[[pp. 57455-57504]] Finding of Significant Contribution and Rulemaking for Certain

Note: EPA no longer updates this information, but it may be useful as a reference or resource.

[Federal Register: October 27, 1998 (Volume 63, Number 207)]
[Rules and Regulations]
[Page 57455-57504]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr27oc98-16]

[[pp. 57455-57504]] Finding of Significant Contribution and Rulemaking for Certain
States in the Ozone Transport Assessment Group Region for Purposes of
Reducing Regional Transport of Ozone

[[Continued from page 57454]]

[[Page 57455]]

Regional Office when making the submittals.
3. Final Rule
After taking into account the comments submitted in response to the
May 11, 1998 proposal, EPA today is promulgating emission inventory
reporting requirements for States subject to the NO_X SIP
call. The regulatory text appears in 40 CFR 51.122, and the main
emission reporting requirements are summarized in Table VI-1 below.

Table VI-1.--Summary of NO_X Reporting Requirements
------------------------------------------------------------------------
then, your State
If you own or operate and must report to EPA
the source's
------------------------------------------------------------------------
A point source.............. You are not subject Ozone season²
to regulations emissions.
relied on to
achieve the NO_X
reductions required
in this SIP call ¹.
1. triennially ³,5.
2. for 2007⁵.
A point source.............. You are subject to Ozone season
regulations relied emissions.
on to achieve the
NO_X reductions
required in this
SIP call ¹.
1. annually ⁴.
2. triennially ⁵.
3. for 2007 ⁵.
An area source.............. You are not subject Ozone season
to regulations emissions.
relied on to
achieve the NO_X
reductions required
in this SIP call ¹.
1. triennially.
2. for 2007.
An area source.............. You are subject to Ozone season
regulations relied emissions.
on to achieve the
NO_X reductions
required in this
SIP call ¹.
1. annually ⁶.
2. triennially.
3. for 2007.
A mobile source............. You are not subject Ozone season
to regulations emissions.
relied on to
achieve the NO_X
reductions required
in this SIP call ¹.
1. triennially.
2. for 2007.
A mobile source............. You are subject to Ozone season
regulations relied emissions.
on to achieve the
NO_X reductions
required in this
SIP call ¹.
1. annually ⁶.
2. triennially.
3. for 2007.
------------------------------------------------------------------------
¹The EPA considers the State to rely on regulations to achieve the NO_X
reductions required if those regulations require reductions beyond
those reflected in the base case 2007 inventory.
² Ozone season is May 1 through September 30.
³ Triennial reporting (which is every 3 years) starts with emissions
occurring in 2002.
⁴ Annual reporting starts with emissions occurring in 2003.
⁵ Triennial and 2007 reports for point sources contain additional data
elements not required in the annual reports.
⁶ The data elements in the annual report for area and mobile sources
satisfy the reporting requirements for these source categories for the
triennial and 2007 reports. However, the triennial reports start with
emissions occurring in the year 2002 and the annual reports start with
emissions occurring in the year 2003.

4. Data Elements to be Reported
In addition to reporting the NO_X emissions values shown
in Table VI-1, the State must report other critical data necessary to
generate and validate these values. This includes data used to identify
source categories such as site name, location and (source
classification code) SCC codes. It also includes data used to generate
the NO_X emissions values such as fuel heat content and
activity level. The specific data elements required for each source
category are further defined in 40 CFR 51.122.
5. 2007 Report
The EPA is requiring that States submit to EPA for the year 2007 a
special onetime statewide NO_X emissions inventory from all
NO_X sources (point, area, and mobile) within the State. The
data reporting requirements are identical to the reporting requirements
for the triennial inventories, and this reporting requirement is being
imposed to allow evaluation of whether the budget is met in 2007. This
one-time special inventory is necessary because the ordinary 3-year
reporting cycle does not fall in the year 2007.
States which must submit the 2007 inventory may project incremental
changes in emissions from 2007 to 2008 to allow the 2008 inventory
requirement to be more easily met and to reduce the burden on States
which must submit full NO_X inventories for consecutive
years, i.e., 2007 and 2008.
The EPA received comments saying that EPA should not require the
special report in 2007 due to increased resources required but rather
should adjust the schedule of the triennial reports so that a triennial
report year will fall on 2007. Alternatively, the EPA could eliminate
the 2008 triennial report. The EPA has considered these alternatives,
but believes that the schedule which was proposed is necessary to
maintain consistency with

[[Page 57456]]

other EPA reporting requirements and is not unnecessarily burdensome.
6. Ozone Season Reporting
The EPA is requiring that the States provide ozone-season (i.e.,
May 1 through September 30) inventories for the sources for which the
State reports annual, triennial and 2007 emissions. The ozone season
emissions may be calculated from annual data by prorating emissions
from the ozone season by utilization factors that must be reported and
that are further defined in 40 CFR 51.122. For the triennial and 2007
reports, ozone season emissions from all NO_X source
categories within the State, controlled or uncontrolled, must be
reported. The EPA is requiring that each State provide its ozone season
calculation method to EPA for approval.
7. Data Reporting Procedures
When submitting a formal NO_X budget emissions report and
associated data, the State should formally notify the appropriate EPA
Regional Office of its activities. States are required to report
emissions data in an electronic format to one of the locations given
below. Several options are available for data reporting. The State may
choose to continue reporting to the EPA Aerometric Information
Retrieval System (AIRS) using the AIRS facility subsystem (AFS) format
for point sources. (This option will continue for point sources for
some period of time after AIRS is reengineered (before 2002), at which
time this choice may be discontinued or modified.) A second option is
for the State to convert its emissions data into the Emission Inventory
Improvement Program/Electronic Data Interchange (EIIP/EDI) format. This
file can then be made available to any requestor, either using E-mail,
floppy disk, or value added network, or can be placed on a file
transfer protocol (FTP) site. As a third option, the State may submit
its emissions data in a proprietary format based on the EIIP data
model. For the last two options, the terms ``submitting'' and
``reporting'' data are defined as either providing the data in the
EIIP/EDI format or the EIIP based data model proprietary format to EPA,
Office of Air Quality Planning and Standards, Emission Factors and
Inventory Group, directly or notifying that group that the data are
available in the specified format and at a specific electronic location
(e.g., FTP site). A fourth option for annual reporting (not for third
year reports) is to have sources submit the data directly to EPA. This
option will be available to any source in a State that is both
participating in an approved trading program and that has agreed to
submit data in this format. The EPA will make both the raw data
submitted in this format and summary data available to any State that
chooses this option.
For the latest information on data reporting procedures, call the
EPA Info Chief help desk at (919) 541-5285 or e-mail to
info.chief@epamail.epa.gov.
8. Confidential Data
Emissions data being requested in today's action are not considered
confidential by the EPA (See 42 U.S.C. 7414). However, some States may
restrict the release of certain types of data, such as process
throughput data. Where Federal and State requirements are inconsistent,
the EPA Regional Office should be consulted for final reconciliation.

C. Timeline

The reporting requirements fit into the general time line
summarized below:
September 30, 1999--Deadline for SIP submissions in response to
this SIP call.

2002--The first triennial emissions inventory report must be submitted
for ozone season emissions for this year. States must collect emissions
inventory information for all NO_X sources in the State. This
report must be submitted by December 31, 2003 (i.e., 12 months after
the end of the calendar year for which the data are collected.)
May 1, 2003--The SIP measures required to achieve the NO_X
reductions must be implemented by this date.
2003--The first annual emissions inventory report must be submitted for
certain ozone season NO_X emissions for this year.
Specifically, States must collect emissions information regarding all
sources for which the State is relying on measures to meet its
NO_X budget (``SIP call sources''). This report is due
December 31, 2004.
2004--The second annual emissions inventory report must be submitted
for ozone season emissions from SIP call sources for this year. This
report is due December 31, 2005.
2005--The second triennial report must be submitted for ozone season
emissions from all NO_X sources for this year. The report is
due December 31, 2006.
2006--The third annual report must be submitted for ozone season
emissions from SIP call sources in the State for this year. This report
is due December 31, 2007.
2007--The special year 2007 emission inventory report for ozone season
emissions from all NO_X sources in the State must be
submitted for this year. This report is due December 31, 2008. The EPA
will assess whether States have met their budgets in the year 2007.
2008--The third triennial emissions inventory report must be submitted
for ozone season emissions for this year. This report is due December
31, 2009.

Annual and triennial reports must continue to be submitted in
future years beyond 2008 in order for the EPA to track compliance with
the budget or any revisions to the budget that may occur after 2007.

VII. NO_X Budget Trading Program

A. General Background

In the November 7, 1997 proposed rulemaking, EPA offered to develop
and administer a multi-state NO_X trading program to assist
States in the achievement of their budgets. Today's notice sets forth a
model program on which States may choose to base their SIP submittal.
The trading program employs a cap on total emissions in order to ensure
that emissions reductions under the transport rulemaking are achieved
and maintained, while providing the cost effectiveness of a market-
based system. States can voluntarily choose to participate in the
NO_X Budget Trading Program by adopting the final model rule,
which is a fully approvable control strategy for achieving over 90
percent of the emissions reductions required under the transport rulemaking.

B. NO_X Budget Trading Program Rulemaking Overview

Prior to publication of the proposed NO_X Budget Trading
Program, EPA held two public workshops to solicit comments and
suggestions from States and other stakeholders on a NO_X cap-
and-trade program. Over 150 people participated in each of the
workshops. To facilitate meaningful comments from these participants,
EPA developed papers on critical issues that were made available for
review prior to each workshop. These papers discussed major issues
relevant to developing a NO_X Budget Trading Rule, delineated
options and, in some cases, offered recommendations. The issues
associated with each working paper were presented at the workshops,
followed by open discussion periods allowing workshop participants to
comment and discuss each issue. Input from workshop participants was
extremely helpful in drafting the proposed NO_X Budget
Trading Program. In addition to

[[Page 57457]]

input gained from the workshop process, the NO_X Budget
Trading Program builds directly upon the Ozone Transport Commission's
NO_X Budget Program and recommendations from the OTAG's
Trading and Incentives Workgroup. On May 11, 1998, EPA published the
proposed NO_X Budget Trading Program as a part of the
supplemental notice for the proposed ozone transport rulemaking. The
final NO_X Budget Trading Rule published in today's notice
reflects changes that have been made in response to comments received
on the May 11, 1998 proposal.

C. General Design of NO_X Budget Trading Program

1. Appropriateness of Trading Program
The EPA proposed that a voluntary market-based program be
established as one possible means for a State to meet its
NO_X emissions reduction obligations under the NO_X
SIP call. The vast majority of commenters, including States, industry,
and environmental groups, supported a market approach over traditional
``command and control'' mechanisms to fulfill reduction requirements.
However, many commenters argued that the proposed State budgets, based
on the cost-effectiveness of an emission limit of 0.15 lb/mmBtu for
large combustion sources, are too stringent to provide sufficient
surplus allowances to support a market. These commenters argued that
cost and technological constraints would prevent regulated sources from
over-controlling, thus reducing the pool of allowances and the cost
savings EPA predicts would accompany trading. However, several other
commenters stated that the trading program was the most cost-effective
means to reduce emissions and would in fact generate sufficient
allowances for trading. These commenters noted that all but the highest
emitting coal-fired units can achieve this rate, and that many sources
are able to achieve emission limits significantly below 0.15 lb/mmBtu.
They also argued that, at least in the early years of the trading
program, the growth factors used to determine the budgets will lead to
a less stringent emission reduction requirement than 0.15 lb/mmBtu.
The EPA notes that nothing requires a State to impose a 0.15 lb/
mmBtu limit on its large combustion sources. The States will select in
their SIPs which sources to regulate and the type of regulation to
impose in order to achieve their NO_X budgets. The EPA
believes that trading for large combustion sources under a budget based
on 0.15 lb/mmBtu is a feasible, highly cost-effective means of meeting
a State's budget. The Agency believes that 0.15 lb/mmBtu can easily be
achieved by gas and oil-fired boilers. In fact, more than 50 percent of
gas and oil-fired boilers already operate at NO_X levels
below 0.15 lb/mmBtu and should therefore easily be able to generate
excess allowances if trading is allowed. The EPA recognizes that for
coal-fired boilers to operate at or below a 0.15 lb/mmBtu emission
limit, selective catalytic reduction (SCR) will generally be necessary.
Under a trading scenario, however, if one coal-fired boiler is able to
emit below 0.15 lb/mmBtu by installing SCR, it can provide excess
allowance to another coal-fired boiler and obviate the need for that
boiler to install SCR. (For further technical justification for the
feasibility of 0.15 lb/mmBtu, see Section III.B.2 of this preamble.) In
summary, EPA concludes that, should a State elect to control large
combustion sources with a budget based on an emission rate of 0.15 lb/
mmBtu, ample allowances would exist to sustain a market under the
NO_X Budget Trading Program.
Several of the commenters who did not support the trading program
proposed by EPA were generally wary of the use of market approaches for
environmental regulation, especially in the context of ozone attainment
strategies, citing concerns that emissions in existing nonattainment
areas may increase under such a program. The EPA, however, believes
that a trading program is an appropriate mechanism to achieve the
NO_X reductions required under the SIP call. The EPA proposed
the trading program in the SNPR based on recommendations from OTAG,
experience from the Ozone Transport Commission, and EPA's public
workshops held in November and December 1997. This trading program was
designed to mitigate transport of ozone and its precursors to
facilitate attainment and maintenance of the ozone NAAQS. Analyses in
conjunction with the SIP call show that implementation of a trading
program with a uniform control level results in no significant changes
in the location of emissions reductions than would result from a non-
trading scenario (``Supplemental Ozone Transport Rulemaking Regulatory
Analysis'', April 1998, page 2-19). The NO_X reductions
required by the SIP call will significantly lower background levels of
ozone and can be coupled with local measures to achieve further
NO_X reductions, as well as VOC reductions, where necessary
to reach attainment. States concerned with contribution by local
sources in the trading program are free to limit emissions from
particular sources by imposing source-specific emission limits where
deemed necessary.
2. Alternative Market Mechanisms
The SNPR proposed to establish a model cap-and-trade program for
certain large combustion sources. This proposed program employs a cap
on total emissions to ensure achievement and maintenance of the
emissions reductions required under the NO_X SIP call while
providing the flexibility and cost effectiveness of a market-based
system. Several commenters supported EPA's recommendation for a cap-
and-trade program. Several others complained that EPA's focus on a
capped trading program was inappropriate, citing OTAG's recognition
that NO_X market systems could also be implemented without an
emissions cap. As a result, these commenters felt that EPA could not
make a cap a prerequisite to approval of a State trading program. They
suggested that EPA recognize that a rate-based program can be part of a
viable SIP, perhaps by outlining parameters of an acceptable
alternative program or working with OTAG States to develop a rate-based
program that would better accommodate future growth. Another issue
raised by a few commenters was that the trading program would either
conflict with or would ignore existing local or State-based trading
programs.
The EPA first reiterates that the model program is voluntary (63 FR
25918). In providing a cap-and-trade program as a streamlined means by
which to comply with the NO_X SIP call, EPA does not preclude
implementation of other solutions. The purpose of the trading program
is to provide a compliance mechanism that capitalizes on a proven means
of cost effectively meeting a specific emissions budget that the Agency
will assist States in administering.
As OTAG concluded, the procedures for a cap-and-trade program have
already been developed and used successfully, whereas procedures for
other types of multi-state trading programs have not been developed and
implemented to the same degree. Therefore, EPA does not have the same
level of experience or established protocols to follow in the design
and administration of other types of trading programs. The OTAG did
encourage development of provisions to implement other types of trading
programs, and EPA recognizes that these alternative trading programs
may be appropriate in some circumstances.

[[Page 57458]]

However, EPA recommends a cap-and-trade program for purposes of the
NO_X SIP call because, by limiting total NO_X
emissions to the level determined to address the interstate transport
problem, a cap better ensures achievement and maintenance of the
environmental goal articulated in the NO_X SIP call. In
contrast, under a non-cap trading program, the addition of new sources
to the regulated sector or increased utilization of existing sources
could increase total emissions above the level determined to address
transport, even though a NO_X rate limit is met.
States, however, have the flexibility to respond as they see fit to
meet their emissions budgets established under the NO_X SIP
call. States are free to pursue other regulatory mechanisms or include
other types of trading programs in their SIPs, whether newly created or
already existing, on the condition that they meet EPA's SIP approval
criteria as delineated for the NO_X SIP call. These criteria
mandate that regulatory requirements for boilers, turbines and combined
cycle units that are greater than 250 mmBtu or that serve electrical
generators that are greater than 25 MWe be expressed in one of three
ways: (1) In terms of mass emissions; (2) in terms of emissions rates
that when multiplied by the affected sources' maximum operating
capacity would meet the tonnage component of the emissions budget for
these sources; or (3) an alternative approach for expressing regulatory
requirements, provided the State demonstrates, to EPA's satisfaction,
that its alternative provides equivalent or greater assurance than
options (1) or (2) that seasonal emissions budgets will be attained and
maintained. For further information regarding SIP approvability
criteria, see Section VI.A.2.b of this preamble.
3. State Adoption of Model Rule
In the SNPR, EPA proposed that States electing to participate in
the NO_X Budget Trading Program could either adopt the model
rule by reference or develop State regulations in accordance with the
model rule. The few commenters on this issue were primarily concerned
about lack of guidance by EPA in this area for State adoption of the
model rule and the potential for deviation from the model rule in the
State-adopted rules. This section clarifies EPA's intent in issuing a
model rule and distinguishes between sections of the model rule that
State rules must mirror, and those that States may choose to alter or
eliminate while maintaining a SIP that is approvable for purposes of
joining the NO_X Budget Trading Program.
a. Process for Adoption. One commenter suggested that rather than
adopting the NO_X Budget Trading Program, it should be
sufficient for each State to include a statement in its SIP declaring
that the State will participate in the Federal program, along with a
demonstration of the authority for the State to do so. This would leave
the details in the Federal rule and avoid differences that could arise
through each State adopting its own rule. However, EPA does not have
the statutory authority under title I to promulgate a Federal cap-and-
trade program to achieve a State's SIP call budget unless the State
fails to respond adequately to the SIP call. The EPA understands the
commenter's concern regarding differences among State rules to
implement the NO_X Budget Trading Program, and intends to
ensure consistency as explained in the following Section.
The EPA's intent in issuing a model rule for the NO_X
Budget Trading Program is to provide States with a model program that
serves as an approvable strategy for achieving more than 90 percent of
the required reductions under the NO_X SIP call. States
choosing to participate in the program will be responsible for adopting
State regulations to support the NO_X Budget Trading Program,
and submitting those rules as part of the SIP. As articulated in the
proposed rulemaking (63 FR 25920), there are two legal alternatives for
a State to use in joining the NO_X Budget Trading Program:
incorporate 40 CFR part 96 by reference into the State's regulations,
or adopt State regulations that mirror 40 CFR part 96 but for the
variations and omissions described below.
b. Model Rule Variations. The EPA would like to clarify the
variations and omissions from the model rule that are acceptable in a
State rule, to provide States flexibility while still ensuring the
environmental results and administrative feasibility of the program.
More specifically, EPA will clarify those variations that maintain a
State's eligibility for the streamlined SIP approval associated with
adoption of the model rule, those changes that will require more
extensive review by EPA prior to approval, and those changes that are
not acceptable for incorporation into the NO_X Budget Trading
Program.
In order for a SIP revision to be approved for State participation
in the NO_X Budget Trading Program, on a streamlined basis or
otherwise, the State rule should not deviate from the model rule except
in the areas of applicability, NO_X allowance allocation
methodology, and early reduction credit methodology (all of which are
described briefly in the following paragraphs and in more detail in
subsequent Sections of today's notice). Deviations from the model rule
regarding allocation methodologies and early reduction credit
methodologies as defined in this Section do not impact a State's
eligibility for streamlined approval of its SIP with respect to the
NO_X Budget Trading Program. However, some deviations
regarding applicability will require more extensive EPA review, as
explained below. Changes to program applicability may render a State's
rule ineligible for streamlined approval, though the rule would still
be eligible for approval after a more thorough EPA review.
State rules that deviate beyond the applicability, allocation, and
early reduction credit flexibility provided in the model rule would not
be approvable for inclusion in the NO_X Budget Trading
Program. SIPs incorporating a trading program that is not approved for
inclusion in the broader NO_X Budget Trading Program may
still be acceptable for purposes of achieving some or all of a State's
obligations under the NO_X SIP call, provided the SIP
criteria outlined in Section VI.A.2.b are met. However, only States
participating in the NO_X Budget Trading Program would be
included in EPA's tracking systems for NO_X emissions and
allowances used to administer the multi-state trading program.
For States participating in the NO_X Budget Trading
Program, applicability is one of the three main areas in which the
State may deviate from the model rule. State rules need to include an
applicability section that at least covers the core sources defined in
the model rule, but States may allow additional stationary sources to
participate in the trading program. These sources must be able to
monitor and report emissions in accordance with the model rule, and
identify an individual responsible for fulfilling program requirements
to be eligible for inclusion. States have three options to expand
applicability and one to limit it, as explained in the following
paragraphs.
States may choose to expand applicability either by: (1) Including
smaller sources in the core source categories, (2) including additional
source categories, or (3) providing individual sources the ability to
opt in. Expansion of applicability to smaller core sources will
maintain the State's eligibility for streamlined SIP approval with
regard to the NO_X Budget Trading Program. Including
additional source categories beyond the core sources (e.g., municipal
waste combustors), however, will require more careful review by EPA

[[Page 57459]]

in some cases to ensure that the trading program requirements can be
met, and therefore preclude streamlined SIP approval otherwise
associated with adoption of the model rule. Regarding individual source
opt-ins, States have the discretion to determine whether or not to
include this provision in their State rule. The opt-in provision is not
a prerequisite to approval of a SIP incorporating the NO_X
Budget Trading Program. However, if a State does choose to include
provisions for opt-in sources, these provisions must mirror those in
the model rule. Providing the provisions do so, the SIP remains
eligible for streamlined EPA approval.
States may also choose to limit applicability of the trading
program by allowing units with a low federally enforceable
NO_X emission limit (e.g. 25 tons per control period) to be
exempt from trading program requirements. A State may include this
exemption provision as it appears in the model rule to allow these
sources not to participate in the trading program, or a State may omit
the provision. Neither of these actions will interfere with streamlined
SIP approval by EPA, provided the exemption provisions mirror the model
rule if included in the State rule.
In terms of allocations, States must include an allocation section
in their rule, conform to the timing requirements for submission of
allocations to EPA that are described in this preamble, and allocate an
amount of allowances that does not exceed their State trading program
budget. However, States may allocate NO_X allowances to
NO_X budget sources according to whatever methodology they
choose. The EPA has included an optional allocation methodology in 40
CFR part 96, but States are free to allocate as they see fit within the
bounds specified above, and still receive streamlined SIP approval for
purposes of the NO_X Budget Trading Program.
Today's final rule also includes an optional methodology in
Sec. 96.55(c) that States may use for issuing early reduction credits
from the State compliance supplement pools. However, States may
distribute the State compliance supplement pool to sources as they wish
in accordance with the requirements set forth in 40 CFR 51.121(e)(3)
and still receive streamlined SIP approval for purposes of the
NO_X Budget Trading Program.
In summary, a State is eligible for streamlined approval of the
portion of their SIP incorporating the NO_X Budget Trading
Program if the State adopts all the provisions of the model rule (e.g.,
banking and monitoring provisions) with variations incorporated only in
the manner explained in this Section. Streamlined approval requires
that applicability extends only to the core sources, or to core sources
and smaller sources within the core source categories and that the opt-
in provision and the exemption option for sources with a low federally
permitted emission limit, if included, mirror those in the model rule.
Regarding allocations, eligibility for streamlined approval extends to
those State rules whose allocations do not exceed the State trading
program budget and are determined in accordance with the timing
requirements delineated in the model rule. A State rule is still
eligible for approval, but not streamlined approval, if the
applicability determination for the NO_X Budget Trading
Program extends beyond the core sources to additional source
categories, to allow for the additional review necessary to ensure such
an extension of applicability is administratively feasible and
environmentally sound. A State rule is also eligible for streamlined
approval if it includes methodologies for issuing credit from the State
compliance supplement pool in accordance with the provisions in 40 CFR
51.121(e)(3). Differences among States in these areas will provide
flexibility while not detracting from the operation or implementation
of the multi-state trading program. Therefore, variations as explained
in this section are acceptable to EPA with assurance that State rules
will be sufficiently consistent. In addition, joint implementation of
the program with EPA will ensure that once these consistent rules are
established, they will be implemented consistently as well.
Several commenters expressed concern that the lack of prohibitions
on State-imposed trading restrictions in conjunction with the model
rule would lead to variation between States and cripple the trading
program. The EPA agrees with commenters that additional restrictions
imposed on the trading program by individual States could increase
economic costs without providing significant environmental benefit.
Therefore, EPA does not believe that any restrictions on trading are
necessary, and does not foresee approving State rules that include
trading restrictions in SIPs incorporating the NO_X Budget
Trading Program. However, to address local air quality problems, a
State participating in the NO_X Budget Trading Program may
establish permit limitations for specific sources participating in the
trading program. The EPA considers such a limitation appropriate given
local air quality concerns and does not consider it a trading
restriction, and therefore the incorporation of such limitations will
not preclude streamlined SIP approval. These sources would still
participate in the NO_X Budget Trading Program and the
unconstrained market operating in the program, but could not use
allowances to exceed their permit limitation; the source would be held
to the permitted limit, regardless of how many allowances it holds for
the purposes of the trading program. This topic is discussed in more
detail in the next Section.
4. Unrestricted Trading Market
a. Geographic Issues. For the NO_X SIP call, EPA is
basing the State budgets on the uniform application of reasonable,
cost-effective NO_X control measures for each State
determined to contribute significantly to nonattainment in a downwind
State. The EPA's analyses show that the collective reductions across
the region will produce significant air quality benefits across the
region. The development of and justification for the State budgets
under the NO_X SIP call is described in Section III,
Determination of Budgets. Although the analyses in today's final action
demonstrate that the collective emissions for the NO_X SIP
call region significantly contribute to nonattainment, the location of
particular emissions does impact the effects that the emissions have on
other areas within the region. Emissions in some locations may cause
greater overall effects than emissions from other locations.
In the SNPR, EPA proposed a single trading program allowing all
emissions to be traded on a one-for-one basis without restrictions on
trading allowances within the SIP call region. The EPA also solicited
comment on whether the trading program should attempt to factor in
differential effects of NO_X emissions based on the location
of the emissions. Possible options for factoring in the differential
effects include defining exchange ratios for trades between areas based
on the differential effects of emissions between areas, establishing
subregions for trading, and/or prohibiting certain trades (63 FR 25902
at 25919).
The Agency received more than fifty comments on this issue from the
regulated community, States, and environmental organizations. A number
of commenters did support limiting trading by establishing smaller
subregions within the SIP call region or

