, and an environmental association) on the 
appropriateness of using a 52-day low NOX period for assessing LNB 
performance when, for some boilers, considerably more post-retrofit 
data was available.
    Some commenters fully endorsed EPA's 52-day methodology and 
implicit assumption that utilities not under a compliance obligation 
are unlikely to operate the controls for maximum emission reductions 
following LNB optimization and a low NOX test period. They 
believed EPA had demonstrated that the 52-day methodology and ``load-
weighted annual average NOX emission rates'' adequately addressed 
annual dispatch and load patterns in most cases. A utility that owns 
and operates coal-fired units which have become subject to state-
mandated NOX Reasonably Available Control Technology (RACT) 
requirements in 1995 said EPA should go even further and ``use NOX 
data only from units that have had to comply with a recent NOX 
standard (such as NOX RACT)'' for

[[Page 67126]]

evaluating the effectiveness of LNB technology (see docket item IV-G-
14, p. 1). EPA notes that 6 wall-fired boilers and 3 tangentially fired 
boilers in the LNB Application Database are located in the Northeast 
Ozone Transport Region and are subject to NOX RACT requirements. 
The mean load-weighted annual average NOX emission rates over the 
post-optimization period for these boilers are: 0.403 lb/mmBtu (wall-
fired) and 0.344 lb/mmBtu (tangentially fired).
    One commenter noted that utilities had an explicit disincentive for 
operating their LNBs to achieve the maximum practicable emission 
reductions during 1994 and 1995, since section 407(b)(2) allows EPA to 
promulgate revisions to Group 1 emission standards if measured average 
post-retrofit NOX emission rates during this time frame indicate 
``more effective low NOX burner technology is available'' (see 
docket item IV-D-63, p.14). Another commenter endorsed the conclusion 
that observations during the 52-day low NOX period may understate 
the actual reduction capability of LNBs (see docket items IV-D-047, p. 
2 and IV-D-063, p. 12-14).
    Other commenters disagreed with the assumption that utilities did 
not have any incentive to operate the installed LNBs to achieve maximum 
emission reductions consistent with prudent boiler operations. One 
utility stated that plant personnel ``operated [their] NOX control 
systems in a compliance mode even though its units were technically not 
yet subject to the Phase I NOX standard. [The utility] established 
performance goals based on operating NOX reductions systems to 
meet the standard and management bonuses were geared to meeting these 
goals'' (see docket item IV-D-020, p. 6). EPA notes that all of this 
utility's wall-fired units sustained average NOX emission rates 
below 0.44 lb/mmBtu throughout their ``post-optimization'' periods 
(i.e., the post-retrofit period excluding a shakedown period based on 
actual boiler experience). The post-optimization periods for these 
units varied in length from 12 to 18 months. Another utility stated 
that boilers were operated in a manner to optimize NOX emission 
reduction; to do otherwise would be ``counterproductive to the design 
of the burners and would defeat the training of the operating staff'' 
(see docket item lV-D-023, p. 4). EPA notes that the units owned and 
operated by both of these utility commenters are located outside 
designated ozone nonattainment areas and are not subject to NOX 
RACT or any other state-mandated NOX control requirements. Their 
decision to operate in a low-NOX mode, therefore, was voluntary 
and not made on the basis of whether a compliance obligation existed.
    Several commenters indicated that the best approach for estimating 
annual average NOX emission rates is to use a full year of post-
retrofit monitoring data (see, for example, docket item IV-D-38, p. 3). 
Commenters reiterated the concern raised prior to the proposal rule, 
that by not using essentially all the recorded post-retrofit CEM data, 
EPA is not accurately assessing the long-term performance capabilities 
of LNBs (see, for example, docket items IV-D-35, p. 3; IV-G-15, pp. 2-
3). They said EPA's 52-day low NOX period methodology fails to 
take into account all of the operating variables that affect LNB 
performance and biases the LNB performance assessment toward emission 
reduction levels that may not be achievable over the long term. 
Further, commenters who participated in DOE Clean Coal Technology 
Demonstrations where the 52-day methodology was used, said the ``52-day 
rule'' defines ``the minimum number of continuous days of data needed 
before a data set can be considered `long-term' data. It is not a rule 
that justifies selective editing of data, when more data are 
available'' (see docket item II-D-65, p. 29).
    Some of these commenters suggested using all CEM data recorded 
after a fixed-length shakedown period whereas others believed a 
variable-length shakedown period is more appropriate given the site-
specific nature of the LNB equipment optimization and operator training 
processes. EPA notes that one utility commenter reported that burner 
optimization for each of their five tangentially fired retrofits was 
completed within 120 days of startup (see docket item IV-D-23, p.4), 
which is considerably longer than the fixed 30-day shakedown period 
recommended by DOE and others. Another utility commenter reported that 
one of their wall-fired boilers, E.D. Edwards 2, was still being 
optimized more than a year after the retrofit date (see docket item IV-
D-73, p. 3).
    Several commenters indicated support for the post-optimization 
period approach, which EPA had presented in the proposed rule together 
with the 52-day low NOX period methodology and load-weighted 
annual average NOX emission rates. As one utility said, `the post-
optimization period' emission results are the best data set 
characterizing long-term low-NOX mode boiler operation. This 
database maximizes the amount of low-NOX mode data (i.e., sample 
size) collected following a period of demonstrated minimum NOX 
operation.'' (See docket item IV-D-051, p. 8.)
    Some commenters indicated a 52-day low NOX period methodology 
would be credible for assessing the long-term performance of LNB 
technology if NOX emission rates following LNB optimization do not 
vary significantly with boiler load (see, for example, docket item IV-
D-72, p. 4). While these commenters generally believe NOX emission 
rates are a function of load for many boilers (see discussion below 
under NOX vs. Boiler Load Relationship), they do endorse the 
concept of using less than essentially all the recorded post-retrofit 
CEM data for assessing LNB performance.
    Response: EPA believes that the 52-day low NOX period 
methodology is technically justified for evaluating the achievable 
NOX reduction capability of LNBs. This time period is sufficiently 
long, in most instances, to reflect long-term operation as evidenced by 
the generally similar load dispatch patterns observed during the low 
NOX period and for calendar year 1994 for most boilers in the LNB 
Application Database. However, assuring proper selection of a low 
NOX period that is representative of long-term boiler operating 
conditions in all instances can be difficult. An example of this is 
E.D. Edwards 2 where, according to the utility, the 52-day low NOX 
period EPA had selected for the proposed rule analysis was atypical 
because it represents ``a period of testing in a low NOX mode when 
the boiler was not optimized.'' Shortly thereafter, the utility re-
tuned the boiler for improved efficiency, to reduce loss on ignition 
(LOI), and to maintain full compliance with particulate and opacity 
emissions standards. (See docket item IV-D-073, pp. 3-4.) Another 
commenter suggested possible adverse plant impacts may have occurred 
during the low NOX period for a few other boilers in the LNB 
Application Database (see docket item IV-D-65, Enclosures 7 and 14); 
EPA's analysis of the specific impacts and remedial actions cited 
indicates that these possible issues are adequately addressed by 
extending the low NOX period into the longer post-optimization 
period. Therefore, to maximize the likelihood that the performance 
evaluation period is representative and to assure observations over the 
broadest possible range of boiler operating variables and electric 
power generation demand scenarios, EPA is using the longer post-
optimization period as the basis for assessing the performance of LNBs 
applied to Group 1 boilers for the final rule.

[[Page 67127]]

    EPA's decision to use the post-optimization period is also based, 
in part, on the comments utilities have submitted regarding their 
actions to operate installed LNBs in a compliance mode during 1995, 
prior to the effective date of the Acid Rain Phase I NOX Emission 
Reduction Program. EPA believes that there were reasons for utilities 
to operate installed LNBs as if the emission standards were in effect, 
even though such operation could increase utility O & M costs. EPA has 
rejected the concept of using a ``post-retrofit minus 30 (or 60 or 90) 
days period'' approach because utilities submitted significant evidence 
documenting that the time required for LNB optimization is highly 
variable and can be much longer than any of the fixed shakedown periods 
under consideration (see, for example, docket items IV-D-023, IV-D-073, 
and IV-G-04). Nonetheless, for comparison purposes, EPA has computed 
average NOX emission rates based on the post-retrofit minus 30 
days period for boilers in the LNB Application Database (see docket 
item IV-A-6, Table 3-1).
    The addition of four more quarters of CEM data to the LNB 
Application Database substantially lengthens the post-optimization 
period for most boilers.7 The post-optimization period also 
includes six months of 1996 compliance data for each Phase I boiler in 
the database. Table 6 presents summary statistics on the amount of 
hourly CEM data and calendar months encompassed by the post-
optimization periods.
---------------------------------------------------------------------------

    \7\ A notable exception is the post-optimization time period for 
E.D. Edwards 2, which has been lengthened by a lesser amount. In 
response to the utility's comments, EPA has selected another low 
NOX period, beginning after October 1, 1995, the date on which 
EPA believes corrections for adverse opacity and particulate 
emissions were substantially complete.