[[Page 57460]]

establishing trading ratios based on the idea that there are
differential effects of NO_X emissions based on the location
of the emissions. However, none of these commenters included a complete
proposal with a justification or description for the appropriate
subregional boundaries or trading ratios. The majority of commenters on
this subject favored unrestricted trading within areas having a uniform
level of control. Most commenters supporting unrestricted trading
stated that restrictions would result in fewer cost-savings without
achieving any additional environmental benefit and would increase the
administrative burden of implementing the program. They expressed
concern that discounts or other adjustments or restrictions would
unnecessarily complicate the trading program, and therefore reduce its
effectiveness.
Consistent with the proposal, the final model rule is designed to
be a single jurisdiction trading program allowing all emissions to be
traded on a one-for-one basis, without restrictions or limitations on
trading allowances within the trading area. EPA has used the IPM to
evaluate the emissions and cost impacts of alternative regulatory
options under the SIP call for the electric power sector. These
analyses can be found in the RIA. The model has been used to show the
level and location of emissions if the SIP call were implemented under
a number of different alternatives including unrestricted trading and
command-and-control approaches. The results indicate that significant
shifts in the location of emissions reductions would not occur with
unrestricted trading compared to where the reductions would occur under
command-and-control and intrastate only trading scenarios. Based upon
the IPM results and EPA's air quality modeling, EPA has chosen a
region-wide trading program allowing all emissions to be traded on a
one-for-one basis without trading restrictions. EPA's analyses suggest
that the net effect of all the trades is that the net emissions will
not significantly shift within the region compared to a command-and-
control scenario. For this reason, EPA believes that the need for
trading subregions or trading ratios that differ from one-for-one are
unsubstantiated for the purposes of this SIP call and the
NO_X Budget Trading Program.
Although the location of net emissions is not expected to
significantly shift as a result of trading, it is possible that a State
may identify a specific location (e.g., major NO_X source
adjacent to or within an urban center) where NO_X reductions
would be particularly beneficial for ozone mitigation. For these
situations, a State may establish a specific permit limitation
restricting the amount of NO_X that may be emitted from the
source. The source would still be included in the trading program but
it would not be allowed to emit above the amount specified in the
permit limitation regardless of the number of NO_X allowances
it may hold. The source would be allowed to trade the allowances it is
unable to use. In this way, States will be able to tailor specific
attainment strategies within the framework of the NO_X Budget
Trading Program without restricting the trading options for most
sources included in the program.
b. Episodic Issues. The EPA also received several comments
addressing the episodic nature of ozone formation and whether this
should be factored into the design of the trading program. Commenters
noted that under the NO_X SIP call, which is designed to
reduce total NO_X emissions from May through September of
each year, it is still possible that NO_X emissions may be
relatively higher during ozone episodes compared with NO_X
emissions on other days between May and September. In addition, the
effect of a unit of emissions may be higher during ozone episodes. To
address this concern, the commenters stated that the trading program
should provide incentives or safeguards to ensure that NO_X
emissions reductions are achieved specifically during ozone episodes.
One commenter asserted that emissions could either be capped during
ozone episodes or that the trading program could place a premium on the
use of NO_X allowances during ozone episodes. The commenter
recommended the latter option. The premium would require that sources
surrender NO_X allowances at rates greater than 1-to-1 for
each ton of NO_X emitted during the ozone episodes.
Consistent with the NO_X SIP call, the NO_X
Budget Trading Program focuses on reducing total NO_X
emissions from May to September for the jurisdictions that are
identified in the NO_X SIP call and that choose to
participate in the trading program. Proposals to address NO_X
emissions during specific episodes and in specific nonattainment areas
are more closely tied to issues affecting individual attainment plans
rather than the goal of the NO_X SIP call which is to reduce
transport. It would be very difficult to apply the appropriate premium
to the individual sources that contribute NO_X emissions
affecting specific ozone episodes. The meteorology and source
contribution for each ozone episode is different. And in some cases,
NO_X emissions and the resulting ozone may be transported for
several days before contributing to an ozone violation.
Provisions designed to ensure that NO_X emissions
reductions are achieved specifically during ozone episodes are more
likely to be effective in controlling NO_X emissions that are
released adjacent to or within locations frequently affected with
elevated ozone levels. Where a State identifies such a source, EPA
believes specific permit limitations are an appropriate and effective
method for controlling the source's emissions. As stated in the
previous section, EPA believes that States may use permit limitations
to tailor specific attainment strategies within the framework of the
NO_X Budget Trading Program without restricting the trading
options for most sources included in the program. Furthermore, this
provides each State more flexibility in establishing its attainment
plan rather than applying one approach to address the episodic nature
of ozone throughout the SIP call region. Therefore, EPA has not
included additional trading restrictions to address ozone episodes in
the design of the final NO_X Budget Trading Program.

D. Applicability

1. Core Sources
In the SNPR, EPA proposed that compliance with the emission
limitation requirements of the NO_X Budget Trading Rule,
i.e., the requirement to hold sufficient NO_X allowances to
cover emissions, apply to a core group of large stationary sources that
includes all fossil fuel-fired stationary boilers, combustion turbines,
and combined cycle systems (i.e., units) that serve an electrical
generator of capacity greater than 25 MWe and to any fossil fuel-fired
stationary boilers, combustion turbines, and combined cycle systems not
serving a generator that have a heat input capacity greater than 250
mmBtu/hr. A unit was considered fossil fuel-fired if fossil fuels
accounted for more than 50 percent of the unit's heat input on an
annual basis. The EPA solicited comment on the appropriateness of the
categories included in the core group, whether the size cut-offs should
be higher or lower for the source categories, and the appropriateness
of including other source categories in the core group. Comments on the
concept of a core group fell into three broad categories:
. Those who agreed with the core group concept and who
generally agreed

[[Page 57461]]

with EPA's proposed core group definition;
. Those who felt that the core group definition was too
limiting; and
. Those who felt that the core group definition was too inclusive.
a. Commenters Who Felt the Core Group Should Not Be Changed.
Commenters who supported the concept of a core group generally and the
cut-offs proposed by EPA specifically explained that the cut-offs are
consistent with the Acid Rain Program and that the use of a core group
will minimize inconsistencies that could impede establishment of
interstate trading. Commenters also added that the program should
provide the flexibility to allow additional sources to opt-in on an
individual basis or for States to bring in additional sources on a
categorical basis. Some of these commenters added that the timing for
bringing in these sources or source categories should be dependent upon
the ability of the source or source category to accurately monitor
emissions. For some source categories it might be appropriate to bring
them in at the start of the program; for others, it might be necessary
to wait until their ability to quantify emissions has improved.
Commenters who generally supported the concept of a core group of
sources as it was defined in the SNPR did have several specific
concerns. One commenter noted that while the SNPR preamble clearly
explained that the rule only included fossil-fuel-fired units, the rule
itself was not clear on this issue. Another commenter suggested that
because the proposed definition differentiated between electrical
generating units and non-electrical generating units it excluded
sources that should be in the trading program such as cogeneration
facilities that consisted of boilers greater than 250 mmBtu/hr that
served electric generating units with a rating of less than 25 MWe.
The EPA agrees that the establishment of a core group will help
facilitate interstate trading as well as compliance with the emissions
budget. If there is not some minimum group of trading participants,
sources that are in the program will have less of an opportunity to
trade allowances and realize the economic benefits of trading. In
addition, by ensuring that most of the emissions from industries
covered by the trading program are included in a capped system, the
trading program can be simplified because concerns about load shifting
to uncapped sources is minimized. The EPA also agrees that making the
cut-offs consistent with existing regulatory programs helps to minimize
conflicts with existing regulatory programs. The EPA also agrees with
both of the concerns raised by the commenters. Therefore the regulatory
definition of unit has been clarified to make it clear that a unit must
be fossil-fuel fired. The EPA has also added a clarification to the
definition of fossil-fuel fired. This clarification is intended to
define a baseline period for determining if a unit is fossil-fuel
fired. The revised definition states that fossil-fuel fired means the
combustion of fossil fuel, alone or in combination with any other fuel,
where the fossil fuel comprises more than 50 percent of the annual heat
input on a Btu basis. An existing unit is considered fossil-fuel fired
if it meets this criterion for any year since 1990 (or if not operating
since 1990 during the last year of operation). A new unit is considered
fossil-fuel fired if it is projected to meet this criterion or, if
after operation begins, it does meet this criterion.
In addition, to address the concern about excluding cogeneration
facilities that are greater than 250 mmBtu/hr that serve electric
generating units with a rating of less than 25 MWe, the applicability
has been changed to include all units greater than 250 mmBtu/hr,
regardless of how much electricity they generate.
b. Commenters Who Felt the Core Group Should Be Expanded.
Commenters who felt the trading program should be expanded focused on a
number of areas. Several commenters argued generally that the program
should allow any source to participate if the source can document that
emissions reductions have been achieved. A number of commenters
mentioned as examples the inclusion of medium-sized and smaller
stationary sources in the RECLAIM program. A few commenters argued that
the addition of certain sources is needed for consistency with the OTC
NO_X Budget Rule. Other commenters opposed the core group
concept because they believe that regulation of low-level and local
sources in the Northeast is an essential step in solving the ozone
problem. Others argued that excluding non-utility sources from the
trading program unfairly excludes these sources from least-cost
compliance options. Some commenters suggested specific categories of
units that should be allowed to, but not required to, participate in
the trading program. These included:

(1) Municipal waste combustors;
(2) Internal combustion engines;
(3) Process units;
(4) Units for which the output product is not comparable to other
units on which the allocations are based, such as process heaters,
hazardous waste incinerators, process vents and nitric acid plants.

The EPA believes that many of the concerns about the core source
definition stem from a misunderstanding of its purpose. The core
sources definition was intended to indicate the minimum applicability
requirements that a State rule would have to include to participate in
a larger multi-state program that EPA would help to administer. It was
not intended to limit individual States from including more sources (as
long as the sources meet certain criteria further explained below) in
the larger multi-state program (63 FR 25924). Nor was it intended to
prohibit a State (or group of States) from developing its own trading
program with a more limited applicability.
If, however, a State or group of States developed a trading program
that did not meet the minimum requirements set forth in the model
NO^X Budget Trading Program, such as minimum core source
applicability, EPA would not participate in the administration of such
a trading program. This is because it would not be administratively
cost-efficient for EPA to manage multiple trading programs with a
variety of applicability and other requirements designed to address the
same issue.
The EPA is not expanding the core source group to include any
additional sources because EPA believes that this decision is better
left to the states. Therefore the model rule will allow a State to
expand the applicability of the trading program to include additional
stationary sources if the sources meet certain criteria. These criteria
include the ability to accurately and consistently monitor and report
emissions and the ability to identify a party responsible for ensuring
that monitoring and reporting requirements are met, for authorizing
allowance transfers and for ensuring compliance. The EPA's rationale
for setting these minimum criteria are set forth in the preamble to the
SNPR (63 FR 25923). Also, EPA addresses issues specifically related to
the monitoring requirements for these sources in Section D.3 of today's
preamble.
There are two mechanisms that can be used to include more sources
in the program. One is for a State to expand the applicability criteria
to include other source categories; the other is to give individual
sources the ability to opt-in.
States that choose to expand the applicability criteria can do so
(1) by lowering the applicability threshold for source categories that
are already part of

[[Page 57462]]

the core group in order to include smaller sources or (2) by including
additional source categories that are not included in the core group.
For instance a State in the OTC might choose to lower the applicability
cut-off for electrical generating units to 15 MWe to make the program
more consistent with the existing OTC NO_X Budget Program. If
a State chose to expand the applicability criteria for source
categories already included in the core group this would not affect
EPA's streamlined approval of the NO_X Budget Trading program
component of the State's SIP.
A State might choose to lower the applicability cut-off for sources
in the core group to create different applicability cut-offs for new
and existing units. This could help to better facilitate integration
with a State's new source review program. The EPA took comment on this
concept in the SNPR and received comments both for and against this
proposal. Commenters who opposed it suggested that it would be a
disincentive to replace old units with new cleaner units. Some of these
commenters also noted that expanding the applicability cut-off for all
units would provide an incentive to replace these older units.
Commenters who favored it suggested that it would be an incentive to
make new units as clean as possible. The EPA believes that it is
appropriate for States to determine how best to handle the issue of
small new units.
Another reason to allow smaller sources to opt-in is to simplify
monitoring for situations in which a common stack is shared by a number
of units, some of which are affected and some which are not. In this
situation the owner or operator would have to either install monitors
at each of the affected units, or install monitors at the common stack
and at all of the non-affected units, so that the emissions from these
units could be deducted from the emissions from the affected units. If
the owner or operator is allowed to opt-in the nonaffected unit, they
will be able to install one set of monitors at the common stack
accounting for the emissions from all of the units.
If a State chose to include additional source categories, EPA would
have to review the SIP submittal to ensure that those additional source
categories met the minimum criteria for monitoring and reporting
emissions and for having a responsible official. As further explained
in the SNPR (63 FR 25924), EPA would also have to determine if it could
successfully administer a regional trading program with the inclusion
of these additional source categories.
In the SNPR, EPA proposed developing a list of specific additional
source categories beyond the core group which a State could bring into
the trading program without affecting EPA's streamlined approval of the
trading component of the SIP. While this concept received general
support, none of the commenters provided enough specific support to
demonstrate that all of the sources in a given source category could
meet the criteria to accurately and consistently monitor emissions.
These comments are discussed in Section D.3.
The EPA believes that the opportunity for States to expand the
applicability to include additional sources addresses concerns about
incompatibility with the applicability requirements of existing
programs, such as the OTC Trading Program, as well as concerns that an
individual State might want to expand the program to address local
ozone problems.
The other mechanism that can be used to broaden the applicability
of the program is the individual opt-in procedures in subpart I of part
96. These provisions allow a source to opt-in, if it can meet the
monitoring and reporting requirements of part 75. The EPA received a
number of comments about the monitoring requirements of part 75 as they
related to opt-ins. These comments are addressed in Section D.3 of
today's preamble.
In the SNPR (62 FR 25940-25942 and 62 FR 25991-25994), EPA proposed
that the individual opt-in provisions would only be applicable to
fossil-fuel-fired, stationary boilers, combustion turbines, and
combined cycle systems smaller than the applicability cut-offs of 25
MWe or 250 mmBtu/hr. The EPA agrees that the RECLAIM program has
demonstrated that many combustion sources that are not included in the
core applicability criteria can accurately and consistently monitor
NO_X mass emissions using CEM (or other alternative protocols
for units with low mass emissions) that are very similar to the
provisions in subpart H of part 75. Therefore, in today's action EPA is
allowing States to expand the opt-in provisions to include any
stationary combustion source that emits to a stack and can meet the
monitoring and reporting requirements of subpart H of part 75.
States that choose to add other combustion sources that are not
part of the core group would also have to address issues related to
allocating allowances for those types of sources. Allocation
methodologies that may be appropriate for source categories covered in
the core group may not be as applicable for other source categories.
For instance, as one commenter noted, an output based allocation
methodology might not make as much sense for a municipal waste
combustor, since the primary purpose of a municipal waste combustor is
to combust waste, not to generate usable output.
c. Commenters Who Felt the Core Group Is Overly Inclusive. A number
of commenters argued that the burdens associated with including certain
source categories would outweigh the benefits and that particular types
of sources should therefore be excluded from the core group. Many of
these commenters stated that individual sources in these groups should
be allowed to opt in where there is a net economic benefit to them to
participate rather than mandating inclusion of the source category.
Specific categories include: non-utility boilers generally; generators
of power for on-site use; combustion turbines exempt from Title IV;
small cyclone boilers; combustion turbines below 100 MWe; small,
particularly municipal, electric generating units (e.g., those under 25
MWe); and units with low potential to emit as defined by enforceable
limits (e.g., peaking units with potential to emit less than 100 tons
per year).
The EPA does not believe there is a great distinction between
similarly sized utility and non-utility boilers. Both categories of
boilers are similar in design, have similar control options and have
similar control costs. Therefore, EPA is not excluding large non-
utility boilers from the trading program. The EPA believes the same
arguments that apply to utility and non-utility boilers also apply to
generators of power for on-site use and generators of power for resale.
In light of the fact that utility restructuring will provide more
opportunities for generators of power for on-site use to resell the
power they produce in the future, EPA believes that this distinction is
even harder to make. Therefore, EPA is not excluding large generators
of power for on-site use from the trading program.
In accordance with title IV of the CAA, the Acid Rain Program
exempts simple combustion turbines that commenced commercial operation
before November 15, 1990. These units were exempted from the Acid Rain
Program because the SO₂ emissions from these units were
extremely low. The NO_X emissions from these units are
potentially higher; therefore, EPA is not adding a specific exemption
for these types of units. However, many of these units are small and/or
infrequently operated, so their actual NO_X emissions may be
quite low; therefore, some of these units may qualify for the

[[Page 57463]]

alternative compliance options for units with low NO_X mass
emissions, explained below. Combustion turbines smaller than 100 MWe
are also likely candidates to qualify for the alternative compliance
option explained below.
The Acid Rain Program exempts cyclone boilers with a maximum
continuous steam flow at 100 percent load of greater than 1060 thousand
lb/hr from NO_X control requirements under part 76. These
units were exempted because one of the primary criteria in title IV of
the CAA for setting emissions limitations under part 76 was
comparability of cost with low NO_X emission controls on
boilers categorized as group 1 boilers under Title IV (large
tangentially fired and dry bottom, wall fired). There is no such
criterion in the CAA applicable to this rulemaking. Also, since the
emission reductions required by this rulemaking are more substantial
than the emission reductions required under part 76 ⁷⁰, the
cost per ton of reducing NO_X emission reductions is
correspondingly higher. Therefore, applicability cutoffs that were
relevant in the part 76 rulemaking are not relevant in this rulemaking.
---------------------------------------------------------------------------

\70\ The lowest emission rate required under part 76 is 0.40 lbs/mmBtu.
---------------------------------------------------------------------------

In response to the comment that small electrical generators less
than 25 MWe should be exempt from the NO_X Budget Trading
Program, they were proposed to be exempt and will be exempt under the
final model rule. They do still have the option of opting into the
program if they choose to do so.
In the SNPR (63 FR 25926), EPA took comment on allowing units with
a low federally enforceable NO_X emission limit (e.g. 25 tons
per ozone season), that because of their size would be included in the
trading program, to be exempt from the requirements of the trading
program. In general commenters supported this concept. One commenter
who supported the concept also added that it would be important to
ensure that there were adequate requirements to assure that the
individual sources who took advantage of this option demonstrated
compliance with their unit-specific caps. The commenters who disagreed
with this option expressed concern that a State's budget could be
exceeded if emissions from these units were not accounted for.
Based on the comments received EPA continues to believe that it is
appropriate to offer States the option of providing units that are
above the applicability threshold but that have a very low potential to
emit an alternative compliance option. This option would allow units
that meet the requirements described below to be exempt from the
requirements to hold allowances, and to comply with quarterly reporting
requirements. In order to address the concern that sources must
demonstrate compliance with their individual cap, EPA has added
specific requirements that sources must meet in order to use this
alternative compliance option.
Units that use this option would be required to:
(1) have a federally enforceable permit restricting ozone season
emissions to less than 25 tons;
(2) keep on site records demonstrating that the conditions of the
permit were met, including restrictions on operating time;
(3) report hours of operation during the ozone season to the
permitting authority on an annual basis.
A unit choosing to use this compliance option would be required to
determine the appropriate restrictions on its operating time by
dividing 25 tons by the unit's maximum potential hourly NO_X
mass emissions. The unit's maximum potential hourly NO_X mass
emissions would be determined by multiplying the highest default
emission rate for any fuel that the unit burned (using the default
emission rates, in part 75.19 of this chapter) by the maximum rated
hourly heat input of the unit (as defined in part 72 of this chapter).
States would be allowed, but not required, to incorporate this
alternative compliance option into their SIPs. The EPA does agree that
if a State does incorporate this option into the SIP, it would have to
account for the emissions under its budget. Thus a State that chose to
use this option would have to either:
(1) Subtract the total amount of potential emissions permitted to
be emitted using this approach from the trading portion of the budget
before the remaining portion of the trading budget is allocated to the
trading participants; or (2) Offset the difference between total amount
of potential emissions permitted to be emitted using this approach and
the 2007 base year inventory emissions for these same sources with
additional reductions outside of the trading portion of the budget.
If States choose not to incorporate this alternative compliance
option into their SIPs, or if they choose to incorporate it exactly as
it is set forth in the model rule, it will not affect the streamlined
approval of the trading rule portion of the SIP. A State may choose to
require an alternative means of ensuring that the potential to emit for
units utilizing the alternative means of compliance is limited to less
than 25 tons, however if a State deviates from the model rule in this
way, the SIP will no longer receive streamlined approval.
2. Mobile/Area Sources
The proposed rule did not include mobile or area sources in the
trading program, but solicited comment on expanding applicability to
include these sources, or to include credits generated by these
sources, in the trading program. Mobile and area sources were not
included in the proposed trading rule due to EPA's concerns related to
ensuring that reductions were real, developing and implementing
procedures for monitoring emissions, and identifying responsible
parties for the implementation of the program and associated emissions
reductions.
The EPA received comment from State and local government, industry
and coalitions of industry, and environmental groups regarding the
inclusion of mobile and area sources in the program. Comments focused
on the following main areas: inclusion or exclusion of mobile and area
sources, subcategories of mobile sources for inclusion, and the use of
pilot programs to foster innovation.
Some commenters urged EPA to include mobile and area sources with
as few restrictions as possible in the trading program, primarily on an
opt-in or voluntary basis. These commenters argued that excluding
mobile sources would reduce the potential scope and benefits of the
trading by placing a large portion of States' NO_X inventory
outside the scope of the trading program. They noted that the existence
of RECLAIM protocols for mobile and area source credit generation
demonstrated that EPA's quantification, verification, and
administration concerns were misplaced.
The majority of commenters, however, indicated that mobile sources
should not be included at this time and that the model rule should not
be delayed to address concerns related to inclusion of these sources.
Some commenters argued against ever including mobile and area sources
in the program. One State argued that inclusion of mobile and area
sources would destroy the integrity of the program since mobile and
area source reductions are not necessarily real, verifiable and
quantifiable, failing to display a level of certainty comparable to
those sources included in the trading program. A few commenters
indicated that mobile sources were inherently unsuited to a capped
system, since the difficulties of measuring emissions from these
sources precludes their inclusion in a budget.