   Table 6.--LNB Application Database: Hours of CEM Data and Calendar   
                   Months in Post-Optimization Periods                  
------------------------------------------------------------------------
                                                Hours of CEM    Calendar
                 Boiler types                       data         months 
------------------------------------------------------------------------
Wall-fired boilers: 85% have at least 11                                
 months of CEM data in post-optimization                                
 period:                                                                
    Range....................................    3,877-15,829       6-30
    Average..................................           9,547         16
    Total....................................         372,324        610
Tangentially fired boilers: 79% have at least                           
 11 months of CEM data in post-optimization                             
 period:                                                                
    Range....................................    1,280-12,327       4-18
    Average..................................           7,537         14
      Total..................................         105,523        190
------------------------------------------------------------------------

iii. NOX vs. Boiler Load Relationship

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

[[Page 67128]]

existed at uncontrolled boilers and, in many instances, virtually 
eliminates any long-term relationship. A NOX vs. load relationship 
appears to have persisted for none of the tangentially fired boilers 
and for only a few of the wall-fired boilers (Colbert 5, E.D. Edwards 
2, Quindaro 2, and Jack Watson 5) in the LNB Application Database (see 
docket item IV-A-6, pp. 4-2 through 4-7). However, despite these 
findings, in response to commenters' insistence that a definite 
functional relationship exists between NOX and boiler load, EPA 
has employed a NOX/load weighting scheme in establishing NOX 
emission limits in this final rule. This load-weighting method 
incorporates at least two distinct improvements over the method used 
for the proposed rule analysis. First, following commenters' 
recommendation, the load weighting method employs ten load bins 
consistent with the convention specified in 40 CFR part 75, rather than 
the 25-MW increments used in the proposal. Second, the method uses 
post-retrofit CEM data over the longer post-optimization period, rather 
than the 52-day low NOX period, to estimate mean hourly NOX 
emission rates for each load bin, thus making it unnecessary to combine 
load bins due to sparse data. (Commenters had also said the combining 
of load bins with little or no data tended to mask the NOX/load 
relationship. See docket item, IV-D-65, p. 35.) The load weighting 
method uses hourly boiler or common stack load as reported in the CEM 
data set for 1995 to establish the frequency of operation in different 
load bins over a year. EPA has rigorously investigated the relationship 
of individual load patterns of boilers sharing a common stack to the 
combined load patterns over a year and, thus, to the annual average 
NOX emissions for the common stack (see discussion of common stack 
issues in section III.A.3.v of this preamble). Finally, EPA has 
compared, where data are available, boiler or common stack load 
patterns for 1994 and 1995 to assess inter-year variations in dispatch 
and demand for electrical power generation (see docket item IV-A-6).
    This improved load weighting scheme accounts for any potential 
impact that annual load dispatch patterns may have on NOX 
emissions. Its use should allay concerns raised by commenters on how 
the presence of a NOX/load relationship might impede accurate 
assessment of long-term LNB performance. In addition, EPA's specific 
responses to the main NOX/load issues are presented below:
    Lack of statistical measures to quantify the extent of the 
NOX/load relationship: Even among those commenters who most 
strongly assert the presence of a NOX/load correlation, there is 
little consistency from boiler to boiler in either the functional form 
or the direction of the NOX/load relationship. For example, of the 
three commenters submitting regression equations as evidence of a 
NOX/load relationship, one was based on a cubic model (see docket 
item IV-D-20, Figure 3), another was based on a logarithmic model (see 
docket item IV-G-14, p. 3), and a third was based on a quadratic model 
(see docket item IV-G-16). A fourth commenter, represented the 
NOX/load relationship from one-third to full load for eight 
boilers as straight line plots with slopes varying from approximately 