[[Page 57464]]

Several commenters suggested that some categories of mobile sources
should be included while other categories should not. Commenters
indicated, for example, that it is not feasible to have individual
motorists participate in the cap-and-trade program due to the burdens
and administrative complexity associated with such a vast number of
sources and responsible parties in a trading system. Alternatively,
commenters argued that manufacturers, fuel distributors, and fleet
owners could be included if they were able to generate surplus emission
reductions by going beyond the requirements established by some Federal
measures. These commenters specifically cited the low-RVP regulations,
the vehicle scrappage guidance, and the locomotive regulations as
examples of such Federal measures.
Several commenters who recommended that mobile sources not be
included in the program at this time also recommended that EPA sponsor
pilot programs in States to study the feasibility of inter-sector
trading and to develop mechanisms to address the specific concerns
mentioned regarding the inclusion of mobile and area sources. Along
similar lines, one industry commenter stated that mobile sources may be
appropriate candidates for participation in the trading program only if
adequate emission reduction measurement protocols can be developed.
Foreseeing this occurrence, some commenters felt that EPA should leave
a placeholder in the rule or add a provision that would include mobile
and area sources once the mechanisms to address the specific concerns
of EPA and others have been developed.
The model trading program that EPA is finalizing today will not
include mobile and area sources for the reasons outlined in the SNPR.
The EPA concurs with the concerns raised by commenters against the
inclusion of mobile and area sources, regarding program integrity,
emissions monitoring, and accountability. Most of the proponents of
including mobile or area sources listed general reasons for including
them such as increasing market efficiency, lowering costs, or simply
the existence of RECLAIM protocols to do so. However, these commenters
did not provide sufficient information or documentation to support the
validity of these assertions, and several acknowledged that the
potential for improvement in market efficiency or lower compliance
costs was difficult to ascertain. Further, one proponent acknowledged
that the RECLAIM protocols are new and not yet extensively utilized.
In fact, a recent audit of the RECLAIM program indicates that the
volume of mobile source credits used under the program is very small
(only 99 NO_X tons have been converted from mobile source
reductions in the last five years). Only 5 requests for conversion of
mobile source emission reduction credits to RECLAIM trading credits
were approved in 1994, and no further requests had been received as of
May 1998. The small amount of credits relative to the significant
resource expenditure for the conversion of mobile source credits under
the RECLAIM program (i.e., the need for case-by-case review given the
variability and complexity of the petitions) suggests that the RECLAIM
mobile source protocols and strategy are not yet a cost-effective
option for the trading program.
The EPA remains willing to consider adding mobile or area sources
to the trading program in the future. Most commenters recommended that
the program be opened to mobile or area sources once adequate
mechanisms are developed for addressing related concerns. In response
to these comments, and those recommending that EPA support pilot
programs in States in order to facilitate resolution of the areas of
concern for mobile and area sources, EPA will investigate how grant
funding may be used for such pilots. Additionally, EPA is pursuing
possible ways to incorporate mobile and area source strategies into
other trading and incentive programs. Through these efforts, EPA will
work with States in finding solutions to adequately address concerns
such as emissions variability, difficulty in controlling emissions
growth, difficulty in monitoring emissions levels, and difficulty in
establishing emissions baselines. Through this process, EPA and States
will explore and develop the necessary protocols that could eventually
allow the inclusion of mobile and area sources in some capacity in the
NO_X Budget Trading Program. Anticipating that the
quantification, verification, and administration concerns regarding
expansion of the trading program to include mobile and area sources may
be sufficiently resolved in the future, EPA is reserving in this
rulemaking a section in part 96 for future inclusion of mobile or area
sources in the NO_X Budget Trading Program.
The EPA is aware of other concerns on which the Agency did not
receive comment, including the adequacy of some of the existing mobile
source protocols and the enforcement of mobile source credit generation
strategies. These emerging issues, coupled with past experience, and
the issues raised by commenters lead EPA to conclude that it is not
appropriate to include mobile and area sources in the NO_X
Budget Trading Program at this time.
3. Monitoring
For the reasons set forth in the SNPR (63 FR 25938-40), EPA
proposed that sources in the NO_X Budget Trading Program use
the monitoring methodologies in proposed subpart H of part 75 to
quantify their NO_X mass emissions (63 FR 28032). The
comments that EPA has received can be classified into three main
categories:
. Support for requiring the use of part 75 to demonstrate
compliance with the trading program,
. Support for using CEMS on large units, but concerns about
using part 75 as the monitoring protocol, and
. Concerns about requiring CEMS.
Some of the commenters concerned about requiring CEMS focused on
units of any size that are not subject to the provisions of the Acid
Rain Program. Others focused on smaller units.
The EPA proposed revisions to part 75 (63 FR 28032) for a number of
reasons, one of which was to add procedures for monitoring
NO_X mass emissions (subpart H). These procedures could be
used by sources to comply with any State or Federal program requiring
measurement and reporting of NO_X mass emissions. In
particular, subpart H would be used by sources to meet the monitoring
and reporting requirements of the NO_X Budget Trading Rule
(part 96) and the monitoring and reporting requirements of the SIP call
for (1) combustion units (boilers, turbines and combined cycle units)
which serve electric generators greater than 25 MWe and (2) combustion
units greater than 250 mmBtu/hr, regardless of whether they serve a
generator.
The part 75 revisions also proposed to make a number of other
changes that would affect units using part 75 to comply either with the
requirements of title IV or the requirements of a NO_X mass
emissions program that incorporated or adopted the requirements of part
75. These included a number of minor changes to simplify and streamline
the rule to make it more efficient for both affected facilities and
EPA, a new excepted monitoring methodology that would reduce monitoring
burdens for affected facility units with low mass emissions, new
quality assurance requirements based on gaps identified by EPA during
evaluation of the initial implementation of part 75, and several minor
technical

[[Page 57465]]

changes to maintain uniformity within part 75 and to clarify various
provisions.
The following discussion addresses comments received in the SNPR
docket (A-96-56) that are related to the general requirement to monitor
emissions, the requirement to monitor emissions using CEMS, and the
requirement to monitor using part 75. Although EPA had requested that
all comments related to the use of part 75 for monitoring
NO_X mass be submitted to the part 75 docket (A-97-35), some
comments also dealt with the specific requirements set forth in part 75.
In today's rulemaking, EPA is finalizing sections of part 75
related to monitoring NO_X mass emissions as well as those
which address the excepted monitoring methodology for units with low
mass emissions of NO_X and SO₂ that combust oil or
natural gas. Units using this methodology to comply with the
requirements of part 96 would be subject only to the NO_X
mass emission requirements and not to the SO₂ mass emission
requirements. For a more complete discussion of the NO_X mass
monitoring and reporting provisions in part 75, see the Amendments to
Part 75 Section below and Appendix A of this preamble. These Sections
discuss both the comments received in the part 75 docket as well as the
comments received in the SNPR docket that address the specific
requirements of part 75.
a. Use of Part 75 to Ensure Compliance with the NO_X
Budget Trading Program. Several commenters supported the idea of
requiring all sources in the trading program to meet the monitoring
provisions of part 75. Some of these commenters noted that part 75
provides the consistent and accurate monitoring requirements necessary
to ensure the integrity of a cap and trade program. They also noted
that the proposed revisions offered the flexibility needed for sources
to be able to reasonably comply.
Several commenters supported the concept of trying to consolidate
the monitoring and reporting requirements for units in the
NO_X Budget Trading Program already subject to part 75 under
the Acid Rain Program.
Response: The EPA agrees that accurate and consistent data are
important to ensure the integrity of a trading program and that the
protocols in part 75 provide for such accurate and consistent data from
stationary combustion sources. Today's final model rule would require
all sources in the trading program (including sources currently subject
to part 75) to use the monitoring and reporting procedures set forth in
subpart H of part 75.
b. Use of CEMS on Large Units. A number of commenters expressed
support for the requirement that large units should use CEMS to
quantify NO_X mass emissions. Many of these commenters did,
however, have concerns about using part 75 as the basis for this
monitoring. Some of these commenters elaborated that part 75 was
specifically developed for utility units and that it might not be
applicable to other types of units. Commenters also expressed concerns
about costs associated with upgrading existing CEM systems to meet the
part 75 requirements. The main alternatives they suggested were either
using existing State monitoring and reporting requirements or allowing
States the discretion to create or approve new monitoring and reporting
requirements.
Response: For reasons set forth in the preamble to the SNPR, EPA
believes that the use of CEMS, in general, and the protocols in part
75, more specifically, are the most effective way to ensure that
NO_X mass emissions from large combustion sources are
quantified in an accurate and consistent manner from source to source
and are reported in a consistent and cost-efficient way. This is
important to maintain the integrity and efficiency of the trading system.
The EPA believes that the protocols in part 75 can appropriately be
applied to all of the core sources (fossil fuel-fired electric
generating units and industrial boilers). The issues associated with
monitoring NO_X mass emissions from a stack attached to a
boiler, turbine, or combined cycle unit are the same regardless of
whether that boiler, turbine, or combined cycle unit is owned or
operated by a utility, by an independent power producer, or by a
manufacturer. The EPA does acknowledge that there may be additional
issues associated with monitoring NO_X mass from units such
as process heaters or cement kilns.
The RECLAIM program uses very similar protocols to the ones in part
75 to quantify NO_X mass emissions. Both RECLAIM and part 75
require the use of NO_X CEMS and flow CEMS to quantify
NO_X mass emissions from large sources combusting solid fuel.
Both RECLAIM and part 75 also offer large oil and gas units an
additional option for monitoring. This option involves the use of a
fuel flowmeter and fuel sampling and analysis. The RECLAIM program
requires monitoring of source categories that are in the NO_X
Budget Trading Program core group, such as boilers and turbines, but
also requires monitoring of source categories that are not in the core
group, such as process heaters and cement kilns.
RECLAIM needed to establish a standing working group to resolve
issues related to monitoring NO_X mass from such a wide range
of source categories (See South Coast Air Quality Management District,
RECLAIM Program Three Year Audit and Progress Report, May 8, 1998). EPA
does not believe that the problems that RECLAIM has had with monitoring
are related to the protocols that program uses. Rather, EPA believes
these problems are due to the limited experience that both States and
sources have with monitoring such a wide range of source categories.
The EPA believes that regardless of what protocols are used, if
States opt to bring additional source categories into the trading
program, issues related to monitoring at specific source categories
will arise. These issues will need to be resolved, thus improving State
and EPA experience with those source categories. If a State wants to
include additional sources beyond those included in the core group,
then EPA would resolve issues through the initial certification process
for opt-in units. The EPA will also provide additional guidance on
specific source categories, sharing the experiences gained with
individual opt-in units.
Using one basic set of protocols will make it easier for states,
sources and EPA to work together while gaining more experience with
these sources and resolving the issues in a cooperative and consistent
manner.
The EPA believes that the most significant costs associated with
upgrading from an existing NO_X emission rate monitoring
system to a part 75 NO_X mass monitoring system are
associated with the need to monitor NO_X mass and would be
incurred regardless of the specific monitoring protocol that was
required. Many existing CEM rules other than part 75 require sources to
monitor NO_X emission rate (in lbs/mmBtu) or NO_X
concentration corrected for oxygen (in ppm)(e.g. monitoring
requirements under Subpart D, Da, Db of part 60). In order to meet
these requirements, a NO_X monitoring system must consist of
a NO_X concentration CEM, a diluent CEM and a data
acquisition and handling system (DAHS). The DAHS is the part of the
system that collects raw monitor data, performs calculations, and
generates reports.
In order to upgrade an existing system so that it can monitor
NO_X mass, a source must install a flow CEMS, if it burns
solid fuels, or must install either a flow CEMS or a fuel flow meter if
it burns a homogeneous oil or gas. In addition, the source would have to

[[Page 57466]]

upgrade its DAHS to reflect the reporting of NO_X mass rather
than NO_X emission rate or NO_X concentration.
These costs must be incurred, regardless of the protocol that a source
used to monitor NO_X mass.
The EPA believes that a single monitoring and reporting protocol
for the NO_X Budget Trading Program will keep the costs of
upgrading systems to a minimum. This is because equipment vendors will
be able to create standardized systems that will be applicable to all
sources in the program, rather than having to create many different
State- and source-specific systems. A single monitoring and reporting
protocol will also help ensure a level playing field for all affected
sources.
For these reasons, part 96 requires all large units to monitor
NO_X mass emissions using CEMS in accordance with part 75.
However, as explained below, part 75 does offer various monitoring
options for low-emitting or infrequently operated oil- and gas-fired
units, in addition to CEMS.
c. Commenters Who Do Not Believe That CEMS Are Necessary. Some
commenters expressed concerns about requiring CEMS on any unit that
does not currently have a CEMS monitoring requirement. Suggested
alternatives included the use of stack test data and emission factors.
Some commenters also suggested the testing and monitoring provisions of
a source's title V permit.
Response: For large sources, EPA does not believe that stack test
data and emission factors provide the consistent and accurate data
needed to facilitate a trading program. Stack test data provide a one-
time assessment of a source's emission rate. Emission factors at best
are based on a series of stack tests at similar units. A unit's actual
emission rate may fluctuate greatly over time due to factors such as
the way the unit and/or its associated control equipment is operated
and maintained and the quality of fuel that the unit burns. An emission
factor or stack test will often not be representative of that unit's
actual normal emissions. Continuous monitoring of actual emissions will
ensure that fluctuations in emission rates are accounted for. Because
CEMS provide continuous monitoring, they can also indicate when
emission control equipment is malfunctioning, thus, helping to ensure
that the owners of units continue to properly operate and maintain any
installed emission control equipment.
Title V permits incorporate all of the monitoring requirements to
which a source is subject in order to demonstrate compliance with its
current regulatory requirements. In addition, where a source is not
subject to any other monitoring requirements, it sets forth minimum
monitoring requirements. In many cases the current regulatory
requirements do not require compliance with a mass emissions
limitation. Therefore, the monitoring requirements are not designed to
demonstrate compliance with a mass emission limitation.
Even when a source may have monitoring requirements designed to
demonstrate compliance with a mass emissions limitation, the stringency
of these requirements often varies from source to source and from State
to State. These variations in turn lead to inconsistencies in sources'
accounting of mass emissions. This both creates an uneven playing field
for sources and undermines the integrity of the trading program.
The EPA believes that it is necessary for all sources in the
trading program to be subject to accurate and consistent monitoring
requirements designed to demonstrate compliance with a mass emission
limitation. This will ensure compliance with the requirements of the
SIP Call and will ensure the integrity of the trading program.
The EPA does believe that it is appropriate to provide lower cost
monitoring options for units with low NO_X mass emissions.
Part 75 allows non-CEMS alternatives to quantify NO_X mass
emissions for gas and oil fired units that have low NO_X mass
emissions and/or that operate infrequently.
In contrast, EPA does not believe that the types of protocols set
forth in the Compliance Assurance Monitoring (CAM) rule, part 64, are
appropriate for a trading program because they were not designed to
quantify mass emissions. The preamble to the CAM rule further
elaborates why these protocols are not appropriate for a trading
program (62 FR 54915, 54916, 54922).
The EPA believes that the types of protocols in RECLAIM and the
Ozone Transport Commission's NO_X Budget Trading Program
(``OTC Program'') are more appropriate for a trading program because
they were specifically designed to quantify NO_X mass
emissions. The EPA also believes that the flexible monitoring options
offered by part 75 are consistent with the type of flexibilities
offered in RECLAIM and the OTC Program. RECLAIM requires CEMS on all
units that burn solid fuels and all units that emit more than 10 tons
per year, regardless of the type of fuel they burn.. The OTC Program
requires CEMS on all units that burn solid fuels and all units that do
not qualify as peaking units, that are larger than 250 mmBtu/hr or that
serve generators greater than 25 MW. Like RECLAIM and the OTC Program,
part 75 requires CEMS on all units that burn solid fuel. Part 75 also
requires the use of CEMS on oil and gas fired units that emit more than
50 tons of NO_X annually (or for units that only report
during the ozone season, 25 tons of NO_X during the ozone
season), or that don't qualify as peaking units. In both the OTC
Program and part 75, a peaking unit is defined as a unit that has a
capacity factor of no more than 10 percent per year averaged over a
three year period and no more than 20 percent in any one year.
The EPA believes that these exceptions in part 75 provide cost-
effective monitoring alternatives to CEMs for small, low mass emitting,
or infrequently used units, and therefore, it is appropriate that part
96 require all units to use part 75.
d. Issues Related to Monitoring and Reporting Needed to Support a
Heat Input Allocation Methodology. For monitoring and reporting
NO_X mass emissions, subpart H of part 75 requires the use a
NO_X concentration CEM and a flow CEM. Since the methodology
does not require the use of heat input, EPA would not require sources
to monitor or report heat input or NO_X emission rate for a
NO_X mass emission reduction program. If a State elects to
use a periodically updating allocation methodology that utilizes heat
input, it may need to require sources using this methodology to monitor
and report heat input also.

e. Amendments to Part 75 (1) Summary of Part 75 Rulemaking. Title IV of
the CAA requires the EPA to promulgate regulations for continuous
emissions monitoring (CEM). On January 11, 1993, final rules (40 CFR
part 75) were published (58 FR 3590). Technical corrections were
published on June 23, 1993 (58 FR 34126) and July 30, 1993 (58 FR
40746). A notice of direct final rulemaking and a notice of interim
final rulemaking making further changes to the regulations were
published on May 17, 1995 (60 FR 26510 and 60 FR 26560, respectively).
Subsequently, on November 20, 1996, a final rule was published in
response to public comments received on the direct final and interim
rules (61 FR 59142).

The EPA proposed further revisions to part 75 on May 21, 1998 (63
FR 28032). These revisions included a new subpart H which sets forth
procedures for monitoring NO_X mass emissions, which could be
used by sources to comply with any State or Federal program requiring
measurement of NO_X mass emissions, including the requirements

[[Page 57467]]

of the NO_X Budget Trading Rule (part 96). The May 21, 1998
proposed revisions also proposed to make a number of other changes that
would affect units that were using part 75 to comply either with the
requirements of title IV or the requirements of a NO_X mass
trading program under title I that incorporated or adopted the
requirements of part 75. These included a number of minor changes to
simplify and streamline the rule to make it more efficient for both
affected facilities and EPA; a new excepted monitoring methodology that
would reduce monitoring burdens for affected facility units with low
mass emissions; and new quality assurance requirements to fill in gaps
identified by EPA during evaluation of the initial implementation of
Part 75.
(2) Schedule For Part 75 Final Rulemaking. The comment period for
the proposed revisions to part 75 ended on July 20, 1998. EPA
anticipates completing rulemaking on all of proposed revisions to part
75 by the end of the year. However, because the revisions to subpart H
of part 75 relating to the monitoring and reporting of NO_X
mass emissions are integral requirements of the SIP Call, EPA is
finalizing most of the requirements of subpart H of part 75 with
today's action.
The EPA is also finalizing a new excepted monitoring methodology
for units that combust natural gas and or fuel oil with low mass
emissions of NO_X and SO₂. These provisions are
being finalized because they are one of the methodologies that certain
gas and oil units can use to quantify NO_X mass under the new
subpart H of part 75.
The EPA is not finalizing the rest of the proposed revisions to
Part 75 at this time because EPA is still evaluating the comments
received on the proposed rulemaking. Many of these remaining provisions
will be applicable to any unit that must use the requirements of part
75 in order to meet the requirements of title IV or to meet the
requirements of a State or Federal NO_X reduction program
that adopts the part 75 requirements. For example, the proposed
revisions would allow a unit with CEMS to be exempt from the
requirement to perform a linearity test in any quarter that the
combustion unit for which the CEMs is installed operates for less than
168 hours. If EPA ultimately finalizes this proposed flexibility, it
will become available both to units using part 75 to comply with title
IV and to units using it to comply with the part 96 model trading rule.
As another example, EPA proposed quality assurance requirements for
moisture monitors that would be needed if pollutant concentration
(NO_X, SO₂ or CO₂) were measured on a
dry basis and needed to be converted to a wet basis so that mass
emissions could be determined using a stack flow meter. If EPA
ultimately finalizes this proposed requirement it will affect both
units using part 75 to comply with title IV and units using it to
comply with part 96 (or a State or Federal NO_X mass
reduction program that adopts part 75).
The EPA is also not yet finalizing the recordkeeping and reporting
requirements associated with either the NO_X mass monitoring
provisions in subpart H or the low mass emitter monitoring methodology
because EPA believes that these reporting requirements should be
coordinated with any changes in the reporting requirements that result
from the finalization of the rest of proposed revisions to part 75.
Therefore, EPA has closed the part 75 docket (A-97-35, with respect
to the provisions that are being finalized in today's rulemaking:
section 75.19, a new excepted methodology for estimating emissions for
units with low mass emissions; and subpart H, a new subpart setting
forth provisions for monitoring, recording and reporting NO_X
mass emissions, except where EPA has reserved final action on related
aspects of these provisions. EPA has not closed the docket with respect
to the other provisions that were the subject of EPA's, May 21, 1998
proposal (63 FR 28032).
(3) Summary of Major Differences Between Proposed and Final
Revisions to Part 75. The final rule contains two main differences to
the NO_X mass monitoring and reporting provisions from what
was proposed. The first is that a new methodology for calculating
NO_X mass emissions is included. This methodology utilizes a
NO_X concentration CEM and a flow CEM to calculate
NO_X mass emissions. The second is that sources that are not
subject to title IV are not required to monitor and report data outside
of the ozone season unless otherwise required to do so by the
Administrator or the permitting authority administering the
NO_X mass trading program.
The final rule also contains two main differences from the proposal
with regard to the new excepted monitoring methodology for low mass
emitters. The first is that the methodology is applicable to units with
calculated NO_X mass emissions of up to 50 tons, rather than
25 tons as proposed. The second is that in lieu of using default rates
for NO_X set forth in the rule, the owner or operator of a
unit using this methodology may instead elect to determine a unit
specific rate by conducting stack testing. All of these changes are
discussed in greater detail in Appendix A of this notice. At this time
EPA is only addressing the comments dealing with the two main issues
for which EPA is finalizing revisions to part 75, the reporting of
NO_X Mass (subpart H) and a new excepted monitoring
methodology for low emitters (Sec. 75.19). The EPA intends to address
the rest of the comments on the part 75 rulemaking in a separate,
future rulemaking. The discussions in Appendix A also address comments
received in the SNPR docket (A-96-56) that related specifically to the
monitoring requirements set forth in part 75.

E. Emission Limitations/Allowance Allocations

Each State has the ultimate responsibility for determining the size
of its trading program budget and its individual source allocations as
long as the trading budget plus emissions from all other sources do not
exceed the State's SIP Call budget. The proposed rule published on May
11, 1998 set timing requirements identifying when the allocations
should be completed by each State and submitted to EPA for inclusion in
the NO_X Allowance Tracking System (NATS) and provided an
option specifying how a State might allocate NO_X allowances
to the NO_X budget units. Today's final model rule clarifies
the timing requirements for submission of allowance allocations to EPA
and provides an optional allocation approach. Each State remains free
to adopt the Model Rule's allocation approach or adopt an allocation
scheme of its own provided it meets the specified timing requirements,
requires new sources to hold allowances, and does not allocate more
allowances than are available in the State trading budget.
1. Timing Requirements
In the SNPR, EPA set timing requirements identifying when a State
would finalize NO_X allowance allocations for each control
period in the NO_X Budget Trading Program and submit them to
EPA for inclusion into the NATS. In developing the proposal, the Agency
reasoned that uniform timing requirements would be important to ensure
that all NO_X budget units in the trading program would have
sufficient time and the same amount of time to plan for compliance for
each control period, and sufficient time and the same amount of time to
trade NO_X allowances. After considering a range of timing
requirements, EPA proposed options that allocated NO_X allowances 5

[[Page 57468]]

to 10 years in advance of the applicable control period. The proposal
attempted to strike a balance between systems that change the
allocations on an annual basis and systems that establish a single,
permanent allocation.
The proposed rule included the following timing requirements for
the allocation of NO_X allowances: by September 30, 1999,
each participating State would submit NO_X allowance
allocations to EPA for the control periods in the years 2003, 2004,
2005, 2006, and 2007. After the initial allocation, two timing
requirements were proposed for allocations following the year 2007. The
option set forth in the proposed Model Rule would require a State to
submit allocations to EPA for the control period in the year that is 5
years after the applicable submission deadline. For example, by January
1, 2003 each State participating in the trading program would issue its
allocations for the control period in 2008. The State would issue
allocations for the 2009 summer season by January 1, 2004. The second
option, discussed in the preamble of the supplemental notice, would
require the State to submit five years' worth of allowance allocations
at a time, every five years, starting in 2003. For example, by January
1 , 2003, each State participating in the trading program would issue
allocations for the control periods in the years 2008 through 2012. The
supplemental notice solicited comment on these timing options as well
as the full range of possible timing requirements (including a single,
permanent allocation system and an annually changing allocation
system). The supplemental notice also solicited comment on a provision
requiring EPA to allocate NO_X allowances to NO_X
budget units if a State were to fail to meet the timing requirements.
Comments: Although comments covered the entire range of possible
timing requirements, commenters generally supported striving for
administrative simplicity and ensuring sufficient planning horizons for
affected sources, while still addressing the needs of a changing
marketplace. Most comments fell into one of five categories.
First, a few commenters favored the option set forth in the
proposed Model Rule that would update the allocations each year, five
years in advance of the applicable control period. However, most of
these commenters also supported a system which would update the
allocations less than five years prior to the applicable control period
as that would allow more recent data to be used in the allocations. One
commenter advocated allocating for the previous season based on current
year data (i.e., allocations would be issued at the end of the season
for the preceding control period).
Approximately ten commenters favored the approach which would issue
allowances five to ten years in advance. This group found that five to
ten years of allocations satisfies the desire to have a sufficient
planning horizon while still ensuring responsiveness to changing market
conditions. Utilities generally opposed allocating single year
allowances as it might be disruptive to utility planning.
The third category of commenters advocated longer term or permanent
allocations. Most utility and business commenters favored allocations
that were issued in ten year blocks at a minimum to provide sufficient
time to plan future activities and amortize investments. A report
submitted by a State proposed that allocations extend over the capital
life of equipment, which was at least ten years.
A fourth set of commenters, which included three States, favored
shorter term allocations. These States commented that they may want to
base their allocations on more recent data than that proposed by the
Model Rule and suggested that three years would provide sufficient
planning time for sources. One State suggested tying allocations to the
submission of triennial inventories.
A final group of commenters suggested that no timing requirement
was necessary. They suggested that just as sources may participate in
an interstate trading program with allocations based upon different
methodologies, those same sources may participate in such a program
even if they receive their allowances at different times or for
different periods.
Several State commenters asserted that September 1999 was too early
to have allocations set. These States suggested that the allocation
process is difficult and takes longer than one year. One State
suggested that the early allocation deadline would effectively prevent
States from issuing allowances based upon output for the first period
because an output approach could not be developed in time.
Response: Most commenters supported issuing allowances at least a
couple of years prior to the season in which they would be used. The
commenters generally cited the goal of balancing changing market
conditions with providing sufficient planning horizons, as had the
Agency in the proposal. The EPA agrees that the certainty in having
allowances at least a couple of years into the future would provide
some predictability for sources in their control planning and build
confidence in the market. Most of the State commenters suggested three
years prior to the control season as an adequate length of time for
sources to know their allocations. The Agency agrees that a trading
system could work with sources knowing their allocations three years
prior to the control season. Therefore, EPA has modified its original
proposal to ensure that sources would always have allowances at least
three years in advance of the use date.
In addition to addressing how many years in advance the allocations
are determined, the Agency has also considered whether allocations
should be issued one control period at a time or for multiple control
periods at a time (e.g., five to ten control periods). In response to
the comments received, the Agency has determined that it would be
appropriate to set minimum timing requirements rather than prescribing
a set length of time for all States. Therefore, the Agency is now
requiring States choosing to participate in the NO_X Budget
Trading Program to allocate a minimum of one summer season of
allowances at a time (at least three years in advance of the applicable
control period).
Moving from requiring five summer seasons of allocations (three
years in advance of the first season) to one summer season of
allocations (three years in advance) has the advantage of allowing the
allocation system to be updated sooner with more recent data. This
would provide those States that want to use updating systems to more
fully avail themselves of an updating system. The system could also
incorporate new sources more quickly, thus reducing the need for larger
new source set-asides.
However, the Agency has determined that a State may decide to issue
allowances further into the future than the one-season minimum period
required by this final rule and still receive streamlined EPA review of
its trading program. The NO_X Allowance Tracking System will
be able to handle allocations for longer periods. Therefore, this Final
Rule sets out minimum timing requirements of one season (three years in
advance), but States may issue allocations in larger blocks for as many
as 30 seasons into the future and still receive streamlined EPA review.
However, in determining the length of time for which a State issues
allocations, a State should consider any potential adjustments that may
occur to its future State budgets. For example, as stated in Section
III.B.5.

[[Page 57469]]

of this preamble, the Agency may establish new budget levels for the
post-2007 timeframe. States issuing long-term allocations should
address how the allocations would be adjusted if new budget levels are
established in the future. The Agency does believe that having
allocations three years prior to the relevant control period would be
the minimum needed to support an active multi-state trading market
intended to reduce compliance costs for all States involved.
The three-year minimum timing requirement also is compatible with
beginning the program in 2003, with at least the first year's
allocations submitted to EPA by September 30, 1999. Sources will know
their first year's allocations three years prior to the start of the
program, and by April 1, 2003, all sources will have allocations for at
least four seasons--2003, 2004, 2005 and 2006. The Agency maintains
that the first year's allowances should be issued by September 30, 1999
to provide some predictability for sources in their control planning
and build confidence in the market. It also ties in with the State's
SIP submittal deadlines. For States participating in the trading
program, the allowances are an integral part of the State's plan to
satisfy the requirements of this SIP call. For sources in the Trading
Program, the allowances are the mechanism by which State budget
requirements are translated into source-specific limitations, and
therefore the allocations should be submitted with the SIP submittals.
In response to States who are worried about completing allocations in
this time frame, EPA notes that one State in the OTC resolved its
allocations in six weeks, demonstrating that it is possible to
establish allocations in less than one year.
Requiring only one year's worth of allowances at a time has the
added benefit of being able to more quickly accommodate States that
want to switch allocation methodologies after the start of the program.
For example, a State may decide to issue its initial allocations based
on heat input data because it has not yet finalized an approach to
issuing output-based allocations. The State could take a few additional
years to refine the alternative approach to issuing allowances. When
the State is ready to adopt the output approach, the State would be
able to start using the new approach much sooner than it would be able
to under a system that issued allocations in larger blocks.
Therefore, this preamble sets the following timing requirements for
the allocation of NO_X allowances which will be able to
accommodate States that want to issue allocations one year at a time as
well as States that would like to issue allocations in larger blocks:
by September 30, 1999, the State would submit NO_X allowance
allocations to EPA for at least the control period of 2003. After this
initial allocation, by April 1 of every year starting in 2001, the
State must, at a minimum, submit allowance allocations to EPA for the
control period in the year that is three years after the applicable
submission deadline. For example, by April 1, 2001, a State would
submit allocations for the control period in 2004. By April 1, 2002, a
State would submit allocations for the control period in 2005. This
minimum requirement would allow a State to submit blocks of allowances
that represent any number of years should the State prefer to do so.
For example, by the September 30, 1999 deadline, a State could submit
allocations for only the 2003 control period or for multiple control
periods (e.g., the five control periods of 2003-2007). The SIP would
provide that if the State fails to submit allocations by the required
date, EPA would allocate allowances based on the previous year's
allocation within 60 days of the applicable deadline. This approach
would ensure that starting in 2003, all sources would always have at
least three years of allowances in their accounts.
Today's Model Rule presents an allocation approach that satisfies
the minimum timing requirements. However, the initial allocation is for
three control periods (2003-2005) because this would avoid updating
allocations on an input basis. Any variation on the following approach
would be acceptable providing it satisfies the minimum requirements
specified in the previous paragraph. After this initial allocation, the
model rule would have the State submit allowance allocations to EPA for
the control period in the year that is three years after the applicable
submission deadline. By April 1, 2003, a State would submit allocations
for the control period in 2006. By April 1, 2004, a State would submit
allocations for the control period in 2007, and so forth.
2. Options for NO_X Allowance Allocation Methodology
The Agency proposed that the NO_X Budget Trading Rule
include a recommended NO_X allowance allocation methodology.
The proposed Model Rule laid out an example of an allocation
methodology using heat input data for source allocations. The preamble
to the proposed Model Rule solicited comment on this methodology as
well as two additional options using either input or output data for
determining allocations. The first alternative to using heat input
would base the allocation recommendation on heat input data for the
first five control periods of the trading program and then convert the
allocations to an output basis for the control periods after 2007. The
final option would base the allocation recommendation on output data
for all NO_X Budget units from the start of the trading
program. The Agency also solicited comment on a suggested schedule for
establishing a method for output-based allocations, and on any
technical or data issues relevant to output-based allocations, as well
as on the use of a fuel-neutral or output-neutral calculation to
determine allocations for NO_X Budget units.
Comments: The Agency received numerous comments on the issue of
whether to suggest an allocation recommendation to States.
Approximately 25 commenters suggested that no recommendation is
necessary. Many of these commenters emphasized that EPA had no
authority to prescribe an allowance allocation methodology and a
recommendation could be misinterpreted as a requirement for SIP
approval. Several commenters requested that EPA clarify that the SIP
approval process will be consistently applied to all States regardless
of the allocation method chosen by a State, as long as the total
allocation does not exceed a State's trading budget. Approximately half
of the commenters who stated that no recommendation was necessary
suggested that if EPA were going to make a recommendation, the
recommendation should be a heat input approach.
Close to fifty commenters suggested that an Agency recommendation
was a good idea, but they were divided on the appropriate methodology.
This group included all the State commenters who suggested that a
recommended approach was appropriate for use as a default allocation
mechanism by States that did not determine their own allocations.
Many commenters supported the heat input approach used in the
example in the supplemental notice. Two State commenters said that the
proposed example approach was a useful default for States that did not
come up with their own allocations. Other commenters suggested that
heat input is an easily understood metric for all sources and the data
is readily available.
However, many suggested that EPA should recommend an output method
because they believe output-based allocations tend to reward more efficient

[[Page 57470]]

fuels over fuels that require a higher heat input to generate the same
amount of electricity. Other reasons cited for output-based allocations
include the incentive that updating output allocations provides for
reducing emissions of pollutants such as CO₂ and mercury.
Several commenters suggested that output-based allocations would allow
the environmental goals of the program to be achieved more cost-
effectively; their arguments rested upon assertions that issuing
allowances to non-NO_X emitting units in an output-based
system would reduce the need for NO_X controls over time. One
State commenter said that an output approach was the consensus of
participants at EPA Workshops held prior to drafting of the
Supplemental Notice and therefore should be the recommended approach
suggested by EPA.
One commenter had a specific recommendation for an updating output-
based allocation system which would issue allowances each year for the
current control period. Administrative simplicity, economic efficiency,
incentives for innovation, and lower consumer impact were cited as
reasons supporting that position.
Additional commenters favored the output-based approach but only
for fossil-fuel fired sources and renewables. Several commenters
submitted letters opposing a ``fuel-neutral'' policy and objected to
including nuclear sources in an output allocation to sources. They
stated that a fuel neutral policy would provide incentives for nuclear
generation which has the potential to release small amounts of
radiation to the environment as well as the potential for generation of
high-and low-level radioactive waste.
Response: As was stated in the SNPR, EPA believes that it is
important for as many States as possible to participate in the
NO_X Budget Trading Program. The Agency recognizes that
States have unanimously favored flexibility in developing their own
allocation methodologies. Further, the comments that EPA received in
response to the SNPR (as well as in response to the workshops held
prior to publication of the SNPR) provided no clear consensus for one
methodology over another.
However, the Agency believes it is important to provide a model
allocation methodology that States may choose to use as a guide for
their own allocation process. Several States have commented that
including an example method in the Model Rule would be useful as a
backup for States who do not come up with an alternative method of
allocation. An outlined approach in the Model Rule may also facilitate
the regulatory process within a State that wants to quickly adopt the
Model Rule.
Therefore, today's Model Rule includes an optional allocation
methodology. The Agency has carefully considered arguments for
alternative allocation methods. The EPA would support a decision by a
State to use either heat input or output data as a basis for source
allocations or for the State to auction some or all of its allocation.
In determining the basis for the methodology presented in today's Model
Rule, EPA has decided to use the heat input approach because it is
concerned that an output-based approach has not been fully developed or
made available for public comment. Further, before issuing a model
output-based allocation approach, the Agency would need to make several
revisions to current reporting and monitoring provisions. EPA would
have to revise part 75 to monitor and report temperature, pressure, and
steam heat output (mmBtu) for units with some or all of their output as
heated steam. EPA would also need to put in place procedures which take
advantage of the most accurate data possible. For example, the Energy
Information Administration (EIA) solicited comment in a July 17, 1998
Federal Register Notice on a proposal to make electricity generating
data non-confidential and publicly available from non-utility
electricity generators (63 FR 38620). EPA will not know if this
information is available to the Agency or to States through EIA for
some time. If EIA were to decide that this information should remain
confidential in the future, then EPA and States would need to collect
their own data from sources. Additionally, the Agency is currently
unaware of any public databases of output information besides those for
electrical generation output for certain electrical generating units.
Output information would only become available if sources report it
directly to the Agency or to States.
While today's final Model Rule includes a heat input approach, the
Agency is continuing to work on developing an updating output approach
to source allocations. For States that wish to use output in developing
their source allocations and are willing to wait for EPA to finalize
such an approach, EPA plans to issue a proposed system for output-based
allocations in 1999 and finalize an output-based option in 2000.
However, the Agency's ability to issue an output-based approach on this
schedule is contingent upon resolving the issues and promulgating the
necessary rule changes mentioned in the previous paragraph.
Assuming EPA finalizes an output-based option in early 2000, States
wishing to use this output-based system could adopt the necessary
rules, and output data could be measured and collected at
NO_X budget units during the control periods in the years
2001 and 2002. Output data could then be available for States to
calculate allocations for the control periods starting in 2006. Heat-
input-based allocations could be used for the 2003 through 2005 control
seasons.
However, this does not prohibit a State from developing its own
output-based system on a faster timeline. For example, if a State has
developed an output-based approach for use in its initial allocations,
it may use that approach. Or, the State may issue its initial
allocation for 2003 using heat input data and then by April 1, 2001
issue output allocations for the control periods starting in 2004.
The Agency recognizes that a State's choice of when and for what
blocks of time it issues allocations is intertwined with the choice of
allocation methodology. Several commenters suggested that more
incentives for generation efficiency and therefore ancillary
environmental benefits (CO₂ and mercury reductions) are
provided in an output system with periodic updates, and those
incentives are lost in an heat input system that is periodically
updated. These commenters suggested that with a heat-input-based
system, States should issue permanent allocations rather than updating
the allocations. An allocation system that issues permanent streams of
allowances (using either a heat input or an output methodology) would
still provide an incentive for generation efficiency although perhaps
not to the extent that an updating output system might. However, if a
State issues a permanent stream of allowances to existing sources, that
State would have to decide how to address new sources (options include
establishing an allocation set aside or an auction, or requiring new
sources to obtain allowances from existing sources).
3. New Source Set-Aside
The Agency proposed an allocation set-aside account equaling 2
percent of the State trading program budget for each control period for
new NO_x Budget units as part of its recommended allocation
approach. The concept and size of the set-aside is included only as an
optional feature of the Model Rule; however, the Model Rule requires
new sources to hold allowances to cover

[[Page 57471]]

their emissions. The supplemental notice proposed that allowances from
the set-aside be given out on a first-come, first-served basis at an
emission rate of 0.15 lb/mmBtu multiplied by a budget unit's maximum
design heat input. The source would then be subject to a reduced
utilization calculation so that a reduction in the emission rate below
0.15 lb/mmBtu would be rewarded, but a reduction in utilization would
not. In other words, EPA would deduct NO_x allowances
following each control period based on the unit's actual utilization
for the control period. After the deduction, the allocation that had
been granted to the new unit from the set-aside would equal the product
of 0.15 lb/mmBtu and the budget unit's actual heat input for the
season. EPA solicited comments on the use of a set-aside as part of the
recommended allocation methodology as well as the proposed size and
operation of the set-aside.
Comments: The Agency received many comments regarding the proposal
for a new source set-aside. While several commenters were opposed to a
new source set-aside because it might bias control decisions in favor
of adding new sources relative to controlling existing sources,
numerous other commenters expressed general support for accommodating
new sources with allowances.
Several of these commenters offered suggestions for how the set-
aside should be designed. A few commenters stated that the size of the
set-aside should be related to the timing requirements and noted that
shorter timing requirements make it easier to accommodate new growth.
One commenter who advocated annually updating the allocation system
noted that its proposal would eliminate the need for a new source set-
aside. Some commenters supported the set-aside concept but asserted
that States should be able to decide the correct size. Other commenters
agreed with the set-aside concept in theory but did not think the
allowances should come from existing sources.
Additional commenters had specific proposals for the size of the
set-aside. One commenter suggested that the size of the set-aside
should reflect the actual growth projected in budget calculations and
that the unused portion of the set-aside should be retired. A few
commenters agreed with the proposed 2 percent size.
Several commenters offered suggestions on how to issue the set-
aside allowances to new sources. One commenter suggested that the
allowances should be given to new sources at the actual emission rate
if it was below the proposed 0.15 lb/mmBtu level.
Finally, several commenters suggested that the concept of a set-
aside was an issue that should be left completely up to the States.
Response: The Agency believes that a new source set-aside should be
large enough to provide all new units entering the trading program with
allocations. The Agency maintains that as much as possible within the
context of the overall trading budget, allocations should be provided
to new sources on the same basis as that used for existing units until
the time when the new sources receive an allocation as part of an
updating allocation system. Therefore, the Agency continues to include
a new source set-aside as part of its optional allocation methodology
described in the Model Rule. The EPA proposed the 2 percent set-aside
in the SNPR after looking at the amount of growth from new sources
projected by the Integrated Planning Model (and used in the budget
determinations) and estimating how much growth could be expected over
the five year period that new sources might have to wait before
receiving an allocation. In light of the allocation methodology and
timing specified in today's Model Rule as well as revisions made to the
growth factors used in State budget determinations since the SNPR, the
Agency has re-evaluated the size of the new source set-aside proposal.
The revised Integrated Planning Model projects approximately \1/2\
percent annual growth in capacity utilization for new sources. Given
the timing and optional allocation methodology specified in today's
Model Rule, the 2003, 2004, and 2005 set-aside would need to
accommodate any source that started operating after May 1, 1995.
Assuming the \1/2\ percent growth rate projected by IPM, the Agency
finds that a 5 percent set-aside should be large enough to accommodate
all new sources for the 2003, 2004, and 2005 control seasons.
After 2005, the new source set-aside would need to accommodate any
source that commenced operation after May 1 of the control period three
years prior to the control period in which the set-aside would be
available. For example, in 2006, the set-aside should be large enough
to accommodate any source that commenced operation after May 1, 2003.
Assuming the growth rates predicted by the IPM, the Agency finds that a
2 percent set-aside should be large enough to accommodate new source
growth after May 1, 2003.
A 5 percent set-aside provision for the first three control seasons
and 2 percent for the control periods starting in 2006 is incorporated
into today's Model Rule as an option States may adopt. However, States
may choose to handle new sources in any way as long as the emissions
from new sources are subject to the overall State budget. For example,
some States may choose to issue allowances for longer periods of time
than that outlined as the minimum requirement in today's Model Rule.
These States may find that a 5 percent set-aside is not sufficient to
accommodate all their new source growth, and may want to consider a
larger set-aside or alternative means to accommodate new sources. Or,
States may decide to allocate allowances based on a new source's
permitted or actual emissions, which may be lower than 0.15 lb/mmBtu.
This would require a smaller set-aside.
In the model rule set-aside provision, allowances will be issued to
new sources on a first-come, first-served basis. Allowances that are
not issued to new sources in the applicable control period will be
returned to the existing sources in the State on a pro-rata basis to
guard against the possibility of a disproportionately large set-aside.
The EPA maintains its position that new sources should receive
allowances at the same rate as that applied to existing sources (i.e.,
large electric generating units would receive allowances at a 0.15 lb/
mmBtu rate, large non-electric generating units would receive
allowances at the average emission rate for existing large non-electric
generating units after controls are in place, as explained in section 4
below). However, to reinforce the flexibility available on these
issues, as long as a State requires new sources to hold allowances, the
Agency reiterates that States may have any size set-aside (including
zero), may allocate the set-aside in whatever manner they choose, and
may carry over from one year to the next any amount of allowances
(subject to the banking provisions on this SIP call). If a State
decides to return unused allowances from a new source set-aside to
existing sources, the State would indicate to EPA (as the administrator
of the allowance tracking system) what number of allowances should be
returned to which existing units.
4. Optional NO_X Allocation Methodology in Model Rule
While specific source allocations are required for States
participating in the NO_X Budget Trading Program, the
allocation methodology presented here is an optional approach that may
be adopted by States. As long as a State (1) does not allocate more
allowances than are available in the State NO_X trading

[[Page 57472]]

budget, (2) requires new sources to hold allowances, and (3) issues
allocations on a schedule that meets the minimum timing requirements,
the State may adopt whatever methodology it finds the most appropriate
and still qualify for inclusion in the NO_X Budget Trading Program.
The Model Rule contains the following optional allocation
methodology. It differs from the approach presented in the proposed
rule on the timing provisions, the allocation methodology for non-
electric generating units, and the size of the optional new source set-
aside. As proposed in the SNPR, initial unadjusted allocations to
existing NO_X Budget units serving electric generators would
be based on actual heat input data (in mmBtu) for the units multiplied
by an emission rate of 0.15 lb/mmBtu. For the control periods in 2003,
2004, and 2005, the heat input used in the allocation calculation for
large electric generating units equals the average of the heat input
for the two highest control periods for the years 1995, 1996, and 1997.
Once the State completes the initial allocation calculation for all the
existing NO_X budget units serving electric generators for
2003, 2004, and 2005, the State would adjust the allocation for each
unit upward or downward so that the total allocations match the
aggregate emission levels apportioned by an approved SIP to the State's
NO_X Budget units serving electric generators. Then, the
State would adjust the allocation for each unit proportionately so that
the total allocation equals 95 percent of the aggregate emission levels
apportioned to the State's NO_X Budget units serving electric
generators (to provide for the 5 percent new source set-aside). A State
would submit the 2003, 2004, and 2005 allocations to EPA by September
30, 1999.
For the control periods starting in 2006, the heat input used in
the allocation calculation for large electric generating units equals
the heat input measured during the control period of the year that is
four years before the year for which the allocations are being
calculated. Once the State completes the initial allocation calculation
for all existing budget units, and the State adjusts the allocations to
match the aggregate emission levels apportioned to NO_X
Budget units serving electric generators, the State would adjust the
allocation for each unit proportionately so that the total allocation
equals 98 percent of the aggregate emission levels apportioned to
NO_X Budget units serving electric generators (to provide for
the 2 percent new source set-aside).
For reasons explained elsewhere in today's rulemaking, EPA
determined the aggregate emission levels for large non-electric
generating units in each State budget based upon a 60 percent reduction
rather than the 70 percent proposed in the SNPR. The 60 percent
reduction results in an average emission rate across the region of 0.17
lbs/mmBtu for large non-electric generating units. Therefore, initial
unadjusted allocations to existing large non-electric generating units
would be based on actual heat input data (in mmBtu) for the units
multiplied by an emission rate of 0.17 lb/mmBtu. For non-electric
generating units subject to the trading program, 1995 heat input data
is used in the allocation calculation for the control periods 2003,
2004, and 2005 (1995 is the most recent data the Agency knows is
currently available for non-electric generating units). Once the State
completes the initial allocation calculation for all the existing large
non-electric generating units for 2003, 2004, and 2005, the State would
adjust the allocation for each unit upward or downward so that the
total allocations match the aggregate emission levels apportioned by an
approved SIP to the State's large non-electric generating units. Then,
the State would adjust the allocation for each unit proportionately so
that the total allocation equals 95 percent of the aggregate emission
levels apportioned to the State's large non-electric generating units
(to provide for the 5% new source set-aside). A State would submit the
2003, 2004, and 2005 allocations to EPA by September 30, 1999.
For the control periods starting in 2006, the heat input used in
the allocation calculation equals the heat input measured during the
control period of the year that is four years before the year for which
the allocations are being calculated. Once the State completes the
initial allocation calculation for all existing budget units, and the
State adjusts the allocations to match the aggregate emission levels
apportioned to large non-electric generating units, the State would
adjust the allocation for each unit proportionately so that the total
allocation equals 98 percent of the aggregate emission levels
apportioned to large non-electric generating units (to provide for the
2% new source set-aside).
A State would establish a separate allocation set-aside for new
units each control period. Five percent of the seasonal trading budget
will be held in a set-aside account for the control periods in 2003,
2004, and 2005. At the end of the relevant control period, the State
would submit a NO_X allowance transfer request to EPA to
return any allowances remaining in the account to the existing sources
in the State on a pro-rata basis.
The allowances would be issued to new sources on a first-come
first-served basis at a rate of 0.15 lb/mmBtu for NO_X Budget
units serving electric generators and 0.17 lb/mmBtu for large non-
electric generating units multiplied by the budget unit's maximum
design heat input. Following each control period, the source would be
subject to a reduced utilization calculation, in which EPA would deduct
NO_X allowances based on the unit's actual utilization.
Because the allocation for a new unit from the set-aside is based on
maximum design heat input, this procedure adjusts the allocation by
actual heat input for the control period of the allocation. This
adjustment is a surrogate for the use of actual utilization in a prior
baseline period which is the approach used for allocating
NO_X allowances to existing units.

F. Banking Provisions

As explained in Section III.F.7., EPA requested comment in the SNPR
on whether and how banking should be incorporated into the design of
the NO_X Budget Trading Program. Banking may generally be
defined as allowing sources that make emissions reductions beyond
current requirements to save and use these excess reductions to exceed
requirements in a later time period. Options ranged from a program
without banking to several variations of a program with banking, prior
to and/or following the start of the program. The EPA also requested
comment on options for managing the use of banked allowances in order
to limit the emissions variability associated with banking. The EPA
specifically proposed using a ``flow control'' mechanism in cases where
the potential exists for a large amount of banked allowances to be
available.
This section addresses how banking has been incorporated into the
NO_X Budget Trading Program based on the criteria set forth
in the NO_X SIP call.
1. Banking Starting in 2003
In accordance with the provisions discussed in III.F.7.a., trading
programs used to comply with the NO_X SIP call may allow
banking to start in the first control period of the program, the 2003
ozone season. The majority of commenters supported banking in the
context of the NO_X Budget Trading Program. Based on the
advantages that banking can provide, as discussed in the SNPR and the
comments, the NO_X

[[Page 57473]]

Budget Trading Program has been designed to allow banking starting in
the first control period of the trading program. NO_X Budget
units that hold additional NO_X allowances beyond what is
required to demonstrate compliance for a given control period may
carry-over those allowances to the next control period. These banked
allowances may be used or sold for compliance in future control periods.
2. Management of Banked Allowances
The NO_X SIP call establishes that a flow control
mechanism be paired with any banking provisions to limit the potential
for emissions to be significantly higher than budgeted levels because
of banking. This mechanism allows unlimited banking of allowances saved
through emissions reductions by sources, but discourages the
``excessive use'' of banked allowances by establishing either an
absolute limit on the number of banked allowances that can be used each
season or a rate discounting the use of banked allowances over a given
level. In the SNPR, EPA solicited comment on the application of flow
control in the NO_X Budget Trading Program. Although many
commenters were opposed to any restrictions on the use of banked
allowances, several commenters stated that if restrictions were to be
imposed, they would favor flow control as the most cost-effective,
least rigid means of management. A few commenters added that, if
implemented, flow control should be applied on a source-by-source basis
so as to avoid penalizing all of the participants in the trading
program for the excess banking of individual participants. One
commenter stated that if EPA concludes that there is an adequate basis
for imposing some type of restriction, it should avoid placing any
absolute limit on the amount of banked allowances that can be used in a
given season.
The NO_X SIP call established that flow control should be
set at the 10 percent level. The effect of setting flow control at 10
percent of the trading program budget is that on a season-by-season
basis, sources may use banked allowances or credits for compliance
without restrictions in an amount up to 10 percent of the
NO_X budget for those sources in the trading program. Banked
allowances or credits that are used in an amount greater than 10
percent of the NO_X budget for those sources will have
restrictions on their use.
The following provides a brief description of exactly how the flow
control mechanism will operate in the NO_X Budget Trading
Program. The number of banked allowances held by all participants in
the multi-state trading program will be tabulated each year following
the compliance certification process to determine what percentage
banked allowances are of the overall multi-state trading budget for the
next year. If this percentage is equal to or below 10 percent, all
banked allowances may be used in the upcoming control season on a one
allowance for one ton basis. If this percentage is greater than 10
percent, flow control will be triggered. In years when flow control is
triggered, a withdrawal ratio will be established prior to the control
period for which it would apply. The withdrawal ratio will be
calculated by dividing 10 percent of the total trading program budget
by the total number of banked allowances. This ratio will be applied to
each compliance or overdraft account (only accounts used for
compliance) holding banked allowances as of the allowance transfer
deadline at the end of the control period for which it applies. Banked
allowances in each account may be used for compliance on a one-for-one
basis in an amount not exceeding the amount established by the
withdrawal ratio. Banked allowances used in an amount exceeding that
established by the withdrawal ratio must be used on a two-for-one
basis. By setting the withdrawal ratio prior to the applicable control
period (in years flow control is triggered) and applying it at the time
of compliance certification at the end of the applicable control
period, sources have one full control period to incorporate the value
of using banked allowances into their operations.
As described above, the NO_X Budget Trading Program
applies the flow control mechanism on a regional basis and establishes
a 2-for-1 discount for banked allowances that are used in an amount
greater than the flow control limit. The regional approach for applying
flow control was selected over the source-by-source approach for the
following reasons:
. EPA believes this option provides more flexibility to
individual sources than the source-by-source approach. If the 10
percent limit were placed on each source based on the source's
allocation, the limit would be in effect every year for every source,
even when the amount of banked allowances throughout the entire trading
region was below 10 percent of the regional trading budget. In
contrast, the regional approach only applies flow control when the
amount of banked allowances throughout the region (entire multi-state
trading area) exceeds the 10 percent limit. In response to the
commenter suggesting that the regional approach penalizes all
participants in the trading program for the excess banking of
individual participants, EPA notes that it would be difficult for a few
sources to cause the entire regional bank to exceed 10 percent of the
budget. In addition, based on the analyses presented in the RIA, EPA
does not anticipate that flow control is likely to be triggered.
Consequently, flow control is more of an insurance policy, rather than
a provision that is routinely expected to be operational.
. The regional approach also provides flexibility to sources
if and when it is triggered. Because the withdrawal ratio is set before
the applicable control period but not applied until the control
period's allowance transfer deadline, sources have over seven months to
manage the amount of banked allowances they use on a 1-for-1 basis
versus a 2-for-1 basis.
. EPA believes the regional approach is also a more
universal approach than the source-by-source approach under a variety
of allocation programs that States may use in the NO_X Budget
Trading Program. To apply the flow control mechanism on a source-by-
source basis, the 10 percent limit would be applied to each source's
allocation. In this way, a source could use an amount of banked
allowances up to 10 percent of it's allocation without restrictions.
Restrictions would be placed on banked allowances that the source uses
in an amount greater than 10 percent of its allocation. Under certain
allocation programs, States may choose not to allocate NO_X
allowances to new sources and require that these sources obtain the
necessary amount of NO_X allowances for compliance from the
market. By not having an allocation of NO_X allowances, new
sources would be prevented from using banked allowances under the
source-by-source approach. EPA believes that approaches to accommodate
sources without a fixed allocation under the source-by-source flow
control approach would overly complicate the system.
. The regional approach for applying flow control is also
the approach used in the Ozone Transport Commission's (OTC) trading
program. Because the NO_X Budget Trading Program is designed
to include States currently operating in the OTC program, using the
same approach for flow control will minimize the disruption for these
sources to convert to the NO_X Budget Trading Program.
The other issue for flow control is the type of restriction to
place on banked allowances used in an amount greater than the 10
percent limit. The NO_X Budget Trading Program includes the
2-for-1 discount as the applicable