15 deg. to 45 deg. (see docket item IV-D-72, Attachment 1). Although no 
supporting documentation was provided explaining how these plots were 
derived, they would imply a linear model was appropriate. The situation 
is further complicated when a NOX/load relationship is discernible 
over only a portion of the load range. This is particularly an issue 
for wall-fired boilers retrofit with LNBs. EPA's plots of data from 
post-retrofit wall-fired boilers show that if a NOX/load 
relationship is discernible at all, it occurs almost entirely in the 
upper 10-20% of the boiler load range.
    The absence of a consistent functional form for the NOX/load 
relationship and a failure to persist across the full load range makes 
application of a statistical measure to quantify the extent of the 
NOX/load correlation difficult. Nonetheless, assuming a linear 
relationship between NOX and boiler load, EPA estimated the 
strength of correlation as indexed by R2 during post-retrofit 
period for 30 wall-fired and 11 tangentially fired boilers or common 
stacks in the LNB Application Database and, during the pre-retrofit 
period, for 13 wall-fired and 6 tangentially fired boilers or common 
stacks (see docket item IV-A-6, Cadmus Group 1 technical report, Table 
4-1). The R2 statistic measures the fraction of the variability in 
the dependent variable, hourly average NOX emission rate, 
explained by the model. EPA chose an R2 of 40% as a threshold for 
detection of the possible existence of a predictable correlation. For 
the post-retrofit hourly average NOX emission rate measurements, 
only 13% of the wall-fired and none of the tangentially fired boilers 
or common stacks had an R2 of 40% or higher (suggesting no 
predictable correlation). EPA compared the load dispatch pattern during 
the post-optimization period for each boiler or common stack crossing 
the R2 threshold to its annual dispatch pattern in 1995 and 
concluded the patterns were similar enough that the improved load-
weighting methodology would mitigate the effects of any NOX/load 
correlation on estimated controlled annual average emission rates.
    Inconsistency with earlier EPA studies: Earlier technical analyses 
performed for EPA in conjunction with other utility NOX emission 
rulemakings generally adopted the industry accepted presumption of a 
NOX vs. boiler load relationship. However, this was almost 
exclusively for uncontrolled Group 1 boilers, not boilers retrofit with 
LNBs. Prior studies also showed the direction, magnitude, and form of 
this correlation to be both highly boiler-specific and difficult to 
predict. (See, for example, docket item IV-J-20). Thus, for example, in 
these earlier studies, some uncontrolled tangentially fired boilers 
exhibit increasing NOX emission rates with decreasing boiler 
loads, others show precisely the reverse correlation, and still others 
have U-shaped curves. Uncontrolled wall-fired boilers typically exhibit 
increasing NOX emission rates with increasing boiler loads. 
However, this relationship was not found to be universally valid 
either, and the strength of the correlation, when present, varies 
considerably from one boiler to another.
    For this final rule, EPA's analysis is more exhaustive than these 
earlier studies. It encompassed more boilers, longer data streams, and 
better quality data. Separate graphs were generated for every boiler or 
common stack in the LNB Application Database, plotting NOX hourly 
emission rates as a function of hourly load, using long-term quality 
assured CEM data. To allow comparison of uncontrolled and controlled 
emissions, wherever available, pre- and post-retrofit hourly data were 
plotted on the same graph, differentiated by distinct symbols.
    A comparison of the pre-retrofit and post-retrofit plots shows 
that, with one exception, for both wall-fired boilers and tangentially 
fired boilers, if any NOX vs. load relationship existed for 
uncontrolled emissions, the installation of LNBs both reduced the 
magnitude and shortened the effective range of that relationship.
    As discussed above, EPA also developed a statistical measure 
(R2) of the strength of the correlation between NOX and 
boiler load, assuming a linear relationship. This statistical analysis 
corroborates the visual assessment of the data plots. For the post-
retrofit hourly average NOX emission rate measurements, only 13% 
of the wall-

[[Page 67129]]

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

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

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

[[Page 67130]]

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

i. Background

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

[[Page 67131]]