[[Page 57474]]

restriction. EPA agrees with the commenters that favored this approach
over using an absolute limit. The EPA believes the 2-for-1 discount
provides more flexibility for sources to achieve compliance than is
offered by the absolute limit. The discount is also beneficial to the
environment, when triggered, by allowing only one ton of NO_X
emissions for every two tons removed. Additionally, the OTC program
uses the 2-for-1 discount.
The following example illustrates how flow control will be used.
For the year 2006, assume the total trading program budget across all
States equals 300,000 allowances and 35,000 allowances are banked from
control periods prior to the 2006 control period. Since more than 10
percent (35,000/300,000 = 11.7%) of the total trading program budget is
banked, a withdrawal ratio will be established prior to the 2006
control period and will apply to all compliance and overdraft accounts
(only accounts that may be used for compliance) holding banked
allowances at the end of the 2006 control period. In this case, the
withdrawal ratio would be 0.86 (determined by dividing 10 percent of
the total trading program budget by the total number of banked
allowances, or 30,000/35,000). Thus if a source holds 1,000 banked
allowances at the end of the 2006 control period, it will be able to
use 860 on a 1-for-1 basis, but will have to use the remaining 140, if
necessary, on a 2-for-1 basis. As a result, if the source used all its
banked allowances for compliance in the 2006 control period, the 1,000
banked allowances could be used to cover only 930 tons of
NO_X emissions (860 + 140/2). Of course, a source could buy
additional current year allowances to cover emissions on a 1-for-1
basis or buy additional banked allowances (allowances not needed by
other sources for compliance) to increase the amount of banked
allowances it may use on a 1-for-1 basis.
3. Early Reduction Credits
As described in section III.F.7.c., the majority of commenters
generally supported the option of awarding early reduction credits. EPA
is allowing, but not requiring, States to grant early reduction credits
to sources for reductions in ozone season NO_X emissions
prior to the 2003 ozone season. States may issue early reduction
credits in an amount not exceeding the State's compliance supplement
pool. The compliance supplement pool is further explained in section
III.F.6.
Based on the support the commenters on the NO_X Budget
Trading Program expressed for early reduction credits, EPA is including
optional provisions in the trading program that States may use for
issuing credits. States participating in the NO_X Budget
Trading Program that choose to issue early reduction credits may follow
the methodology included in part 96 or may develop their own
methodology, provided the State's program meets the following
requirements. The State program must ensure that early reduction
credits will not be issued in an amount exceeding the State's
compliance supplement pool. The State program must also meet the
criteria for early reduction credits discussed in section III.F.7.c.
Finally, the State should notify EPA of the amount of credits issued to
particular NO_X Budget units by no later than May 1, 2003.
Early reduction credits shall be issued to units as allowances for the
2003 control period. For purposes of the banking provisions, the
allowances will not be considered banked in the 2003 control period.
However, any unused allowances carried from the 2003 control period to
the 2004 control period shall be considered banked as will be the case
for all unused allowances carried over to the next control period. Per
the requirements discussed in section III.F.7.c., allowances issued for
early reduction credits may be used for compliance by sources in the
2003 and 2004 control periods. Any of these allowances that are not
used for compliance in the 2003 or 2004 control periods shall be
retired by EPA from the account in which they are held.
As discussed in Section III.F.6.b.ii., States also have the option
of issuing some or all of the State's compliance supplement pool
directly to sources according to the criteria for direct distribution.
Consequently, States participating in the NO_X Budget Trading
Program may also use the direct distribution option for issuing the
compliance supplement pool. In this case, the State must notify EPA by
May 1, 2003 of the specific NO_X Budget units that will be
receiving the direct distribution.
4. Optional Methodology for Issuing Early Reduction Credits
The methodology described below is an optional methodology included
in part 96 that States participating in the NO_X budget
Trading Program and choosing to issue early reduction credits may
follow. States participating in the NO_X Budget Trading
Program may also choose to develop their own methodology as discussed
above. The following methodology is designed to meet the criteria for
issuing early reduction credits discussed in section III.F.7.c. and to
provide incentives for a State's NO_X budget units to
generate early credits in an amount no greater than the size of the
State's compliance supplement pool. The State may choose to issue the
entire compliance supplement pool as early reduction credits through
this methodology, or the State may choose to reserve some of the
compliance supplement pool to be issued to sources according to the
direct distribution criteria as described above.
This methodology is applicable for reductions made during the 2001
and 2002 ozone seasons. NO_X budget units that request early
reduction credits will be required to monitor ozone season
NO_X emissions according to the monitoring provisions of part
75, subpart H by the 2000 ozone season. The information from the 2000
ozone season shall be used to establish a baseline emission rate for
the NO_X budget unit. To be eligible for early reduction
credits, a NO_X budget unit shall reduce its emissions rate
in the 2001 and/or 2002 control period(s) no less than 20 percent below
its baseline emissions rate established for the 2000 ozone season. The
size of the early reduction credit request shall equal the difference
between 0.25 lb/mmBtu and the unit's actual emissions rate multiplied
by the unit's actual heat input for the applicable control period.
NO_X Budget units requesting early reduction credits should
submit the request to the State by no later than October 30 of the year
for which the early reductions were generated.
The methodology conforms with the NO_X SIP call's
criteria for early reduction credits. By requiring that the reductions
be measured using provisions in part 75, the reductions will be
verified as having actually occurred and will be quantified according
to the same procedures as required for compliance with the general
requirements of the NO_X Budget Trading Program. The
procedure for calculating the credit request is intended to ensure that
the reductions are surplus. Phase II of the title IV NO_X
emissions limits are required to be installed at specific coal-fired
boilers by January 1, 2000. By requiring that an early reduction credit
must be generated by no less than a 20 percent reduction below the 2000
baseline emission rate, credits will only be issued for reductions that
go below emissions levels achieved for compliance with title IV
requirements. This provision ensures that the early reduction credits
are only issued for reductions below existing requirements (i.e., surplus).
Calculating the early credit based on the difference between 0.25
lb/mmBtu

[[Page 57475]]

and the unit's actual emissions rate establishes a standard emissions
rate from which all early reduction credits are calculated. This
approach ensures that sources with higher NO_X emissions
rates prior to the 2001 ozone season are not provided an opportunity to
generate more early reduction credits than relatively cleaner sources.
In this way, all sources have an equal opportunity to generate early
reduction credits below a standard emissions rate.
According to the requirements in the NO_X SIP call,
States may not issue early reduction credits in an amount greater than
the State's compliance supplement pool. To ensure this provision is
met, the optional methodology is designed for States to issue all early
reduction credits following the 2002 ozone season. By October 30, 2002,
a State will have received all early reduction requests for both the
2001 and 2002 ozone seasons. After review of the requests, the State
would issue credit to all valid requests according to the following
procedure. If the amount of valid requests is less than the size of the
State's compliance supplement pool, the State would issue one allowance
for each ton of early reduction credit requested. If the amount of
valid requests is more than the size of the State's pool, the State
would reduce the amount in the credit requests on a pro-rata basis so
that the requests equal the size of the State's pool. After the
requests have been reduced, the State would then issue allowances based
on the remaining size of each credit request. States would complete the
issuance of allowances for the early reduction credit requests as soon
as possible following October 30, 2002, but no later than May 1, 2003.
5. Integrating the OTC Program With the NO_X Budget Trading
Program's Banking Provisions
The OTC NO_X Budget Program is a multi-state, capped
NO_X trading program that begins in 1999 and includes many
States subject to today's action. By the start of the NO_X
Budget Trading Program under the NO_X SIP call, sources in
the OTC program will potentially hold banked NO_X allowances
resulting from early reductions and/or overcontrol with program
requirements. At issue is the ability of OTC sources to use these
banked allowances in the NO_X Budget Trading Program.
Commenters have supported allowing OTC sources to use banked
allowances (i.e., early reductions from the 1997 and 1998 ozone seasons
and unused allowances from the 1999 through 2002 ozone seasons) from
the OTC program for compliance in the NO_X Budget Trading
Program. Commenters have stated that because OTC sources will be
subject to a market-based cap-and-trade program prior to the 2003 ozone
season, it is important to create a smooth transition from the OTC
program to the NO_X Budget Trading Program. They have
suggested discounting OTC Phase II allowances to make them equivalent
to those achieved under the NO_X SIP call. One OTC State
suggested accomplishing this by adjusting the OTC banked allowances by
a ratio of the Phase II OTC control requirement to the Phase III OTC
control requirement, working with EPA to determine the exact ratio. A
few OTC States suggested that OTC allowances banked in Phase II could
be used as early reduction credits in the NO_X Budget Trading
Program. A commenter from outside the OTC voiced concern that the use
of OTC allowances banked by sources for the years 1999 through 2002
could distort the larger trading market established under the SIP call.
The EPA believes that the compliance supplement pool provides the
opportunity to integrate the OTC program into the NO_X Budget
Trading Program by allowing OTC States to bring their banked allowances
into the NO_X Budget Trading Program as early reduction
credits after the 2002 ozone season. The EPA established two primary
criteria for the generation of early reduction credits in III.F.7.c.:
first, the credits must be surplus, verifiable, and quantifiable; and
second, a State may not grant an amount of early reduction credits in
excess of a State's compliance supplement pool. EPA believes that
banked allowances held by sources in the OTC program would qualify as
being surplus, verifiable, and quantifiable. The banked allowances
would be surplus because they would represent emissions reductions that
go beyond what is required by the emissions limitations established by
the OTC program in the applicable ozone seasons. The banked allowances
would also be verified and quantified according to the procedures in
the OTC program which are essentially identical to the requirements
that will be in place under the NO_X Budget Trading Program.
As for the second criterion that a State issue no more early
reduction credits than provided through the compliance supplement pool,
EPA believes this could be addressed according to the following
procedure. If the number of banked allowances held by an OTC State's
NO_X Budget units, after the compliance certification process
for the 2002 ozone season, is less than the number of credits available
in the pool for that State, the NO_X budget units in that
State may carry all of their banked allowances from the OTC program
into the NO_X Budget Trading Program. The banked allowances
brought in from the OTC program would be subtracted from the State's
compliance supplement pool. Any remaining credits in the compliance
supplement pool could be distributed by the OTC State through the
direct distribution option, if necessary. If, on the other hand, an OTC
State's NO_X Budget units hold banked allowances from the OTC
program in excess of the amount of credits in the State's pool, after
the compliance certification process for the 2002 ozone season, the
State would need to reduce the amount of allowances eligible for being
carried into the NO_X Budget Trading Program. This could be
achieved by reducing the amount of banked allowances held by the units
on a pro rata basis so that the number of allowances carried into the
NO_X Budget Trading Program is less than or equal to the size
of the State's compliance supplement pool.
The process described above provides a mechanism for OTC States to
use the compliance supplement pool to carry banked allowances from the
OTC program as of the end of the compliance period in 2002 over into
the NO_X Budget Trading Program. The EPA believes this
integration acknowledges the important reductions made in the OTC
program prior to 2003 while providing similar opportunities for sources
outside the OTC to generate credits for early reductions. Since all
States in the NO_X Budget Trading Program will have an
opportunity to receive credit for early reductions, EPA does not
believe any market distortion will occur.

G. New Source Review

Under the New Source Review (NSR) provisions of section 173 of the
CAA, a new major source or a major modification to an existing major
source of a particular pollutant that proposes to locate in an area
designated nonattainment for that pollutant must offset its new
emissions. In the SNPR, the EPA solicited comment on whether and how
the offset requirement could be met by sources' participation in the
NO_X Budget Trading Program. The Agency stated its belief
that sources obligated to obtain NO_X offsets under the NSR
program should be able to do so by acquiring NO_X allowances
through the trading program. In essence, the EPA reasoned that, where a
trading program is a capped system, a new source's acquisition of
allowances to cover its increased emissions would necessarily

[[Page 57476]]

result in actual emissions reductions elsewhere in the system.
The EPA continues to believe that nonattainment NSR offset
requirements of the CAA can be met using the mechanism of the
NO_X Budget Trading Program. However, there are a number of
complex issues involved with integrating these programs, for example,
the statutory requirements to obtain offsets from certain geographic
areas and, depending on the classification of the 1-hour ozone
nonattainment area, at certain offset ratios. Because the Agency is
continuing to evaluate these issues, it will not be providing guidance
at this time on integrating these programs; however, the EPA intends to
provide such guidance as soon as possible. At that time, the EPA will
respond to the comments received on this topic in the course of this
rulemaking.

VIII. Interaction With Title IV NO_X Rule

The EPA proposed, in the May 11, 1998 supplemental notice, to add a
new Sec. 76.16 to part 76, the Acid Rain NO_X Emission
Reduction Program regulations. The purpose of the proposed Sec. 76.16
was to increase utilities' flexibility in situations where units owned
or operated by a utility were subject to both a NO_X cap-and-
trade program and the Phase II NO_X emission limitations
under the Acid Rain NO_X Emission Reduction Program. Under
proposed Sec. 76.16, a State or group of States could request that the
Administrator relieve all units located in the State or States and
otherwise subject to the Phase II NO_X emission limitations
(under Secs. 76.6 and 76.7) of the requirement to comply with such
emission limitations. The Administrator could also take this action on
his or her own motion. All Group 1 boilers (i.e., tangentially fired or
dry bottom wall fired boilers) would remain subject to the Phase I
NO_X emission limitations (under Sec. 76.5), while Group 2
boilers (i.e., cell burner boilers, cyclones, wet bottom boilers, and
vertically fired boilers) would have no NO_X limits under the
Acid Rain Program. This relief would be available if all such units
were subject, under a SIP or a FIP, to a NO_X cap-and-trade
program meeting certain requirements. The NO_X cap-and-trade
program had to include, inter alia, either an annual cap or seasonal
caps that together limited total annual emissions and a requirement
that each unit use authorizations to emit (or allowances) to account
for all NO_X emissions. In addition, there had to be a
demonstration that total annual NO_X emissions from all units
otherwise subject to the Acid Rain NO_X emission limitations
and located in the State or group of States would, under the
NO_X cap-and-trade program, be equal to or lower than the
total number of annual NO_X emissions if the units remained
subject to the Acid Rain NO_X emission limitations.
Alternative emission limitations and NO_X averaging plans
under part 76 would not be taken into account in such a demonstration.
Although the purpose of proposed Sec. 76.16 was to provide more
flexibility to utilities consistent with the requirements of section
407, almost all utility commenters and many State and State agency
commenters opposed the proposal. Many commenters argued that relieving
a utility's units in one State of the applicability of the Phase II
NO_X emission limitation would prevent the utility from using
those units, along with units that the utility owns or operates in
other States, in an interstate averaging plan under the Acid Rain
Nitrogen Oxides Emission Reduction Program. Under section 407(e) of the
CAA, as implemented under Sec. 76.11, a utility may comply with the
Acid Rain NO_X emission limitations by averaging the
emissions of units that the utility owns or operates in the same State
or other States. Many utilities have complied, or plan to comply, with
the Acid Rain NO_X Emission Reduction Program by using
averaging plans, including some interstate averaging plans. However, a
unit that has no Acid Rain emission limitation obviously cannot be
included in an averaging plan since EPA would have no authority under
title IV to limit the unit's emissions, whether on an individual-unit
or a group-average basis. Further, as a practical matter, the group
average limit for any given year, which must be calculated based on the
limit applicable to each individual unit in the averaging plan, could
not reflect any limit for such a unit. See 40 CFR 76.11(a) (1) and (2)
(allowing only units with Acid Rain NO_X emission limitations
in effect to participate in an averaging plan) and (d)(1)(ii)(A)
(showing calculation of the group average limit using each unit's Acid
Rain NO_X emission limitation).
In the proposal, EPA attempted to address the issue of the
potential impact of proposed Sec. 76.16 on averaging plans. Proposed
Sec. 76.16(b)(1)(ii) required that, in determining whether a
NO_X cap-and-trade program met the requirements for granting
units relief from the Phase II NO_X emission limitations, the
Administrator must consider ``whether the cost savings from trading
will be offset by elimination of the ability of an owner or operator of
a unit in the State or the group of States to use a NO_X
averaging plan under Sec. 76.11.'' 63 FR 25974. However, commenters
were still concerned that the Administrator could, even after taking
this into consideration, grant the relief over a utility's objections
and prevent the utility from using an averaging plan that included the
units for which the Administrator made the Phase II NO_X
emission limitations inapplicable. In light of the utilities' concerns
that proposed Sec. 76.16 would actually reduce utilities' compliance
flexibility, albeit under title IV, and prevent the use of averaging
plans authorized under section 407(e), EPA has decided not to revise
part 76 as proposed and is not adopting proposed Sec. 76.16 as a final
rule.
Suggestions by some commenters that, instead of adopting proposed
Sec. 76.16, EPA extend the compliance date under the Acid Rain Program
for the Phase II NO_X emission limitations are rejected as
outside the scope of this rulemaking. As acknowledged by commenters,
that issue was raised in the rulemaking adopting the Phase II
NO_X emission limitations, and the compliance deadline of
January 1, 2000 set in that rulemaking was recently upheld by the
courts in Appalachian Power v. EPA, 135 F.3d 791 (D.C. Cir. 1998). The
SIP call rulemaking did not include any proposal to alter that date. On
the contrary, EPA stated in the SIP call:
Obviously, in proposing a new 40 CFR 76.16, EPA is not requesting
comment on any aspect of the December 19, 1996 final rule [i.e., the
rule that set the Phase II NO_X emission limitations and that
included an earlier, proposed version of Sec. 76.16], including any
issues addressed by the Court in Appalachian Power. 63 FR 25951.
Similarly, commenters' suggestions concerning other revisions to
the Acid Rain NO_X Emission Reduction Program regulations
(e.g., revisions to change the averaging provisions in the Acid Rain
regulations to allow averaging among units that lack common owners or
operators) are rejected as outside the scope of this rulemaking.

IX. Non-Ozone Benefits of NO_X Emissions Decreases

A. Summary of Comments

One commenter suggested that drinking water nitrate is not affected
by atmospheric emissions and that the impacts of eutrophication are
unknown, although no evidence was presented. Another commenter stated
that EPA should estimate in the RIA the benefits of the SIP call with
respect to the non-ozone impacts. One comment was received stating that
EPA should not consider non-ozone benefits as

[[Page 57477]]

justification for the proposed emission reductions.

B. Response to Comments and Conclusion

1. Drinking Water Nitrate
There is no disagreement that high levels of nitrate in drinking
water is a health hazard, especially for infants. The contribution of
atmospheric nitrogen (N) deposition to elevated levels of nitrate in
drinking water supplies can be described as an evolving impact area.
The Ecological Society of America has included discussion of this
impact in a recent major review of causes and consequences of human
alteration of the global N cycle in its Issues in Ecology series
(Vitousek, Peter M., John Aber, Robert W. Howarth, Gene E. Likens, et
al. 1997. Human Alteration of the Global Nitrogen Cycle: Causes and
Consequences. Issues in Ecology. Published by Ecological Society of
America, Number 1, Spring 1997). For decades, N concentrations in major
rivers and drinking water supplies have been monitored in the United
States, Europe, and other developed regions of the world. Analysis of
these data confirms a substantial rise of N levels in surface waters,
which are highly correlated with human-generated inputs of N to their
watersheds. These N inputs are dominated by fertilizers and atmospheric
deposition.
Increases in atmospheric N deposition to sensitive forested
watersheds approaching N saturation would be expected to result in
increased nitrate concentrations in stream water. This phenomenon has
been documented in the Los Angeles, California area and has been well-
established for areas in Germany and the Netherlands (Riggan, P.J.,
R.N. Lockwood, and E.N. Lopez, ``Deposition and Processing of Airborne
Nitrogen Pollutants in Mediterranean-Type Ecosystems of Southern
California'' Environmental Science and Technology, vol. 19, 1985).
Stream water nitrate concentrations in watersheds subject to chronic
air pollution in the Los Angeles area were two to three orders of
magnitude greater than in chaparral regions outside the air basin.
2. Eutrophication
The EPA believes that the eutrophication problem associated with
atmospheric nitrogen deposition is well established. The National
Research Council recently identified eutrophication as the most serious
pollution problem facing the estuarine waters of the United States
(NRC, 1993). NO_X emissions contribute directly to the
widespread accelerated eutrophication of United States coastal waters
and estuaries. Atmospheric nitrogen deposition onto surface waters and
deposition to watershed and subsequent transport into the tidal waters
has been documented to contribute from 12 to 44 percent of the total
nitrogen loadings to United States coastal water bodies. Nitrogen is
the nutrient limiting growth of algae in most coastal waters and
estuaries. Thus, addition of nitrogen results in accelerated algae and
aquatic plant growth causing adverse ecological effects and economic
impacts that range from nuisance algal blooms to oxygen depletion and
fish kills.
3. Regulatory Impact Analysis
The EPA believes it is important to note the potential impacts of
the rulemaking, including the substantial benefits to the environment
of several non-ozone impacts. As described in the November 7 proposal,
in addition to contributing to attainment of the ozone NAAQS, decreases
of NO_X emissions will also likely help improve the
environment in several important ways: (1) On a national scale,
decreases in NO_X emissions will also decrease acid
deposition, nitrates in drinking water, excessive nitrogen loadings to
aquatic and terrestrial ecosystems, and ambient concentrations of
nitrogen dioxide, particulate matter and toxics; and (2), on a global
scale, decreases in NO_X emissions will, to some degree,
reduce greenhouse gases and stratospheric ozone depletion. These
benefits were also specifically recognized by OTAG, which in its July
8, 1997 final recommendations, stated that it ``recognizes that
NO_X controls for ozone reductions purposes have collateral
public health and environmental benefits, including reductions in acid
deposition, eutrophication, nitrification, fine particle pollution, and
regional haze.'' However, the benefits of some of these impacts are
very difficult to estimate. Where possible, EPA provides estimates of
the impacts of the rulemaking--both ozone and non-ozone--in the RIA.
4. Justification for Rulemaking
While EPA believes this information is important for the public to
understand and, thus, needs to be described as part of the rulemaking
and RIA, there should be no misunderstanding as to the legal basis for
the rulemaking, which is described in Section I, Background, of this
notice and does not depend on the non-ozone benefits. The non-ozone
benefits did not affect the method in which EPA determined significant
contribution nor the calculation of the emissions budgets.

X. Administrative Requirements

A. Executive Order 12866: Regulatory Impacts Analysis

Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Agency must determine whether a 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.
In view of its important policy implications and potential effect
on the economy of over $100 million, this action has been judged to be
a ``significant regulatory action'' within the meaning of the Executive
Order. As a result, the final rulemaking was submitted to OMB for
review, and EPA has prepared a Regulatory Impact Analysis (RIA)
entitled ``Regulatory Impact Analysis for the Regional NO_X
SIP Call (September 1998).''
This RIA assesses the costs, benefits, and economic impacts
associated with potential State implementation strategies for complying
with this rulemaking. Any written comments from OMB to EPA and any
written EPA response to those comments are included in the docket. The
docket is available for public inspection at the EPA's Air Docket
Section, which is listed in the ADDRESSES Section of this preamble. The
RIA is available in hard copy by contacting the EPA Library at the
address under ``Availability of Related Information'' and in electronic
form as discussed above under ``Availability of Related Information.''
The RIA attempts to simulate a possible set of State implementation
strategies and estimates the costs and benefits associated with that set of

[[Page 57478]]

strategies. The RIA concludes that the national annual cost of possible
State actions to comply with the SIP call are approximately $1.7
billion (1990 dollars). The associated benefits, in terms of
improvements in health, crop yields, visibility, and ecosystem
protection, that EPA has quantified and monetized range from $1.1
billion to $4.2 billion. Due to practical analytical limitations, the
EPA is not able to quantify and/or monetize all potential benefits of
this action.

B. Regulatory Flexibility Act: Small Entity Impacts

The Regulatory Flexibility Act (5 U.S.C. 601 et seq.) (RFA), as
amended by the Small Business Regulatory Enforcement Fairness Act (Pub.
L. No. 104-121) (SBREFA), provides that whenever an agency is required
to publish a general notice of proposed rulemaking, it must prepare and
make available an initial regulatory flexibility analysis, unless it
certifies that the proposed rule, if promulgated, will not have ``a
significant economic impact on a substantial number of small
entities.'' 5 U.S.C. 605(b). Courts have interpreted the RFA to require
a regulatory flexibility analysis only when small entities will be
subject to the requirements of the rule. See, Motor and Equip. Mfrs.
Ass'n v. Nichols, 142 F.3d 449 (D.C. Cir. 1998); United Distribution
Cos. v. FERC, 88 F.3d 1105, 1170 (D.C. Cir. 1996); Mid-Tex Elec. Co-op,
Inc. v. FERC, 773 F.2d 327, 342 (D.C. Cir. 1985) (agency's
certification need only consider the rule's impact on entities subject
to the rule).
The NO_X SIP Call would not establish requirements
applicable to small entities. Instead, it would require States to
develop, adopt, and submit SIP revisions that would achieve the
necessary NO_X emissions reductions, and would leave to the
States the task of determining how to obtain those reductions,
including which entities to regulate. Moreover, because affected States
would have discretion to choose which sources to regulate and how much
emissions reductions each selected source would have to achieve, EPA
could not predict the effect of the rule on small entities.
For these reasons, EPA appropriately certified that the rule would
not have a significant impact on a substantial number of small
entities. Accordingly, the Agency did not prepare an initial RFA for
the proposed rule.
For the final rule, EPA is confirming its initial certification.
However, the Agency did conduct a more general analysis of the
potential impact on small entities of possible State implementation
strategies. This analysis is documented in the RIA. The EPA did receive
comments regarding the impact on small entities. These comments will be
addressed in the Response to Comment document.
This final rule will not have a significant impact on a substantial
number of small entities because the rule does not establish
requirements applicable to small entities. Therefore, I certify that
this action will not have a significant impact on a substantial number
of small entities.