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

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

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

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

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

[[Page 67132]]

retrofit emission rate values.\11\ This database was used to perform 
sensitivity tests on the effect of using long-term vs. short-term 
measurements of uncontrolled emission rate on the projections of the 
number of Phase II, Group 1 boilers that could comply with various 
performance standards. For these tests, EPA used the long-term, instead 
of short-term, measurements for uncontrolled emission rate in Step 1 
(Model Building) wherever such pre-retrofit data were available (18 out 
of 53 boilers). The R2 values for the resulting regression models 
based on load-weighted annual average emission rates over the post-
optimization period were 65.3% (wall-fired boilers) and 78.9% 
(tangentially fired boilers), indicating acceptable fit (see docket 
item IV-A-6, Tables 4-6a and 4-6b). Applying these models to the Phase 
II, Group 1 data set of uncontrolled emission rates produced the 
results shown in docket item IV-A-6, Tables 4-7a and 4-7b. Within the 
primary range of interest (i.e., from 80th to 90th percentiles), the 
percentage of boilers estimated to achieve a specified emission limit 
using the long-term data typically varies by less than 2% (and not more 
than 5%) from the percentage derived using strictly short-term data. 
Both positive and negative differences occur, depending on the exact 
percentile and type of boiler, suggesting the emission limit could be 
lowered in some instances and raised in others. EPA concludes that 
using short-term measurements of uncontrolled emission rate has not 
systematically nor significantly lowered the resulting estimates of 
controlled emission rates achievable by Phase II, Group 1 boilers 
retrofit with LNBs.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

[[Page 67133]]

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

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

iv. Technical Assumptions Used in Group 1 Regression Model

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

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

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

[[Page 67134]]

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

    \16\ The two-step version of Model #2 fits a first-order linear 
model p=0=1U+ data, where U is 
the regressor variable ``uncontrolled emissions'' and P is the 
response variable ``percent reduction.'' Then, in step 2, C, the 
controlled emission rate, is calculated from P using the equation 
C=U(1-P/100). However, Model #2 (two step) can be reformulated as a 
one step second-order linear regression model, 
C='0+'1U+11U2+
'. Like Model #1 (one-step), Model #2 (one step) regresses C on U.
---------------------------------------------------------------------------

    Interestingly, EPA's calculations indicate that had the Agency 
adopted Model #1, as advocated by the commenter (a large association of 
utilities), the resulting achievable annual emission rates at the 90th, 
85th, and 80th percentiles, for both wall-fired boilers and 
tangentially fired boilers, would be approximately one-half to one 
percentage point lower (i.e., more stringent) than the achievable 
annual emission rates obtained using Model #2. (See docket item IV-A-6, 
Tables 4-10a and 4-10b). Thus, although EPA adopted Model #2 on 
strictly statistical grounds, it turns out that in the analysis for the 
final rule, Model #2 was more favorable than Model #1 to those 
commenters seeking less stringent emission limitations.
v. Common Stack Issues in Group 1 Analysis
    Background: In the proposed rule analysis, EPA found no strong 
correlation between boiler operating loads and post-retrofit hourly 
average controlled emission rates for single-stack boilers in the LNB 
Application Database and therefore, assumed that two boilers of the 
same type (i.e., wall-fired or tangentially fired) and NOX control 
status (i.e., both had LNBs only) sharing a common stack would have 
similar post-retrofit controlled emission rates. (EPA notes that some 
utilities also made this assumption when completing the Acid Rain Cost 
Form for NOX Control Costs for their Phase I LNB retrofits and 
provided ``sister unit'' estimates of emission rates in instances where 
multiple units were sharing a common stack.) In EPA's analysis, 
therefore, the rates from similarly situated individual units at a 
common stack were assumed to be the same, and single boiler and 
multiple boiler data were analyzed together (i.e., the common stack 
emission rate was assigned to each constituent unit).
    Comment/Analysis: EPA received approximately 4 comment letters 
(from 3 utilities and a utility association) on considerations for 
using common stack data when analyzing LNB performance applied to Group 
1 boilers. One commenter advised EPA to ``use caution when evaluating 
NOX data from combined stacks'' (see docket item IV-G-14, p. 1). 
Another commenter said EPA should ``either exclude common stack 
emissions data from its analysis, or revise its analysis based on data 
collected during periods when only a single unit [to a common stack] is 
operating'' (see docket item IV-D-65, p. 42).
    EPA notes that the decision on how to treat common stack data has 
important ramifications for both: (1) The amount of post-retrofit CEM 
data available for analysis; and (2) the number and representativeness 
of LNB retrofit cases in the LNB Application Database. Sixteen (16) of 
the 39 wall-fired boilers (41%) and 6 of the 14 tangentially fired 
boilers (43%) in the LNB Application Database exhaust to common stacks 
with similarly situated boilers also in the database; collectively, 
these boilers contribute 242,000 hours to the total of 477,800 hours of 
post-retrofit CEM data available through the second quarter of 1996 to 
support the final rule. Twenty-two (22) of the boilers sharing a common 
stack have post-optimization periods spanning 11 calendar months or 
longer. EPA does not consider the approach of excluding common stack 
emissions data, suggested by one commenter, a viable option because 
disregarding the substantial collective experience of these boilers 
would clearly reduce statistical confidence in the resulting assessment 
of LNB performance.
    Accordingly, EPA has sought other ways to address the commenters' 
criticism that EPA did not provide credible support in the proposed 
rule analysis for its treatment of common stack data. The specific 
concerns cited are: (1) Using the common stack post-retrofit NOX 
emission rate as the emission rate for each individual boiler sharing 
the common stack in the regression analyses; and (2) developing 
NOX/load curves for common stacks by summing the NOX 
emissions and loads from the boilers sharing the stack (see docket item 
IV-D-65, pp. 37-38).
    Response: EPA has performed extensive follow-up analysis on whether 
measured common stack emission rate data over the post-optimization 
period reflects the combined annual averages of individual boilers 
sharing the common stack. EPA compared the combined common stack 
emission rate to the individual-unit emission rates at every common 
stack in the LNB Application Database for which usable post-retrofit 
CEM data could be identified for periods when only a single unit was 
operating. In all, EPA studied 10 common stacks with 22 constituent 
boilers and over 19,800 hours of individual-unit emission rate data. 
The analysis included:
    (1) Box and whisker plots: The plots present side-by-side displays 
of the range of emission rates at common stacks when all units were 
operating compared to when only single units were operating: for each 
common stack, separate plots were generated using emission rates 
observed during the low NOX period and the post-optimization 
period. In both cases the plots show little difference between 
multiple-unit common stack emission rates and the individual unit 
emission rates over the averaging periods.
    (2) Percent Difference Calculations: Computing the percent 
difference between the multiple-unit and single-unit average emission 
rates for the post-optimization averaging period revealed that, on 
average, the percent difference for the wall-fired boilers was -0.3%, 
while for the tangentially fired boilers the percent difference was 
1.8%. (See docket item IV-A-6, Tables 4-8a and 4-8b.) This strongly 
indicates that, contrary to the belief of some commenters, there is not 
a significant disparity between the common stack and constituent unit 
NOX emission rates for the post-optimization averaging period.
    (3) Sensitivity Analysis: EPA performed a series of analyses to see 
how estimates of achievable annual emission limitations were affected 
by various treatments of common stack emissions. Three scenarios were 
investigated. In the first, the regression model was built using the 
constituent unit emission rates instead of the common stack emission 
rates. In the second, each common stack emission rate was used only 
once for each stack. In the third, the common stack emission rate was 
repeated for each unit. The third treatment is the same as that used by 
EPA in the proposed rule. The regression models fit the load-weighted 
data over the post-optimization averaging period approximately equally 
well, as measured by R2, for the various treatments of common 
stack emissions data. (The R2's ranged from 73.1-75.1% for the 
wall-fired boilers and from 62.8-72.1% for the tangentially fired 
boilers (see docket item IV-A-6, Tables 4-9a

[[Page 67135]]

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

[[Page 67136]]

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

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


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

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

[[Page 67137]]

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

B. Group 2 Boiler NOX Emission Limits

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

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

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

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

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

[[Page 67138]]

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

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

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

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

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

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

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

[[Page 67139]]

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

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

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

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

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

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

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

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

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

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

[[Page 67140]]

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

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

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

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

[[Page 67141]]

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

i. Appendix B Methodology

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

[[Page 67142]]

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

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

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

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


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

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

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

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

[[Page 67143]]

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

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

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

ii. EPA's Comparison Methodology

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

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

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

iii. Conclusions

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

[[Page 67144]]

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

[[Page 67145]]

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

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

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

[[Page 67146]]

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

i. Coal Reburning

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

[[Page 67147]]

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

ii. Selective Catalytic Reduction (SCR)

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

[[Page 67148]]

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

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

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

[[Page 67149]]