C. Unfunded Mandates Reform Act

Title II of the Unfunded Mandates Reform Act of 1995 (Pub. L. 104-
4) (UMRA), establishes requirements for Federal agencies to assess the
effects of their regulatory actions on State, local, and tribal
governments and the private sector. Under section 202 of the UMRA, 2
U.S.C. 1532, EPA generally must prepare a written statement, including
a cost-benefit analysis, for any proposed or final rule that ``includes
any Federal mandate that may result in the expenditure by State, local,
and tribal governments, in the aggregate, or by the private sector, of
$100,000,000 or more * * * in any one year.'' A ``Federal mandate'' is
defined under section 421(6), 2 U.S.C. 658(6), to include a ``Federal
intergovernmental mandate'' and a ``Federal private sector mandate.'' A
``Federal intergovernmental mandate,'' in turn, is defined to include a
regulation that ``would impose an enforceable duty upon State, local,
or tribal governments,'' section 421(5)(A)(i), 2 U.S.C. 658(5)(A)(i),
except for, among other things, a duty that is ``a condition of Federal
assistance,'' section 421(5)(A)(i)(I). A ``Federal private sector
mandate'' includes a regulation that ``would impose an enforceable duty
upon the private sector,'' with certain exceptions, section 421(7)(A),
2 U.S.C. 658(7)(A).
Before promulgating an EPA rule for which a written statement is
needed under section 202 of the UMRA, section 205, 2 U.S.C. 1535, of
the UMRA generally requires EPA to identify and consider a reasonable
number of regulatory alternatives and adopt the least costly, most
cost-effective, or least burdensome alternative that achieves the
objectives of the rule.
The EPA has prepared a written statement consistent with the
requirements of section 202 of the UMRA and placed that statement in
the docket for this rulemaking. Furthermore, as EPA stated in the
proposal, EPA is not directly establishing any regulatory requirements
that may significantly or uniquely affect small governments, including
tribal governments. Thus, EPA is not obligated to develop under section
203 of the UMRA a small government agency plan. Furthermore, as
described in the proposal, in a manner consistent with the
intergovernmental consultation provisions of section 204 of the UMRA
and Executive Order 12875, EPA carried out consultations with the
governmental entities affected by this rule. Finally, the written
statement placed in the docket also contains a discussion consistent
with the requirements of section 205 of the UMRA.
For several reasons, however, EPA is not reaching a final
conclusion as to the applicability of the requirements of UMRA to this
rulemaking action. First, it is questionable whether a requirement to
submit a SIP revision would constitute a federal mandate in any case.
The obligation for a state to revise its SIP that arises out of
sections 110(a) and 110(k)(5) of the CAA is not legally enforceable by
a court of law, and at most is a condition for continued receipt of
highway funds. Therefore, it is possible to view an action requiring
such a submittal as not creating any enforceable duty within the
meaning of section 421(5)(9a)(I) of UMRA (2 U.S.C. 658 (a)(I)). Even if
it did, the duty could be viewed as falling within the exception for a
condition of Federal assistance under section 421(5)(a)(i)(I) of UMRA
(2 U.S.C. 658(5)(a)(i)(I)).
As noted earlier, however, notwithstanding these issues EPA has
prepared the statement that would be required by UMRA if its statutory
provisions applied and has consulted with governmental entities as
would be required by UMRA. Consequently, it is not necessary for EPA to
reach a conclusion as to the applicability of the UMRA requirements.
The analysis assumes that states would adopt the control strategies
that EPA assumed in its analyses underlying this action. The EPA
further notes that in two related proposals also signed today--one
concerning federal implementation plans if States do not comply with
the SIP call and one concerning the petitions submitted to the Agency
under section 126 of the CAA--EPA is taking the position that the
requirements of UMRA apply because both of those actions could result
in the establishment of enforceable mandates directly applicable to
sources (including sources owned by state and local governments).

D. Paperwork Reduction Act

The information collection requirements in this rule have been
submitted for approval to the Office of

[[Page 57479]]

Management and Budget (OMB) under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. An Information Collection Request (ICR) document
has been prepared by EPA (ICR No. 1857.02) and a copy may be obtained
from Sandy Farmer by mail at Regulatory Information Division; U.S.
Environmental Protection Agency (2137); 401 M St., SW., Washington, DC
20460, by email at farmer.sandy@epa.gov, or by calling (202) 260-2740.
A copy may also be downloaded from the internet at http://www.epa.gov/
icr. The information requirements are not effective until OMB approves them.
The EPA believes that it is essential that compliance with the
regional control strategy be verified. Tracking emissions is the
principal mechanism to ensure compliance with the budget and to assure
the downwind affected States and EPA that the ozone transport problem
is being mitigated. If tracking and periodic reports indicate that a
State is not implementing all of its NO_X control measures
beginning with the compliance date for NO_X controls or is
off track to meet its statewide budget by September 30, 2007, EPA will
work with the State to determine the reasons for noncompliance and what
course of remedial action is needed.
The reporting requirements are mandatory and the legal authority
for the reporting requirements resides in section 110(a) and 301(a) of
the CAA. Emissions data being requested in today's rule is not be
considered confidential by EPA. Certain process data may be identified
as sensitive by a State and are then treated as ``State-sensitive'' by EPA.
The reporting and record keeping burden for this collection of
information is described below:
Respondents/Affected Entities: States, along with the District of
Columbia, which are included in the NO_X SIP call.
Number of Respondents: 23.
Frequency of Response: annually, triennially.
Estimated Annual Hour Burden per Respondent: 269.
Estimated Annual Cost per Respondent: $7,140.00.
Estimated Total Annual Hour Burden: 6,197.
Estimated Total Annualized Cost: $164,190.00.
There are no additional capital or operating and maintenance costs
for the States, along with the District of Columbia, associated with
the reporting requirements of this rule. During the 1980s, an EPA
initiative established electronic communication with each State
environmental agency. This included a computer terminal for any States
needing one in order to communicate with the EPA's national data base
systems. Costs associated with replacing and maintaining these
terminals, as well as storage of data files, have been accounted for in
the ICR for the existing annual inventory reporting requirements (OMB #
2060-0088).
Burden means the total time, effort, or financial resources
expended by persons to generate, maintain, retain, or disclose or
provide information to or for a Federal agency. This includes the time
needed to review instructions; develop, acquire, install, and utilize
technology and systems for the purposes of collecting, validating, and
verifying information, processing and maintaining information, and
disclosing and providing information; adjust the existing ways to
comply with any previously applicable instructions and requirements;
train personnel to be able to respond to a collection of information;
search data sources; complete and review the collection of information;
and transmit or otherwise disclose the information.
An Agency may not conduct or sponsor, and a person is not required
to respond to a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations are listed in 40 CFR Part 9 and 48 CFR Chapter 15.
Send comments on the Agency's need for this information, the
accuracy of the provided burden estimates, and any suggested methods
for minimizing respondent burden, including through the use of
automated collection techniques to the Director, Office of Policy,
Regulatory Information Division; U.S. Environmental Protection Agency
(2137); 401 M St., SW.; Washington, DC 20460; and to the Office of
Information and Regulatory Affairs, Office of Management and Budget,
725 17th St., NW., Washington, DC 20503, marked ``Attention: Desk
Officer for EPA.'' Comments are requested by November 27, 1998. Include
the ICR number in any correspondence.

E. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

1. Applicability of E.O. 13045
The Executive Order 13045 applies to any rule that EPA determines
(1) ``economically significant'' as defined under Executive Order
12866, and (2) the environmental health or safety risk addressed by the
rule has a disproportionate effect on children. If the regulatory
action meets both criteria, the Agency must evaluate the environmental
health or safety effects of the planned rule on children; and explain
why the planned regulation is preferable to other potentially effective
and reasonably feasible alternatives considered by the Agency. This
proposed rule is not subject to E.O. 13045, entitled ``Protection of
Children from Environmental Health Risks and Safety Risks (62 FR 19885,
April 23, 1997), because it does not involve decisions on environmental
health risks or safety risks that may disproportionately affect children.
2. Children's Health Protection
In accordance with section 5(501), the Agency has evaluated the
environmental health or safety effects of the rule on children, and
found that the rule does not separately address any age groups.
However, the Agency has conducted a general analysis of the potential
changes in ozone and particulate matter levels experienced by children
as a result of the NO_X SIP call; these findings are
presented in the Regulatory Impact Analysis. The findings include
population-weighted exposure characterizations for projected 2007 ozone
and PM concentrations. The population includes a census-derived
subdivision for the under 18 group.

F. Executive Order 12898: Environmental Justice

Executive Order 12898 requires that each Federal agency make
achieving environmental justice part of its mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects of its programs, policies, and
activities on minorities and low-income populations. The Agency has
conducted a general analysis of the potential changes in ozone and
particulate matter levels that may be experienced by minority and low-
income populations as a result of the NO_X SIP call; these
findings are presented in the Regulatory Impact Analysis. The findings
include population-weighted exposure characterizations for projected
ozone concentrations and PM concentrations. The population includes
census-derived subdivisions for whites and non-whites, and for low-
income groups.

G. Executive Order 12875: Enhancing the Intergovernmental Partnerships

Under Executive Order 12875, EPA may not issue a regulation that is
not required by statute and that creates a mandate upon a State, local
or tribal government, unless the Federal

[[Page 57480]]

government provides the funds necessary to pay the direct compliance
costs incurred by those governments. If the mandate is unfunded, EPA
must provide to the Office of Management and Budget a description of
the extent of EPA's prior consultation with representatives of affected
State, local and tribal governments, the nature of their concerns,
copies of any written communications from the governments, and a
statement supporting the need to issue the regulation. In addition,
Executive Order 12875 requires EPA to develop an effective process
permitting elected officials and other representatives of State, local
and tribal governments ``to provide meaningful and timely input in the
development of regulatory proposals containing significant unfunded
mandates.''
Today's rule does not create a mandate on State, local or tribal
governments. As explained in the discussion of UMRA (Section X.C), this
rule does not impose an enforceable duty on these entities.
Accordingly, the requirements of section 1(a) of Executive Order 12875
do not apply to this rule.

H. Executive Order 13084: Consultation and Coordination With Indian
Tribal Governments

Under Executive Order 13084, EPA may not issue a regulation that is
not required by statute, that significantly or uniquely affects the
communities of Indian tribal governments, and that imposes substantial
direct compliance costs on those communities, unless the government
provides the funds necessary to pay the direct compliance costs
incurred by the tribal governments. If the mandate is unfunded, EPA
must provide to the Office of Management and Budget, in a separately
identified section of the preamble to the rule, a description of the
extent of EPA's prior consultation with representatives of affected
tribal governments, a summary of the nature of their concerns, and a
statement supporting the need to issue the regulation. In addition,
Executive Order 13084 requires EPA to develop an effective process
permitting elected and other representatives of Indian tribal
governments ``to provide meaningful and timely input in the development
of regulatory policies on matters that significantly or uniquely affect
their communities.''
Today's rule does not significantly or uniquely affect the
communities of Indian tribal governments. The rule applies only to
certain States, and does not require Indian tribal governments to take
any action. Moreover, EPA does not, by today's rule, call on States to
regulate NO_X sources located on tribal lands. Accordingly,
the requirements of section 3(b) of Executive Order 13084 do not apply
to this rule.
The only circumstance in which the rule might even indirectly
affect sources on tribal lands would be if the budget set for one or
more of the 23 jurisdictions reflects assumed emissions reductions from
NO_X sources on tribal lands located within the exterior
boundaries of those States. The EPA is not aware of any such sources.
However, to address the possibility that one or more of the State
budgets reflects reductions from such sources, and because any such
State generally would not have jurisdiction over such sources (see
EPA's rule promulgated under CAA section 301(d), 63 FR 7254, February
12, 1998), EPA will consider any request to revise as appropriate the
budget and base year 2007 emissions inventory for such a State, based
on a demonstration that the State does not have authority to regulate
those sources.

I. Judicial Review

Section 307(b)(1) of the CAA indicates which Federal Courts of
Appeal have venue for petitions of review of final actions by EPA. This
Section provides, in part, that petitions for review must be filed in
the Court of Appeals for the District of Columbia Circuit if (i) the
agency action consists of ``nationally applicable regulations
promulgated, or final action taken, by the Administrator,'' or (ii)
such action is locally or regionally applicable, if ``such action is
based on a determination of nationwide scope or effect and if in taking
such action the Administrator finds and publishes that such action is
based on such a determination.''
Any final action related to the NO_X SIP call is
``nationally applicable'' within the meaning of section 307(b)(1). As
an initial matter, through this rule, EPA interprets section 110 of the
CAA in a way that could affect future actions regulating the transport
of pollutants. In addition, the NO_X SIP call, as proposed,
would require 22 States and the District of Columbia to decrease
emissions of NO_X. The NO_X SIP call also is based
on a common core of factual findings and analyses concerning the
transport of ozone and its precursors between the different States
subject to the NO_X SIP call. Finally, EPA has established
uniform approvability criteria that would be applied to all States
subject to the NO_X SIP call. For these reasons, the
Administrator also is determining that any final action regarding the
NO_X SIP call is of nationwide scope and effect for purposes
of section 307(b)(1). Thus, any petitions for review of final actions
regarding the NO_X SIP call must be filed in the Court of
Appeals for the District of Columbia Circuit within 60 days from the
date final action is published in the Federal Register.

J. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. The EPA will submit 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 United States prior
to publication of the rule in the Federal Register. A ``major rule''
cannot take effect until 60 days after it is published in the Federal
Register. This action is a ``major rule'' as defined by 5 U.S.C.
Sec. 804(2). This rule will be effective December 28, 1998.

K. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Pub. L. No. 104-113, section 12(d) (15 U.S.C. 272
note) directs EPA to use voluntary consensus standards in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. Voluntary consensus standards
are technical standards (e.g., materials specifications, test methods,
sampling procedures, and business practices) that are developed or
adopted by voluntary consensus standards bodies. The NTTAA directs EPA
to provide Congress, through OMB, explanations when the Agency decides
not to use available and applicable voluntary consensus standards.
This final rulemaking sets forth a model trading program including
environmental monitoring and measurement provisions that States are
encouraged to adopt as part of their SIPs. If States adopt those
provisions, sources that participate in the trading program would be
required to meet the applicable monitoring requirements of part 75. In
addition, this final rulemaking requires States that choose to regulate
certain large stationary sources to meet the requirements of the SIP
call to use part 75 to ensure compliance with their regulations. Part
75 already incorporates a number of voluntary consensus standards. In

[[Page 57481]]

addition, EPA's proposed revisions to part 75 proposed to add two more
voluntary consensus standards to the rule (see 63 FR at 28116-17,
discussing ASTM D5373-93 ``Standard Methods for Instrumental
Determination of Carbon, Hydrogen and Nitrogen in laboratory samples of
Coal and Coke,'' and API Section 2 ``Conventional Pipe Provers'' from
Chapter 4 of the Manual for Petroleum Measurement Standards, October
1988 edition). The EPA's proposed revisions to part 75 also requested
comments on the inclusion of additional voluntary consensus standards.
The EPA is finalizing some revisions to part 75 now, including the
incorporation of two voluntary consensus standards, in response to
comments submitted on the proposed part 75 rulemaking:
(1) American Petroleum Institute (API) Petroleum Measurement
Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for
the Manual Gauging of Petroleum and Petroleum Products, December 1994;
Section 1B, Standard Practice for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992
(reaffirmed January 1997); Section 2, Standard Practice for Gauging
Petroleum and Petroleum Products in Tank Cars, September 1995; Section
3, Standard Practice for Level Measurement of Liquid Hydrocarbons in
Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June
1996; Section 4, Standard Practice for Level Measurement of Liquid
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995;
and Section 5, Standard Practice for Level Measurement of Light
Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging,
March 1997; for Sec. 75.19 and,
(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B,
December 1961 (Reaffirmed October 1992), for Sec. 75.19.
These materials are available for purchase from the following
address: American Petroleum Institute, Publications Department, 1220 L
Street NW, Washington, DC 20005-4070.
These standards are used to quantify fuel use from units that have
low emissions of NO_X and SO_X.
The EPA intends to finalize other revisions to part 75 in the near
future and address comments related to the proposed voluntary consensus
standards and to additional voluntary consensus standards at that time.
Consistent with the Agency's Performance Based Measurement System,
part 75 sets forth performance criteria that allow the use of
alternative methods to the ones set forth in part 75. The PBMS approach
is intended to be more flexible and cost effective for the regulated
community; it is also intended to encourage innovation in analytical
technology and improved data quality. The EPA is not precluding the use
of any method, whether it constitutes a voluntary consensus standard or
not, as long as it meets the performance criteria specified, however
any alternative methods must be approved in advance before they may be
used under part 75.

List of Subjects

40 CFR Part 51

Air pollution control, Administrative practice and procedure,
Carbon monoxide, Environmental protection, Intergovernmental relations,
Nitrogen dioxide, Ozone, Particulate matter, Reporting and
recordkeeping requirements, Sulfur oxides, Transportation, Volatile
organic compounds.

40 CFR Parts 72 and 75

Air pollution control, Carbon dioxide, Continuous emissions
monitors, Electric utilities, Environmental protection, Incorporation
by reference, Nitrogen oxides, Reporting and recordkeeping
requirements, Sulfur dioxide.

40 CFR Part 96

Environmental protection, Administrative practice and procedure,
Air pollution control, Nitrogen dioxide, Reporting and recordkeeping
requirements.

Dated: September 24, 1998.
Carol M. Browner,
Administrator.

Appendix A to the Preamble--Detailed Discussion of Changes to Part 75

The following discussion addresses the comments received both on
the SNPR (68 FR 25902) and the proposed part 75 revisions (68 FR 28032)
that relate to the monitoring of NO_X mass emissions. In
addition, it addresses the comments received on the excepted monitoring
methodology for low mass emitting units that would apply to both units
affected by title IV of the CAA and to units affected by a State or
Federal NO_X mass reduction program that adopted or
incorporated the requirements of this part.

I. NO_X Mass Monitoring and Reporting Provisions

Commenters raised four main issues with the proposed NO_X
mass monitoring and reporting provisions in subpart H. The first issue
has to do with the appropriate monitoring requirements necessary to
support a NO_X mass monitoring program, particularly in light
of the fact that many of the units that would be subject to a program
based on Part 96 are not currently monitoring NO_X mass
emissions. The second has to do with using a NO_X
concentration CEMS and a flow CEMS to calculate NO_X mass.
The third has to do with the requirement to report NO_X mass
emissions year round even though the ozone season is only 5 months
long. The final issue has to do with the requirement to have petitions
for alternatives to part 75 be approved by both the state permitting
authority and by EPA.

A. Background on Use of Part 75 to Monitor and Report NO_X
Mass Emissions

Subpart H of the proposed part 75 rule set forth general monitoring
and reporting requirements that sources subject to a State or Federal
NO_X mass emission reduction program could incorporate or
adopt into that program. Several commenters argued that it was
inappropriate to require sources, who were not already required to meet
the requirements of part 75, to meet those requirements for purposes of
a state program.
Commenters who suggested that it was inappropriate to require a
source that is not already subject to part 75 to meet the requirements
of part 75 for purposes of a state program suggested that the State
should decide what requirements the source needs to meet. The EPA
agrees that this would be appropriate in the case of a program that
only affected that state. For instance, if a State was developing a
NO_X reduction program to address its own non-attainment
problem, it would not be necessary to adopt requirements that were
consistent across a larger geographic area. However, in a multi-state
program, particularly a multi-state trading program which engages in
interstate commerce like the one set forth in part 96, EPA believes it
is necessary to account for emissions in a consistent manner across the
whole region. This ensures that all sources that participate in the
trading program account for their emissions in a consistent manner,
ensuring both integrity in the trading program and a level playing
field for all program participants. Therefore, EPA believes that it is
necessary to create one set of consistent monitoring and reporting
requirements that can be used for such a program. This is consistent
with the way the Act mandated that a multi-state trading program be
implemented under Title IV. It is also consistent with the

[[Page 57482]]

approach taken in implementing other emissions standards, such as the
new source performance standards that affect many states. This approach
also makes it easier for states designing their programs since they
would not have to reinvent the monitoring requirements in each case.
Commenters who suggested that part 75 did not provide enough
flexibility focused on three areas: they suggested that other programs
such as RECLAIM or the OTC trading program provided more flexible non-
CEMS options for units that operated infrequently or had low
NO_X mass emissions; they suggested that sources should be
allowed to use predictive emissions monitoring systems (PEMS); and they
suggested that sources should be allowed to use coal sampling and
weighting to determine heat input.
The EPA believes that the flexibilities offered by part 75 are
consistent with the type of flexibilities offered in RECLAIM and the
OTC Program. RECLAIM requires CEMS on all units that emit more than 10
tons of any individual pollutant per year. The OTC Program requires
CEMS on all units that do not qualify as peaking units that are larger
than 250 mmBtu or serve generators greater than 25 MWs. Subpart H of
part 75 allows non-CEMS alternatives for units that have emissions less
than 50 tons per year of NO_X. If a unit is not required to
report SO₂ and CO₂ for Acid Rain compliance, then
the unit may use the low mass emissions provisions of Part 75 if its
NO_X emissions are less than 50 tons per year. Part 75 also
allows non-CEMS alternatives for units that qualify as peaking units.
In both the OTC Program and part 75, a peaking unit is defined as a
unit that has a capacity factor of no more than 10 percent per year
averaged over a three year period and no more than 20 percent in any
one year. The EPA believes that these options provide cost effective
monitoring methodologies for small or infrequently used units.
While commenters who supported the use of PEMS and the use of coal
sampling and weighting asserted that these methodologies would provide
data equivalent to that provided by the methodologies in Part 75, none
of the commenters provided any data to justify this claim. Therefore
EPA is not adding specific requirements that would allow either of
these methodologies. It should be noted that subpart E of part 75 does
provide a means for a source to demonstrate that an alternative
methodology such as PEMS or coal sampling and weighting is equivalent
to CEMS. Subpart E of part 75 is consistent with Performance Based
Measurement Systems criteria. Any source wishing to use an alterative
methodology may petition the agency under subpart E of part 75.

B. Background on Use of a NO_X Concentration CEMS and a Flow
CEMS to Calculate NO_X Mass

Subpart H of the proposed part 75 rule called for sources in the
NO_X Budget Program to monitor NO_X emission rate
in lb/mmBtu using a NO_X concentration monitor and a diluent
monitor, and then to multiply this by heat input, calculated using a
flow monitor and a diluent monitor. Under this proposal, sources would
then calculate NO_X mass emissions by multiplying the hourly
NO_X emission rate by the hourly heat input to obtain the
pounds of NO_X emitted during the hour. The EPA also
requested comment on whether it would be appropriate for sources in the
NO_X Budget Program to use the NO_X concentration
monitor and flow monitor without a diluent monitor to calculate
NO_X mass emissions. This is analogous to the Acid Rain
Program's current approach to monitoring SO₂ mass emissions.
Commenters recommended that the Agency require sources to determine
NO_X mass emissions from pollutant concentration and stack
gas volumetric flow. The commenters stated that this approach would be
more accurate, more familiar to sources, and more consistent with the
SO₂ mass emissions monitoring in the existing part 75.
The Agency agrees that using NO_X pollutant concentration
and volumetric flow is an appropriate method for monitoring
NO_X mass emissions. Today's final rule includes provisions
in Subpart H and Section 8 of Appendix F of part 75 to allow sources to
choose one of several options for monitoring and calculating
NO_X mass emissions. Sources may monitor NO_X mass
emissions by using either:

All Units

. A NO_X pollutant concentration monitor and a
volumetric flow monitor, or a NO_X concentration monitor and
a diluent monitor to calculate NO_X emission rate in lb/
mmBtu, and a flow monitor and a diluent monitor to calculate heat input; or
. A NO_X concentration monitor and a diluent
monitor to calculate NO_X emission rate in lb/mmBtu, and a
fuel flow meter and oil or gas sampling and analysis to calculate heat
input; or

Oil/Natural Gas Fired Units

. Peaking units may use NO_X to load correlation
procedures from Appendix E of part 75 for NO_X emission rate,
and a fuel flow meter and oil or gas sampling and analysis to calculate
heat input; or
. Units with less than 50 tons of Nox and 25 tons of
SO₂ may use emission rates multiplied by either the maximum
rated heat input capacity of the unit or by the actual heat input of
the unit which may be determined on a longer term basis than a single hour.
The EPA decided to allow sources several options so that they could
use monitoring equipment that is already installed under part 75 to the
greatest extent possible.
In implementing these options, a source would need to designate a
primary approach to calculating NO_X mass emissions. For
example, the designated representative of a coal-fired unit could
choose to designate a primary monitoring approach under Option 1
(pollutant concentration monitor and diluent monitor, and diluent
monitor and flow monitor). The designated representative could then use
a (pollutant concentration monitor and flow monitor) as a backup
monitoring approach. This would be useful for periods when the diluent
monitor is not operating properly, where NO_X emission rate
data in lb/mmBtu would not be available, but NO_X mass
emission data in lb could still be available. The OTC NO_X
Budget Program allows this approach (see docket A-97-35 item II-I-7).
In order to make monitoring as consistent as possible between the
first two approaches for monitoring NO_X mass emissions using
continuous emission monitoring systems (CEMS), EPA is making additional
changes to part 75. First, the Agency is adding language in Section 8
of Appendix F that specifies the calculations for NO_X mass
emissions using either approach. Second, EPA is requiring sources that
use a NO_X pollutant concentration monitor and a flow monitor
as the primary method for calculating NO_X mass emissions to
substitute for missing NO_X pollutant concentration data
using the same missing data procedures as for NO_X CEMS (lb/
mmBtu) under Secs. 75.31(c), 75.33(c) and Appendix C. Third, the Agency
is establishing a relative accuracy testing requirement for
NO_X pollutant concentration monitors that are used to
calculate NO_X mass emissions independently of a
NO_X CEMS (lb/mmBtu). The NO_X pollutant
concentration monitors will need to meet a relative accuracy of 10.0
percent to pass the relative accuracy test audit (RATA). They will need
to meet a relative accuracy of 7.5 percent to perform a RATA on an
annual basis instead of a semi-annual basis. Because the vast majority
of NO_X CEMS (lb/

[[Page 57483]]

mmBtu) and SO₂ pollutant concentration monitors routinely
meet a relative accuracy of 7.5 percent or less, the Agency concludes
that it will also be possible for a NO_X pollutant
concentration monitor, which is part of a NO_X CEMS, to meet
this standard. Fourth, EPA requires these sources to test their
NO_X pollutant concentration monitor and flow monitor for
bias. If the monitor is found to be biased low, then the source must
either fix the monitor and retest it to show it is not biased, or apply
a bias adjustment factor to hourly data. These changes to part 75 make
monitoring consistent between the different monitoring approaches using
CEMS, prevent underestimation of emissions, preserve monitoring
accuracy, and take advantage of approaches already developed for other
monitoring systems that will be familiar to sources.
The EPA decided to allow sources to calculate NO_X mass
emissions using NO_X concentration and flow rate for several reasons:
. This approach would allow sources to remove bias due to
the diluent monitor from calculations of NO_X mass emissions.
. Sources affected by the NO_X Budget Program, but
not by the Acid Rain Program, such as industrial boilers, may be able
to simplify their recordkeeping and reporting because they will not
need to calculate or report NO_X emission rate in lb/mmBtu
for each hour for the trading program.
. Sources will be able to maintain higher availability of
quality-assured NO_X mass emission data, because they will
not need to substitute missing data for purposes of NO_X mass
emissions when data are not available from the diluent monitor.
. As the commenters suggested, this approach is more
analogous to monitoring for SO₂ mass emissions in the Acid
Rain Program.
Because this approach is already allowed under the OTC
NO_X Budget Program, EPA already has accounted for this
possibility in the electronic data reporting format and in its
computerized Emission Tracking System.
For these reasons, the Agency believes that it is appropriate to
allow sources the option of monitoring and calculating NO_X
mass emissions using NO_X pollutant concentration and flow
monitors.
Sources using this approach may still be required to install
maintain and operate a diluent monitor to calculate heat input if
required to do so by their state for purposes of obtaining data needed
to support allocation of NO_X allowances.

C. Background on Year Round Reporting of NO_X Mass Emissions

The proposal would have required all units to report NO_X
mass emissions on an annual basis rather than on an ozone season basis.
One commenter noted that since the proposed SIP call would not require
emission reductions outside of the ozone season it is not necessary to
report NO_X mass emissions outside of the ozone season. The
EPA agrees that solely for the purposes of an ozone program, it may not
be necessary to report NO_X mass emissions outside of the
ozone season except if a source wants to qualify for the low mass
emissions provision. However the requirements of subpart H could be
used to support NO_X mass emission reduction programs where
reductions would be required annually. In addition, the monitoring and
reporting requirements could be used to help consolidate other State or
Federal reporting that would be required on an annual basis. Therefore
in the final rule the requirements of subpart H have been modified so
that they no longer require annual reporting of NO_X mass
emissions, but rather defer to the State or Federal rule that is
incorporating these requirements to define the applicable time period
for reporting.
In addition a new section has been added to subpart H that details
how the requirements of part 75, which are designed to be used
annually, should be used if monitoring and reporting is being done for
only part of the year.
Some of the most significant differences include:
. Owners and operators of units using the fuel sampling
procedures in Appendix D must ensure that they have accurate fuel
sampling information at the beginning of the ozone season. This
requires either sampling the fuel tank itself before the start of the
ozone season or meeting the requirements to sample fuel deliveries on a
year round basis.
. Historical lookback periods for missing data periods only
need to include data from the ozone season. However, if a monitor is
out of control at the beginning of the season, historical data from
seven months ago may represent significantly different operating
conditions (e.g. fuel burned or use of control equipment). Therefore
the AAR would have to certify that the operating conditions are
representative of the previous years operating conditions. If the
conditions are not representative, the standard missing data procedures
could not be used. In this case maximum potential NO_X mass
emissions would have to be substituted.
. The owner or operator of a unit must ensure that the
monitors used for monitoring and reporting are in control. Since CEMS
require ongoing quality assurance to ensure that they are operating
properly, owners and operators of units that do not meet this
requirement during the non-ozone season will have to recertify their
monitors before the start of the ozone season.

D. Background on Requiring EPA and the State Permitting Authority to
Approve Alternatives to Part 75

The proposal would have required owners and operators of units that
are not subject to the requirements of title IV of the CAA that wish to
petition for an alternative to any of the requirements of part 75 to
petition both the state permitting authority and the Administrator.
Several commenters suggested that approval of one or the other should
suffice. Some of the commenters also noted that the requirements were
different for units affected by title IV, who are only required to
petition the Administrator.
The EPA agrees that the requirements for units affected by title IV
and units not affected by title IV are inconsistent. Because of
different requirements of the Act this inconsistency is necessary. The
EPA has the sole authority to grant petitions to units affected by
title IV under Sec. 75.66 of part 75. If a State incorporates those
monitoring requirements into its State rules, this still does not give
it the authority to change or waive the monitoring requirements for a
unit subject to title IV. However, recognizing that granting a petition
affects the accounting of NO_X mass emissions for a State
program, EPA does intend to work cooperatively with State agencies on
petition requests that could affect monitoring and reporting of
NO_X mass emissions.
For sources not affected by title IV that are complying with the
requirements of subpart H because they have been adopted or
incorporated into a State SIP, neither EPA nor the State has sole
authority to approve a petition for an alternative. While the State
does have the authority to set forth specific monitoring and reporting
requirements in a SIP and submit those requirements for EPA approval, a
State does not have the discretion to modify the SIP by changing or
waiving those monitoring and reporting requirements without obtaining
EPA approval. Likewise, EPA does not have sole authority to revise a
SIP since the primary responsibility to develop and implement a SIP is
granted

[[Page 57484]]

to the States under the CAA. The EPA is however required by the CAA to
review and approve or disapprove SIP revisions. Since a petition to
change or waive unspecified requirements related to monitoring and
reporting can not be approved as part of the original SIP approval
process, EPA must be involved in any approvals of alternatives to the SIP.
In addition to the title I requirements for EPA to be involved in
approval of petitions for alternatives to part 75, there are several
other reasons that EPA needs to be involved. The first is that since
EPA is administering the emissions data collection system under part
75, EPA must ensure that any changes to the reporting requirements can
be handled by the emissions tracking system that EPA maintains.
Secondly, in order to ensure the integrity of a multi-state market
based system and to ensure that participants in the system are treated
equitably, it is important to ensure that sources are treated equitably
from State to State. Therefore, if interstate trading is taking place
EPA clearly has a role in approving petitions for alternatives to
ensure that sources are treated consistently from state to state when
engaging in such interstate commerce.

II. Low Mass Emissions Excepted Monitoring Methodology

A. Background

In the January 11, 1993 Acid Rain permitting rule, EPA provided for
a conditional exemption from the emissions reduction, permitting, and
emissions monitoring requirements of the Acid Rain Program for new
units having a nameplate capacity of 25 MWe or less that burn fuels
with a sulfur content no greater than 0.05 percent by weight, because
of the de minimis nature of their potential SO₂,
CO₂ and NO_X emissions (see 58 FR 3593-94 and
3645-46). Moreover, in the January 11, 1993 monitoring rule, EPA
allowed gas-fired and oil-fired peaking units to use the provisions of
Appendix E, instead of CEMS, to determine the NO_X emission
rate, stating that this was a de minimis exception. The EPA allowed
this exception from the requirements of section 412 of the CAA because
the NO_X emissions from these units would be extremely low,
both collectively and individually (see 58 FR 3644-45). One utility
wrote to the Agency, suggesting that the Agency consider further
regulatory relief for other units with extremely low emissions that do
not fall under the categories of small new units burning fuels with a
sulfur content less than or equal to 0.05 percent by weight or gas-
fired and oil-fired peaking units (see Docket A-97-35, Item II-D-31).
The utility specifically suggested that the Agency consider an
exemption, the ability to use Appendix E, or some other simplified
methods which are more cost effective.
In the process of implementing part 75, other utilities also have
suggested to EPA that it provide regulatory relief to low mass emitting
units (see Docket A-97-35, Items II-D-29, II-E-25). These units might
be low mass emitting because they use a clean fuel, such as natural
gas, and/or because they operate relatively infrequently. Some
utilities stated that they spend a great deal of time reviewing the
emissions data when preparing quarterly reports for these units. Others
argued that it would be important to reduce monitoring and quality
assurance (QA) requirements in order to save time and money currently
devoted to units with minimal emissions (see Docket A-97-35, Item II-E-25).
In response to the requests for simplified monitoring and
recordkeeping requirements for units which both operate infrequently
and have low mass emissions on May 21, 1998 the Agency proposed, under
Sec. 75.19 of part 75, changes to the monitoring requirements that
would allow a new excepted methodology for low mass emission units. The
proposed low mass emissions methodology would have allowed units which
have emissions less than 25 tons of both NO_X and
SO₂ to use a methodology with reduced monitoring, reporting
and quality assurance requirements than the use of CEMS or either
appendix D or E methodologies. The methodology proposed used a unit's
maximum rated hourly heat input and generic defaults for
SO₂, NO_X and CO₂ mass emissions. The
proposed methodology was a less accurate methodology for determining
emissions for SO₂, NO_X and CO₂ but
would significantly reduce the burden on industry for these sources.
The allowance of this methodology was justified using the de minimis
individual and aggregate emissions represented by the units who would
qualify for the methodology.
While the proposed methodology did not contain an explicit cutoff
for CO₂, EPA believes that the limited applicability of the
proposal ensured that emissions of CO₂ from units that would
qualify to use the proposal was also de minimis. This is important,
because under section 821 of the Act, the agency is also required to
collect CO₂ emissions data from sources subject to title IV.
This data is required to be collected ``in the same manner and to the
same extent'' as required under title IV.
The Agency solicited comments on both the proposed methodology for
determining emissions and the proposed applicability limits of 25 tons
for both NO_X and SO₂ as well as any other
comments related to the proposed low mass emission methodology. In
reviewing the comments submitted on the proposal, the Agency noted that
several commenters suggested the methodology was too restrictive and
would only allow reduced monitoring to a limited number of units. The
commenters suggested various methods for expanding applicability to the
low mass emission methodology the most common which are; (i) remove the
requirement for units to have both SO₂ and NO_X
emissions of less than 25 tons and instead to allow units to use the
methodology on a pollutant specific basis; (ii) increase the 25 ton
limit for NO_X and SO₂ to 50, 100 or 250 tons;
(iii) allow additional methods for calculating heat input; and (iv)
allow the use of unit-specific NO_X emission rates. One other
significant comment was received which indicated that the default
values for NO_X emission rate in table 1b of proposed
Sec. 75.19 (c) could significantly underestimate emissions from certain
types of units.
In response to the comments, which generally advocating the
applicability of the low mass emissions methodology to more units, the
Agency is adopting the proposed low mass emissions methodology with the
following changes: (1) the NO_X applicability limit is being
raised to 50 tons which will increase the number of units that can use
the methodology; (2) units are being allowed an optional procedure for
heat input which will increase the number of units that can use the
methodology and provide more accurate emission estimates; (3) units are
being allowed to use unit-specific NO_X emission rates
determined through testing which will allow increased applicability and
more accurate emissions estimates for NO_X; and (4) the
values for NO_X emission rate in table 1b of proposed 75.19
(c) are being changed to prevent underestimation of emissions using the
methodology.

B. Discussion of Low Mass Emissions Methodology

Today's new Low Mass Emissions methodology incorporates optional
reduced monitoring, quality assurance, and reporting requirements into
part 75 for units that burn only natural gas or fuel oil, emit no more
than 25 tons of SO₂ and no more than 50 tons of
NO_X annually, and have calculated annual

[[Page 57485]]

SO₂ and NO_X emissions that do not exceed such
limits. Units that are not subject to Title IV of the Act and that are
only subject to subpart H of part 75 are not required to meet the
SO₂ limit to qualify to use the methodology. In addition, if
allowed by their State, they may qualify as low mass emission units
during the ozone season if they emit less than 25 tons of
NO_X per ozone season.
A unit may initially qualify for the reduced requirements by
demonstrating to the Administrator's satisfaction that the unit meets
the applicability criteria in Sec. 75.19(a). Section 75.19(a) requires
facilities to submit historical actual (or projections, as described
below) and calculated emissions data from the previous three calendar
years demonstrating that a unit falls below the 25-ton cutoff for
SO₂ and the 50 ton cutoff for NO_X. The calculated
SO₂ mass emissions data for the previous three calendar
years will be determined by choosing one of the two heat input options
in Sec. 75.19(c) and the appropriate emission rate from table 1a in
Sec. 75.19(c). The calculated NO_X mass emissions data for
the previous three calendar years will be determined by choosing one of
the two heat input options in Sec. 75.19(c) and either the appropriate
emission rate from table 1b in Sec. 75.19(c) or a unit-specific
NO_X emission rate as allowed under Sec. 75.19(c). The data
demonstrating that a unit meets the applicability requirements of
Sec. 75.19(a) will be submitted in a certification application for
approval by the Administrator to use the low mass emissions excepted
methodology.
For units that lack historical data for one or more of the previous
three calendar years (including new units that lack any historical
data), Sec. 75.19(a) will require the facility to provide (1) any
historical emissions and operating data, beginning with the unit's
first calendar year of commercial operation, that demonstrates that the
unit falls under the 25-ton cutoffs for SO₂ and the 50 ton
cutoff for NO_X, both with actual emissions and with
calculated emissions using the proposed methodology, as described
below; and (2) a demonstration satisfactory to the Administrator that
the unit will continue to emit below the tonnage cutoffs (e.g., for a
new unit, applying the applicable emission rates and applicable hourly
heat input, under Sec. 75.19(c), to a projection of annual operation
and fuel usage to determine the projected mass emissions).
For units with historical actual (or projections, as described
above) emissions and calculated emissions falling below the tonnage
cutoffs, facilities allowed to use the optional methodology in
Sec. 75.19(c) in lieu of either CEMS or, where applicable, in lieu of
the excepted methods under Appendix D, E, or G for the purpose of
determining and reporting heat input, NO_X emission rate, and
NO_X, SO₂, and CO₂ mass emissions. The
facility will no longer be required to keep monitoring equipment
installed on low mass emissions units, nor will it be required to meet
the quality assurance test requirements or QA/QC program requirements
of Appendix B to part 75. Moreover, emissions reporting requirements
will be reduced by requiring only that the facility report the unit's
hourly mass emissions of SO₂, CO₂, and
NO_X, the fuel type(s) burned for each hour of operation, and
report the quarterly total and year-to-date cumulative mass emissions,
heat input, and operating time, in addition to the unit's quarterly
average and year-to-date average NO_X emission rate for each
quarter. Owners and operators may also choose to report partial hour
operating time and use the operating time to obtain a more accurate
estimate of heat input determined using the maximum hourly heat input
option. For units which use the optional long term fuel flow
methodology for heat input the source will report hourly and cumulative
quarterly and yearly output in either megawatts electrical output or
thousands of pounds of steam. For units which use unit-specific
NO_X emission rates determined through testing, reporting of
the Part 75 Appendix E test results will be required. For units that
have NO_X controls, data demonstrating that these controls
are operating properly will have to be kept on site. Facilities will
continue to be required to monitor, record, and report opacity data for
oil-fired units, as specified under Secs. 75.14(a), 75.57(f), and
75.64(a)(iii) respectively. Under Sec. 75.14(c) and (d), however, gas-
fired, diesel-fired, and dual-fuel reciprocating engine units will
continue to be exempt from opacity monitoring requirements.
If an initially qualified unit subsequently burns fuel other than
natural gas or fuel oil, the unit will be disqualified from using the
reduced requirements starting the first date on which the fuel (other
than natural gas or fuel oil) burned.
In addition, if an initially qualified unit subsequently exceeds
the 25-ton cutoff for either SO₂ or the 50 ton cutoff for
NO_X while using the adopted methodology, the facility will
no longer be allowed to use the reduced requirements in Sec. 75.19(c)
for determining the affected unit's heat input, NO_X emission
rate, or SO₂, CO₂, and NO_X mass
emissions (unless at a future time the unit can again meet the
applicability requirements based on the recent three years of data).
Adopted Sec. 75.19(b) allows the facility two quarters from the end of
the quarter in which the exceedance of the relevant ton cutoff(s)
occurred to install, certify, and report SO₂,
CO₂, and NO_X data from a monitoring system that
meets the requirements of Secs. 75.11, 75.12, and 75.13, respectively.
Under the low mass emission excepted methodologies in
Sec. 75.19(c), a facility will calculate and report hourly
SO₂, NO_X and CO₂ mass emissions by
multiplying hourly unit heat input by an appropriate emission rate.
Unit heat input is determined using one of two heat input
methodologies, maximum rated hourly heat input or long term fuel flow;
unit SO₂ and CO₂ emission rates are determined
using generic defaults; and unit NO_X emission rate is
determined using one of two methodologies, generic defaults or unit-
specific NO_X emission rate testing.
Commenters raised three major issues, which have led EPA to modify
its proposal. The three major issues raised were: (i) Should the
proposed initial and ongoing applicability criteria of 25 tons of both
NO_X and SO₂ be modified; (ii) was the proposed
methodology for estimating emissions appropriate and, should other
options for calculating emissions be allowed; and (iii) what should the
reduced monitoring and quality assurance requirements be for these units?
1. Applicability Criteria
a. Approach. Based on the rationale described in the preamble to
the May 12, 1998 proposal (63 FR 28037) and in the absence of
significant adverse comment, the Agency is using both actual and
calculated emissions as the basis for determining initial applicability.
b. Cutoff Limit for Applicability. Several commenters requested
that the cutoff limit for applicability of the low mass emission
provision be increased. These comments fell into two broad categories:
(1) decouple the NO_X and SO₂ requirements and
allow units which qualify as a low mass emissions unit for only one
pollutant to monitor that pollutant using the low mass emissions
methodology (see Docket A-97-35, Items, IV-D-24, IV-D-11, IV-D-23, IV-
G-03, IV-D-20); and (2) raise the tonnage cutoff for NO_X and
SO₂ (see Docket A-97-35, Items, IV-G-03, IV-D-24, IV-D-22,
IV-D-23, IV-D-07, IV-G-02).
c. Determining the Criteria for Low Mass Emitters. Based on
comments received the Agency believes that the

[[Page 57486]]

low mass emission provision is appropriate for units which have low
mass emissions because: (i) a unit has a low capacity factor usage or
operates infrequently; or (ii) a unit has low mass emissions despite a
relatively high capacity factor due to the small size of the unit. For
these units, the cost of installing and maintaining CEMS would
represent a relatively large portion of the total value of the
electricity or steam produced by the unit. The Agency, also reasoned
that the types of units identified above can use the excepted
methodology without any significant risk to the environment or
impairment of the Agency's ability to meet its obligations under the CAA.
The Agency also determined the types of units which were not
appropriate candidates for use of the low mass emissions excepted
methodology. In particular, the Agency has concerns about allowing
large numbers of controlled units to use an estimation methodology such
as the low mass emission methodology. Because many of these units have
low mass emissions not because they operate infrequently, but rather
because they have controls which reduce their emission rates, their
continued low mass emissions is dependent on continued proper operation
of the controls on the unit. The EPA believes that monitoring actual
emission rates is necessary to ensure that installed emission controls
are operating properly and that actual emissions remain low. On the
other hand, EPA believes that it is appropriate to allow small or
infrequently operated units with controls, such as peaking turbines
with water or fuel injection, to use the low mass emissions provision.
This is appropriate because as long as these units continue to limit
their operation, their potential to emit still remains low, even if
their controls are not working. Therefore, while EPA believes it is
appropriate to allow small infrequently operated units with controls
that have both low actual emissions and a low potential to emit (as
long as they continue to operate at low levels), EPA does not believe
that it is appropriate to allow controlled units that have large
potential to emit if their controls are not operating properly to use
this methodology.
The low mass emission excepted methodology is a new exception, in
addition to the exceptions in the existing rule, from the requirement
for a NO_X CEMS. The determination of whether individual and
collective emissions covered by the exceptions from CEMS are de minimis
must include consideration of emissions from both new and existing
units that will qualify to use the new low mass emissions excepted
methodology and also new and existing units that will qualify to use
other exceptions from the NO_X CEM requirement, i.e. units
using the existing appendix E excepted methodology and units with new
unit exemptions under Sec. 72.7.
The EPA has first considered the level of projected aggregate
emissions determined to be de minimis for purposes of developing the
new unit exemption promulgated in the January 11, 1993 Acid Rain
permitting rule (58 FR 3593-94 and 3645-46). Aggregate emissions
projected for units under the exemption were approximately 138
cumulative tons of SO₂ and 1934 cumulative tons of
NO_X emitted per year from an estimated 170 new units which
might qualify for the exception before the year 2000. As of September
of 1998, 278 exemptions have actually been granted under the new unit
exemption. The Agency estimates that the level of SO₂ and
NO_X mass emissions from these units is 226 tons of
NO_X and 3163 tons of SO₂. The Agency further
believes that this group of excepted units will continue to increase at
the current rate.
The EPA has also considered the level of emissions projected to be
covered by appendix E. The EPA, in the January 11, 1993 Acid Rain
monitoring rule, allowed gas-fired and oil-fired peaking units to use
the provisions of appendix E, instead of CEMS, to determine the
NO_X emission rate. The Agency stated that, even though this
method was less accurate than CEMS, this was a de minimis exception
because emissions from all units that qualify to use the appendix E
reporting methodology were projected to be extremely low, the units did
not have a NO_X compliance obligation, and the cost of
installing and operating CEMS for these units would be high (see 58 FR
3644-45). The preamble to the January 11, 1993 rule estimated the
emissions from oil and gas units which operated with a capacity factor
of less than 10 percent to be 40,000 tons of NO_X per year.
The Agency has analyzed existing appendix E units to determine the
actual NO_X mass emissions reported by these units in 1997.
This analysis indicates that in 1997 approximately 235 units used the
appendix E methodology and had total emissions of approximately 11,000
tons of NO_X in 1997. (see Docket A-97-35, Items, IV-A-1).
The Agency has then considered what level of total NO_X
emissions would be de minimis for all units that may be covered by de
minimis exceptions from the requirement to use CEMS i.e. all units
using the new unit exemption, appendix E, and the new low mass
emissions methodology. The Agency maintains that a de minimis level of
total NO_X emissions should not be more than one percent of
the total NO_X emission inventory currently or in the future
for all units. This approach is supported by the treatment of 40,000
tons of NO_X as de minimis in the January 11, 1993 rule
preamble concerning appendix E, which is somewhat less than 1 percent
of the total NO_X emissions estimated for 1993. However, the
40,000 tons of NO_X determined to be de minimis emissions in
1993 is not an appropriate de minimis level with regard to current and
future levels of NO_X emissions. Several factors have
increased the importance of monitoring lower levels of NO_X
emissions including: (i) The new more stringent NAAQS for ozone
(NO_X is an ozone precursor); (ii) title IV Phase II
NO_X reductions which will reduce the total NO_X
inventory; (iii) today's NO_X SIP call which may result in
NO_X compliance obligations for gas-and oil-fired units and
will reduce the NO_X emission inventory; and (iv) State and
regional NO_X reduction programs, such as the OTC program,
State RACT rules and the RECLAIM program in California, which result in
NO_X compliance obligations for gas-and oil-fired units and
reduced NO_X emission inventory. As a result, EPA views about
20,000 tons (close to 1 percent of projected NO_X emission
inventory) as the de minimis level of NO_X emissions for the
present and foreseeable future. Given that appendix E units and new
unit exemption units currently account for about 14,100 tons of
NO_X there is not a large margin left for establishing
additional exception to the CEM requirements. The Agency has considered
potential future growth in the number of units using the new unit
exemption or appendix E in order to estimate what level of additional
NO_X, SO₂ and CO₂ emissions might be
appropriate to allow under the low mass emissions methodology. Taking
account of the uncertainty inherent in such estimates EPA has set the
applicability criteria for the low mass emission methodology so that
the NO_X emissions covered by the methodology plus future
growth in NO_X emissions covered by the other current de
minimis exceptions (appendix E and the new unit exemption) will not
exceed 5000 tons of NO_X per year in the future.
The Agency has analyzed SO₂, NO_X and
CO₂ emissions and determined that, as long as the cutoffs
for NO_X and SO₂ are coupled so that a unit must
meet both the 50 tons of NO_X and 25 tons of

[[Page 57487]]

SO₂ limits, that SO₂, NO_X and
CO₂ emissions under all exceptions from CEMS requirements
will remain de minimus. Additionally decoupling the NO_X and
SO₂ tons would allow only marginal simplification in
monitoring while significantly complicating the low mass emissions
methodology.
d. Determining the Tonnage Cutoffs for SO₂ and
NO_X. The Agency has conducted a study of actual emissions
data from 1997 quarterly reports under part 75 and evaluated potential
tonnage cutoffs for SO_X and NO_X (see Docket A-97-
35, Item IV-A-1). The analysis was based on the assumption that
reported 1997 emissions of NO_X and SO₂ will be
more representative of calculated emissions under the final low mass
emissions methodology than they would have been under the proposed
methodology. The assumption is considered valid because the final low
mass emissions methodology allows more accurate heat input
determination using long term fuel flow and the use of fuel and unit
specific NO_X emission rates. These options allow more
accurate emissions estimates than the proposed methodology would have.
This differs from the analysis performed for the proposed low mass
emission methodology which calculated emissions based on operating
hours and maximum rated heat input.
Based on this analysis, EPA estimates that the existing Acid Rain
affected sources that would qualify for the low mass emissions excepted
methodology using a coupled 50 tons NO_X and 25 tons
SO₂ limit would represent aggregate emissions of
approximately 3100 tons of NO_X and approximately 260 tons of
SO₂ in 1997 from 224 units. The analysis indicates that the
applicability has been substantially increased in response to the
comments received.
For the proposed 25 ton NO_X cutoff , which is the
limiting factor for applicability in nearly all instances, the Agency
has considered increasing the tons of NO_X to 50 tons, 75
tons, 100 tons, and 250 tons as suggested by various commenters. In its
analysis, the Agency kept SO₂ at 25 tons, as discussed above.
The analysis showed that by increasing the NO_X limit to
250 tons coupled to 25 tons of SO₂, the aggregate tons of
NO_X and SO₂ emitted by units which could
currently qualify for the low mass emissions methodology increased to
approximately 23124 tons NO_X and 4503 tons of
SO₂; this is without considering potential future growth in
the number of units that could qualify to use this exemption.
Increasing the cutoff for NO_X to 250 tons could also allow
many units with highly effective NO_X controls to use the low
mass emissions provision. As explained previously, units with effective
NO_X controls and high operating capacity should not use the
low mass emission provision. The EPA concludes that with a 250 ton
NO_X mass emissions applicability cutoff, the aggregate
NO_X tons and percentage of inventory potentially covered by
all the exceptions encompassed would easily exceed the de minimis level
of emissions. The EPA has therefore, not adopted an increased cutoff
limit for NO_X of 250 tons. Similarly, EPA concludes that an
increased cutoff of 100 tons of NO_X would not be consistent
with the type of source which the Agency has identified for use of the
low mass emission excepted methodology or fit under the de minimis
level of emissions defined for NO_X by the Agency. At the 100
ton cutoff for NO_X coupled to a 25 ton cutoff for
SO₂ the aggregate NO_X emissions are 8841 tons of
NO_X and 540 tons of SO₂ from 408 qualifying
units. The analysis performed by the Agency indicates that 50 tons of
NO_X coupled to 25 tons of SO₂ is the appropriate
cutoff limit for applicability to the low mass emissions excepted
methodology. The approximate aggregate emissions of 3600 tons of
NO_X and 250 tons of SO₂ from 240 sources allows
the appropriate type of units to use the provisions without great
potential of exceeding a de-minimus level of NO_X emissions.
In choosing the 50 ton NO_X mass emission cutoff limit over
other limits, the Agency evaluated the available data and applied the
following criteria: (1) The NO_X tons limit should allow
reduced monitoring for the units which EPA determined were appropriate
candidates for the low mass emissions provisions during the rulemaking
process, namely units with low mass emissions both collectively and
individually due to low operating levels or small size but not highly
controlled units which operate at higher levels; (2) the NO_X
tons limit should allow reduced monitoring for a group of units
consistent with the level of de minimis emissions inventory for all
exceptions for the CEMS requirement; and (3) the limit should not
jeopardize the Agency's ability to effectively fulfill its obligations
under of the CAA.
From the analysis performed, the Agency has demonstrated that
increasing the 25 ton limit for SO₂ would result in allowing
few additional sources the option to use the low mass emissions
methodology. For example at a coupled 50 tons of NO_X and 25
tons of SO₂ increasing the SO₂ tonnage cutoff to
50 tons would allow only 7 additional units to use the methodology. The
additional units identified all combusted oil as the primary fuel which
has a very high sulfur content in comparison to natural gas. While
natural gas fired units could easily increase operations without
substantial increases in SO₂ emissions oil fired units could
not. The additional units which burn oil and qualify are considered
inappropriate candidates for use of the low mass emission provision.
Therefore, the Agency has chosen to leave the tonnage limit at the
proposed level of 25 tons for SO₂. Leaving the cutoff for
applicability for SO₂ at 25 tons also reflected the opinion
of commenters who suggested raising only the NO_X tonnage.
When considering the size cutoffs, EPA also took into account both
the effect that the use of this methodology could have on other
regulatory actions and the effect that other regulatory actions could
have on the number of units and percentage of emissions that could be
covered by units using this methodology. In particular, EPA was
concerned about the SIP call. Units that could qualify to use the low
mass emission methodology do not have a NO_X emission limit
under title IV. However, under the SIP call, units that are using the
monitoring requirements of part 75 to comply with the requirements of
the SIP call, including units that could qualify to use the low mass
emitter methodology, would have an emission limit. As explained in
Section VI.A.2.c and VII.D.3 of today's preamble, EPA believes that it
is important that large sources of NO_X mass emissions
accurately account for their emissions. Because EPA is expecting
substantial reductions in NO_X emissions from the title IV
phase II NO_X emission rate limits, the SIP call and other
similar programs, EPA believes that even if the total NO_X
emissions coming from units that could qualify for the low mass emitter
methodology does not increase, the percentage of emissions coming from
these units will increase. The EPA also believes that the incentives
provided under a trading program could encourage smaller oil and gas
fired units that may not currently qualify under the low mass emission
methodology to install controls. As a result, this could increase the
number of units, the amount of emissions and the percentage of
emissions that could be accounted for by units using this methodology.
EPA believes that the 50 ton cutoff is adequate to ensure that
emissions from units that qualify for the low mass