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

  Table 15.--Major Equipment List Merrimack SCR Anhydrous Ammonia-Based 
                           Boiler Size: 330 MW                          
------------------------------------------------------------------------
   No.            Item                      Description/size            
------------------------------------------------------------------------
1.......  SCR reactor.........  Vertical flow type, 1,615,350 acfm      
                                 capacity, equipped with a plate type   
                                 catalyst with 14,124 ft3 volume placed 
                                 in two layers, insulated casing with   
                                 two empty layers for future catalyst   
                                 addition, sootblowers, hoppers, and    
                                 hoisting mechanism for catalyst        
                                 replacement.                           
3.......  Anhydrous ammonia     Horizontal tank, 250 psig pressure; 87.5-
           storage.              ton storage capacity.                  
2.......  Compressors.........  Rotary type, rated at 400 scfm and 10   
                                 psig pressure.                         
2.......  Electric vaporizer..  Horizontal vessel, 450 kW capacity.     
1.......  Mixing chamber......  Carbon steel vessel.                    
1 Lot...  Ammonia injection     Stainless steel construction.           
           grid.                                                        
1 Lot...  Ammonia supply        Piping for ammonia unloading and supply,
           piping.               carbon steel pipe: 4.0 in. diameter,   
                                 600 ft long, with valves, and fittings.
1 Lot...  Air ductwork........  Ductwork between air heater, mixing     
                                 chamber, and ammonia injection grid,   
                                 carbon steel, 400 ft long, with two    
                                 isolation butterfly dampers, and       
                                 expansion joints.                      
1 Lot...  Sootblowing steam     Steam supply piping for the reactor     
           piping.               sootblowers, consisting of 200 feet of 
                                 2'' diameter pipe with an on-off       
                                 control valve and drain and vent valved
                                 connections.                           
1 Lot...  Flue gas ductwork...  Ductwork modifications to install the   
                                 SCR reactors, consisting of insulated  
                                 duct, isolation damper, turning vanes, 
                                 and expansion joints.                  
1 Lot...  SCR bypass..........  Ductwork consisting of insulated duct,  
                                 12'x24' double-louver isolation damper 
                                 with air seal, and expansion joints.   
1 Lot...  Ash handling          Extension of the existing fly ash       
           modifications.        handling system modifications,         
                                 consisting of one slide gate valves,   
                                 one material handling valves, one      
                                 segregating valve, and ash conveyor    
                                 piping, 180 ft long with couplings.    
1 Lot...  Controls and          Stand-alone microprocessor based        
           instrumentation.      controls for the SCR system with       
                                 feedback from the plant controls for   
                                 the unit load, NOX emissions, etc.,    
                                 including NOX and ammonia analyzers,   
                                 air and ammonia flow monitoring        
                                 devices, and other miscellaneous       
                                 instrumentation.                       
1 Lot...  Electrical supply...  Wiring, raceway, and conduit to connect 
                                 the new equipment and controls to the  
                                 existing systems.                      
1 Lot...  Foundations.........  Foundations for the equipment and       
                                 ductwork/piping, as required.          
1 Lot...  Structural steel....  Steel for access to and support of the  
                                 SCR reactors and other equipment,      
                                 ductwork, and piping.                  
------------------------------------------------------------------------

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

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

[[Page 67150]]

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

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

iii. Gas Reburning

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

[[Page 67151]]

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

[[Page 67152]]

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

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

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

i. Cell Burners

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

ii. Cyclones

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

[[Page 67153]]

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

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

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

iii. Wet Bottom Boilers

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

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

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

iv. Vertically Fired Boilers

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

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

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

C. Compliance Issues

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

[[Page 67154]]

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

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

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

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

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

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

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

[[Page 67155]]

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

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

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

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

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

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

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

[[Page 67156]]

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

[[Page 67157]]

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

[[Page 67158]]

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

[[Page 67159]]

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

IV. Administrative Requirements

A. Docket

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

B. Executive Order 12866

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

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

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

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

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

[[Page 67160]]

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

C. Unfunded Mandates Act

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

[[Page 67161]]

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

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

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

D. Paperwork Reduction Act

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

E. Regulatory Flexibility Act

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

[[Page 67162]]

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

F. Submission to Congress and the General Accounting Office

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

G. Miscellaneous

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

List of Subjects in 40 CFR Part 76

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

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

PART 76--[AMENDED]

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

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

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


Sec. 76.2  Definitions.

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


Sec. 76.5  [Amended]

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


Sec. 76.6  NOX emission limitations for Group 2 boilers.

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

[[Page 67163]]

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


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

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


Sec. 76.10  [Amended]

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


Sec. 76.16  Alternative compliance.

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

[[Page 67164]]

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

Appendix B to Part 76 [Amended]

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