[[Page 57488]]

emitter methodology are de-minimis today. In the future however, growth
in the number of units may cause the level of NO_X,
SO₂ or CO₂ emissions from units qualifying for
and using the new unit exemption, appendix E, the low mass emitter
provision and other programs such as the SIP call to exceed a de-
minimis level and the agency reserves the right to re-assess any and
all of these exceptions in the future if the need arises.
e. Decoupling NO_X and SO₂. In order to
qualify for the low mass emissions excepted methodology, the
applicability criteria require a unit to meet annual tonnage cutoffs of
25 tons for SO₂ and 50 tons for NO_X. The EPA has
considered whether the excepted methodology should be available on a
pollutant specific level so that, for example, a unit which falls below
the tonnage cutoff for SO₂ but not for NO_X could
use the excepted methodology under Sec. 75.19 to measure SO₂
emissions but use a NO_X CEM or the excepted methodology
under appendix E, where applicable, to measure NO_X
emissions. All analysis the Agency has done indicates that the
NO_X tonnage is the limiting factor for greater than 90
percent of all units when applicability is for units to meet a coupled
50 ton NO_X and 25 ton SO₂ limit (see Docket A-97-
35, Items, II-A-10, IV-A-1) For example, approximately 20 units were
identified which would potentially be qualified to use the low mass
emission methodology for a 50 tons of NO_X cutoff who would
not meet the 25 tons of SO₂ cutoff and therefore be
disqualified from using the methodology. Conversely, the agency's
analysis indicated that leaving the tonnage cutoff for SO₂
mass emissions at 25 tons and decoupling NO_X and
SO₂ would potentially allow approximately 650 units in the
program to use the low mass emissions methodology for SO₂
(see Docket A-97-35, Items, II-A-10, IV-A-1). In particular allowing
decoupling could impair the Agency's ability to collect data on
CO₂ emissions as required under the CAA section 821. The
analysis performed by the Agency indicates, that even with a 25 ton
limit on SO₂, 652 units could qualify for the use of the low
mass emissions methodology for SO₂ only. The 652 units
identified represent approximately 10 percent of the total program heat
input and greater than 6 percent of the total program CO₂
emissions. If a unit which qualified for the use of only SO₂
were allowed to use the low mass emissions methodology for
CO₂ the result could be overestimation of CO₂
emissions from a sizeable percentage of the total CO₂
inventory. Future decisions based on such data might draw incorrect
conclusions.
For the reason stated above, if a unit were allowed to qualify for
a single pollutant the unit would be allowed to use the low mass
emissions methodology for that pollutant only and not for
CO₂ or heat input estimations. Therefore, no practical
benefit for industry would result from decoupling SO₂ and
NO_X. Decoupling would not be particularly beneficial because
qualifying for one pollutant only allows only minimal monitoring
reductions when CO₂ and heat input are not simplified. In
addition decoupling would dramatically increase the complexity of the
low mass emissions methodology. The added complications which would
benefit a limited number of sources in only a limited way would
increase the time and effort needed for all other sources in
understanding and implementing the methodology. The agency concludes
that the burden from the increased rule complexity outweighs the
benefit from decoupling SO₂ and NO_X.
The following discussions further explain the Agencies position.
One of the prime benefits of the low mass emissions excepted
methodology will be the simplified reporting which will require less
time and a less sophisticated Data Acquisition and Handling System
(DAHS). In particular, the need for a DAHS that could calculate
substitute data using the current missing data algorithms will be
removed because there are no missing data algorithms for the low mass
emissions excepted methodology. If the excepted methodology is only
applied to one of the pollutants, much of the benefit would be negated
because the DAHS will still need to be capable of calculating
substitute data for the measured pollutant and close to the full
quarterly report would still be required.
Another prime benefit of the low mass emissions excepted
methodology will be the reduction of monitoring and quality assurance
requirements. A unit which would qualify for SO₂ only would
still need to determine CO₂ mass emissions using a fuel flow
meter. Additionally the units which would qualify are primarily gas
fired units which would be allowed to use appendix D for
SO₂. In this case no benefit is allowed by using the low
mass emissions methodology. A limited number of oil fired units would
be granted some reduced sampling requirements.
The agency's analysis indicates that most units which would qualify
for NO_X only can use the excepted methodology under appendix E.
As stated before the analysis indicates that the benefits of
decoupling are outweighed by the complications of allowing decoupling.
f. The use of the Low Mass Emitter Methodology with fuels other
than oil and natural gas. One commenter suggested that the
applicability should be expanded to include other fuels including low
sulfur solid fuels such as wood. EPA disagrees with the commenter who
claims that the methodology should be irrespective of fuel type. The
fuel type is an integral part of the emissions calculations and insures
that emissions are not underestimated. The Agency does not have, and
the commenter did not provide, sufficient data to justify including
wood fired solid fuel units into the low mass emission methodology. The
limited data EPA has does not provide assurance that wood is always low
in sulfur or that it results in low mass emissions of NO_X.
The use of AP 42 emission factors was considered but rejected based on
the possibility of underestimation of NO_X emissions using
the AP 42 factors, as stated in the January 11, 1993 rule preamble at
58 FR 364445. If EPA is provided with information addressing this issue
in the future, EPA will consider expanding the applicability to units
that burn wood in the future.
2. Method for Determining Emissions
On May 21, 1998 the Agency proposed a low mass emissions
methodology which used maximum rated heat input as the only heat input
option and default emission rates for SO₂, NO_X,
and CO₂. The Agency requested comment on whether this
methodology was appropriate or whether an alternate approach should be
adopted for low mass emitting units. In response, several commenters
suggested changing the method for determining emissions. One commenter
suggested allowing the use of unit-specific NO_X testing (see
Docket A-97-35, Item IV-D-20). Another commenter suggested that long
term fuel flow heat input be allowed as an alternative to the proposed
maximum rated heat input (see Docket A-97-35, Item IV-D-13). Two other
commenters suggested that further unspecified options be allowed for
determining heat input (see Docket A-97-35, Items, IV-D-03, IV-G-02).
Additionally several commenters suggested that the reduced monitoring
under the low mass emission methodology was being limited to too few
sources (see Docket A-97-35, Items, IV-D-07, IV-D-22, IV-D-23, IV-D-24,
IV-G-03). Other commenters made the general suggestion that part 75 should

[[Page 57489]]

be more consistent with the monitoring requirements of the OTC
NO_X Budget Program. Finally the Agency received both
comments and data which indicated that for uncontrolled gas fired
turbines combusting both oil and gas the default emission rates for
NO_X in proposed table 1b of Sec. 75.19 (c) were potentially
substantial underestimations of actual emission from these types of
units (see Docket A-97-35, Item IV-D-22). Further analysis by the
Agency provided supporting evidence that the emission rates in proposed
75.19 (c), table 1b, might underestimate emissions significantly for
gas and oil fired turbines (see Docket A-97-35, Item IV-A-1). In
response to these comments which reflected a general desire to expand
the applicability of the low mass emission methodology through changes
in both the heat input and NO_X emissions methodology, and in
light of no negative comments reflecting opposition to allowing the low
mass emission methodology, the Agency began analysis of what changes in
the methods for determining heat input and NO_X emissions
could be allowed without risk of underestimation of emissions, or
negative environmental consequences. The Agency received no comments on
changing either the SO₂ or CO₂ methods for
determining emissions and therefore did not attempt to change these
methodologies.
a. Adoption of the Proposed Methodology. In the proposal, the
Agency considered several methods for determining the estimated
emissions as the basis for applicability of the reduced monitoring and
reporting excepted methodology. For each of the methods considered,
rather than using actual measured sulfur and carbon values,
CO₂, SO₂, and flow CEM readings, NO_X
CEM readings, or NO_X values from an Appendix E
NO_X-versus-heat input correlation, a facility will calculate
the unit's emissions based on an emission rate factor and one of two
heat input methodologies. Since the units that will qualify for the
excepted methodology will still be accountable for reporting emissions
to the Agency and surrendering allowances based on those emissions,
where applicable, the emissions estimations will not just be used to
determine if the unit qualifies under the exception; the reported
estimations will also be used to determine compliance. Prior to the
proposal, some industry representatives suggested that facilities would
be willing to use a conservative emission estimate, such as a maximum
potential emission rate times the maximum heat input, if it would allow
them to save time and money currently spent on monitoring and quality
assurance (see Docket A-97-35, Items II-D-30, II-D-43, II-D-45, II-E-
13, and II-E-25). The Agency decided it was appropriate to retain the
proposed methodologies of maximum rated heat input and default
SO₂, NO_X and CO₂ emission rates for
the final rule. It was also decided to allow increased applicability of
the low mass emissions methodology through optional unit-specific
NO_X emission rate determinations and the use of an optional
heat input methodology (e.g., long term fuel flow).
b. Change in Table 1b, Default NO_X Emission Rates. In
deciding to retain the proposed low mass emission methodology as part
of the final rule the Agency had to consider that some values for
NO_X emission rate in proposed table 1b of Sec. 75.19 (c) had
a high potential for underestimating emissions in at least some cases.
The Agency acknowledged that increasing the default NO_X
emission rates in table 1b of Sec. 75.19 (c) will reduce the number of
units allowed to use the low mass emissions methodology. Based on the
comments received (see Docket A-97-35, Item IV-D-20) and to both allow
increased applicability and increase the default rates to an
appropriate level, the use of NO_X testing to determine
units-specific NO_X emission rates will be allowed as an
alternative option to using the default NO_X emission rates
in table 1b of Sec. 75.19 (c). Allowing the option of unit-specific
NO_X emission rates will generate more realistic
NO_X emission rates than the default NO_X emission
rates in table 1b of Sec. 75.19 (c) and will maintain some of the
simplicity of the NO_X mass methodology from the low mass
emissions methodology proposal.
The next issue was deciding which default NO_X emission
rates in table 1b of Sec. 75.19 (c) to raise and what level to raise
the defaults to. As a first consideration the Agency noted that the
default NO_X emission rates in table 1b of proposed
Sec. 75.19 (c) should be increased to the level at which it will be
highly unlikely that any unit that performed testing will have a higher
emission rate than the default. In this case, a source might opt to use
a default which would knowingly underestimate emissions under certain
operating conditions. Since all of the defaults used in table 1b of
proposed Sec. 75.19 (c) were based on the 90th percentile it is very
likely that some units would have a higher emission rate than the
NO_X emission rates in table 1b of proposed 75.19 (c). For
this reason, all of the NO_X emission rate values in proposed
table 1b were increased to a level which will ensure that units will
not have higher tested emission rates than the default rates in Table
1b. A commenter suggested that these provisions be more consistent with
the provisions for the Ozone Transport Commission (OTC), NO_X
Budget Program (see Docket A-97-35, Item IV-D-13). The default emission
rates the Agency decided to adopt are the default rates used in the OTC
NO_X Budget Program (see Docket A-97-35, Item II-I-7). In the
OTC NO_X Budget Program, units similar in emission
characteristics to those who will qualify as low mass emission units
under today's rule have the option of unit specific testing or unit
generic default OTC NO_X emission rates. In the OTC
NO_X Budget Program units have chosen both options based on
owner or operator preference. Finally, adopting the NO_X
Budget Program defaults creates consistency among programs which is a
supplementary benefit.
c. Unit-Specific NO_X Emission Rate Testing. In
considering the options for unit-specific NO_X emission rate
testing the Agency had to address several concerns, including the
following: (1) Units with NO_X controls who performed unit
specific testing with the controls operating might have the potential
to grossly underestimate emissions if the controls failed; (2) what
sort of test would be appropriate for determining the low mass
emissions methodology fuel -and-unit-specific NO_X emission
rate; (3) how long a period should a source be allowed to use the unit-
specific NO_X rate once determined through testing; (4) under
what conditions should a source be required to retest for a new unit-
specific NO_X emission rate; (5) for sources with historical
reported emissions data using CEMS under part 75, what historical
NO_X emission rate value might be appropriate for use in lieu
of an initial test; and (6) if a source owns multiple identical units,
should representative testing be allowed at some of the units to
represent all units.
The first issue resolved was the use of Appendix E of Part 75
procedures for determination of a unit-specific NO_X emission
rate for each fuel combusted by the unit. The unit-specific
NO_X emission rate selected, for each fuel tested, will be
the highest recorded NO_X emission rate from the test at any
test load or operating condition multiplied by 1.15. Units which
combust multiple fuels can use, for different fuels, either a unit-
specific NO_X rate determined through testing or use the
default NO_X emission rates listed in table 1b of Sec. 75.19
(c). For example, a unit which primarily combusts oil but occasionally
combusts natural gas could determine a unit-specific NO_X
emission rate for oil

[[Page 57490]]

through Appendix E testing and use the default NO_X emission
rate from table 1b of Sec. 75.19 (c) for gas. For hours in which a unit
combusts multiple fuels in one hour, the unit must use the highest
emission rate for that hour for all fuels combusted. In conducting the
Appendix E test, the requirement for monitoring heat input to the unit
during the test is removed as it is an unnecessary burden. The
multiplier of 1.15 is required because of Agency analysis which
indicates that appendix E testing is not representative of emissions at
a given load at all times. In particular, the analysis of units with
NO_X emission rate CEMS indicated that the NO_X
emission rate can vary an average of 15 percent at a given load during
different periods of operation. The most probable cause of the
difference noted is variations in atmospheric moisture content. The
agency notes that units which do appendix E testing during hot humid
conditions would likely underestimate emissions during cooler less
humid conditions. The Appendix E test was chosen for several reasons
including: (1) many current Acid Rain sources which might qualify for
the low mass emissions methodology already have performed Appendix E
testing and will be allowed to use their historical Appendix E test
data to determine a unit-specific NO_X emission rate without
further requirements; (2) the requirements of Appendix E testing are
already familiar to sources and contractors who may perform the
testing, thus reducing further burden imposed by requiring new testing
methodologies; (3) The use of the Appendix E test and the multiplier of
1.15 ensures that a unit uses a NO_X emission rate which will
not underestimate emissions at any normal operating condition.
Once the Appendix E test was chosen, the use of a five year testing
frequency was deemed appropriate as it matched the current Appendix E
test period and matches the current permit renewal cycle.
A special provision was included in the low mass emission
methodology to allow units with historical CEMS NO_X emission
rate data to determine a unit-specific NO_X emission rate
from historical certified CEMS data. Under this provision a unit will
analyze historical data from hours in which a unit combusted a
particular fuel. The analysis will determine the unit-specific
NO_X emission rate which will yield a 95 percent confidence
that the unit will not emit at a higher NO_X emission rate
while combusting the fuel being analyzed. The Agency also considered
using the highest NO_X rate from historical data but reasoned
that the large data sets used to generate the unit-and fuel-specific
emission rate would contain outliers which would make the procedure
unfeasible for most units. The Agency considered several options for
units which used NO_X controls and wished to use unit-
specific NO_X emission rates determined through Appendix E
testing. One option was to allow units to test with the NO_X
control devices not operating or minimized. This option was rejected
for the following two reasons: (1) the Agency does not support adopting
a rule which would require sources to operate in a manner that would
increase emissions; and (2) some sources which have controls are not
allowed to operate when the controls are not operating by permit
restrictions and these units would be disallowed from using the low
mass emission methodology unfairly. The Agency also considered not
allowing units with NO_X emission controls to use the low
mass emission methodology. While the Agency does believe that it is not
appropriate to include large controlled units, the Agency does feel it
is appropriate to allow infrequently used controlled units, such as
peaking turbines with steam or water injection to benefit from the
reduced requirements of this methodology (as further explained above).
Therefore this solution was rejected as excluding many units for which
the Agency believes it is appropriate to allow reduced monitoring from
more accurate and more costly monitoring requirements.
The Agency also considered allowing only units with certain types
of controls to use the low mass emission methodology. This approach was
rejected because the Agency does not, at this time, have the necessary
information or expertise to make an appropriate determination on this
approach.
The Agency also considered allowing units to determine a unit-
specific NO_X emission rate using NO_X controls
with no restriction. In analyzing this option, the Agency identified
several units which would qualify for the low mass emission methodology
based on the applicability criteria of 50 tons of NO_X and 25
tons of SO₂ which the Agency did not believe were
appropriate to use the low mass emission methodology. The units
identified had advanced control technologies such as selective
catalytic reduction (SCR) and burned low sulfur fuels such as natural
gas. The units identified consistently reported hourly emission rates
as low as 0.01 lb/mmBtu as compared to uncontrolled rates which are
generally 10 to 100 times higher for these units. The best method of
continued assurance that a unit's NO_X controls are operating
is monitoring with a NO_X CEMS. These units also operated
during more than half the hours of a year at an average heat input of
greater than 1000 mmBtu/hr. While, for these units, the potential to
underestimate SO₂ emissions was low, the potential to
grossly underestimate NO_X mass emissions using the low mass
emission methodology was much greater. For this reason, the Agency
rejected allowing a controlled unit to use a single emission rate
determined through Appendix E testing once every five years while
NO_X controls were operating.
The methodology the Agency adopted in this rule was the use of a
lower limit of 0.15 lb/mmBtu for a unit-specific NO_X
emission rate for units which opt to perform unit-and fuel-specific
Appendix E testing while controls are operating. For units with
NO_X emission controls, which perform unit-specific
NO_X emission rate testing and whose test results in a
NO_X emission rate of less than 0.15 lb/mmBtu, the source
will use the NO_X emission rate limit of 0.15 lb/mmBtu for
the unit-specific NO_X emission rate instead of the lower
tested NO_X emission rate. Units with NO_X emission
controls who perform unit-specific NO_X emission rate testing
and whose results from the testing indicate a NO_X emission
rate of higher than 0.15 lb/mmBtu will be required to use the higher
NO_X emission rate as the fuel-and unit-specific
NO_X emission rate. In considering this approach the Agency
considered using the lowest NO_X emission rate proposed in
75.19 (c), Table 1b, of 0.172 lb/mmBtu, as well as 0.15 lb/mmBtu, 0.1
lb/mmBtu and 0.05 lb/mmBtu as lower limits for NO_X emission
rate. The proposed gas fired turbine emission rate was 0.172 lb/mmBtu.
Using 0.172 lb/mmBtu as the lower limit for controlled units was
rejected as being an arbitrary choice based on a number representative
of only a single class of units and not representative of the
difference between controlled and uncontrolled units. An analysis was
performed to determine a reasonable lower cutoff between controlled and
uncontrolled units which would allow controlled units to qualify for
the reduced monitoring provisions of the excepted low mass emission
methodology without serious risk of underestimation of emissions. The
analysis indicated that a minimum allowable emission rate of 0.15 lb/
mmBtu for controlled units best allowed for fairness between controlled
and uncontrolled units and insured that very

[[Page 57491]]

large units with high operating hours and extremely low NO_X
emission rates will not be allowed to use the low mass emission
excepted methodology. The Agency's decision was also heavily influenced
by the desire to insure that overall, the emission rate chosen would
insure that aggregate emissions of controlled units were indeed de
minimis. The Agency notes that the lower limit of 0.15 lb/mmBtu
NO_X emission rate, when coupled with the annual limit of 50
tons of NO_X, effectively limits the annual heat input of
units using the methodology to 666,666 mmBtu annual heat input.
Analysis done by EPA found this to be an appropriate limit on heat
input for the low mass emission excepted methodology (see Docket A-97-
35, Item IV-D-20). In general, the lower emission rate limit for
controlled units, and uncontrolled units inability to achieve such low
rates, combines to limit the low mass emission methodology to the
infrequently operated low mass emitting units the Agency was targeting
for use of the provision in today's new rule.
Controlled units that use this methodology are also subject to
additional requirements. The owner or operator of the unit must ensure
that the controls are being operated in the same manner that they were
operated during the unit specific testing. Documentation of this must
be kept on site. Any hour that the controls are not operating properly,
the owner or operator must use the default emission rates for
NO_X in table 1.b of Sec. 75.19 (c), rather than the emission
rate determined through unit specific testing.
Based on experience gained working with the OTC in the
implementation of the OTC NO_X budget program, EPA believes
that many of the units that may benefit from this new excepted
monitoring methodology are banks of identical small emission turbines.
The OTC has allowed these units to do representative sampling at a
number of units rather than requiring testing at all of the units.
While none of the commenters mentioned this specific flexibility of the
OTC NO_X Budget program, EPA believes that this is one of the
flexibilities that commenters who suggested adopting some of the
methodologies that the OTC has allowed for smaller units were referring
to. Therefore this final rule contains a similar allowance for
identical units. If the owner or operator of a number of units that are
located at one facility can demonstrate that those units are identical,
this final rule will allow emission rate testing to be done at a
representative number of units.
d. The Adoption of Maximum Rated Heat Input as Proposed. While
several commenters suggested allowing alternative methods for
determining heat input, none directly suggested replacing or altering
the basic heat input approach as an option (as described in 68 FR
28037-8). For this reason the maximum rated hourly heat input option
from the proposal was retained as a less accurate but acceptable approach.
e. Long Term Fuel Flow for Heat Input Determination. To allow
greater flexibility to units under the low mass emissions methodology
and to allow more realistic estimations of heat input as suggested by
several commenters the Agency is allowing the use of long term fuel
flow measurements to determine heat input to low mass emitting units as
described earlier. The Agency chose to adopt this methodology for the
following reasons: (1) The methodology allows more accurate
measurements of total heat input into a unit over the reporting period
than the use of maximum rated hourly heat input; (2) the methodology
has proven to be usable by sources who have chosen to use a similar
method in the Ozone Transport Commission, NO_X Budget
Program; and (3) the methodology is straightforward and is optional for
sources which might be excluded from using the low mass emissions
methodology if allowed to use maximum rated hourly heat input only.
3. Reduced Monitoring and Quality Assurance Requirements. As
discussed above, today's rule allows facilities to use a maximum rated
hourly heat input value and an emission rate factor to determine the
mass emissions from a low-emitting unit for each hour of actual
operation. This approach involves no actual emissions monitoring and
minimal quality assurance activities. Instead, the facility will only
need to keep track of whether the unit combusted any fuel for a
particular hour and what type of fuel was combusted. In this way, the
revised rule significantly reduces the burden on affected facilities,
while still ensuring that emissions are not under reported.
For owners or operators which opt to use either the long term fuel
flow methodology or a fuel-and unit-specific NO_X emission
rate, some additional quality assurance will be required. As these two
options under the low mass emission methodology are not required and
will allow units which would not otherwise qualify to use the low mass
emission methodology, the additional quality assurance requirements are
not burdensome to the sources using either long term fuel flow or unit-
specific NO_X emission rates.
For the reasons set forth in the preamble, parts 51, 72, 75, and 96
of chapter I of title 40 of the Code of Federal Regulations are amended
as follows:

PART 51--REQUIREMENTS FOR PREPARATION, ADOPTION, AND SUBMITTAL OF
IMPLEMENTATION PLANS

1. The authority citation for part 51 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart G--Control Strategy

2. Subpart G is amended to add Secs. 51.121 and 51.122 to read as
follows:

Sec. 51.121 Findings and requirements for submission of State
implementation plan revisions relating to emissions of oxides of nitrogen.

(a)(1) The Administrator finds that the State implementation plan
(SIP) for each jurisdiction listed in paragraph (c) of this section is
substantially inadequate to comply with the requirements of section
110(a)(2)(D)(i)(I) of the Clean Air Act (CAA), 42 U.S.C.
7410(a)(2)(D)(i)(I), because the SIP does not include adequate
provisions to prohibit sources and other activities from emitting
nitrogen oxides (``NO_X'') in amounts that will contribute
significantly to nonattainment in one or more other States with respect
to the 1-hour ozone national ambient air quality standards (NAAQS).
Each of the jurisdictions listed in paragraph (c) of this section must
submit to EPA a SIP revision that cures the inadequacy.
(2) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the
Administrator determines that each jurisdiction listed in paragraph (c)
of this section must submit a SIP revision to comply with the
requirements of section 110(a)(2)(D)(i)(I), 42 U.S.C.
7410(a)(2)(D)(i)(I), through the adoption of adequate provisions
prohibiting sources and other activities from emitting NO_X
in amounts that will contribute significantly to nonattainment in, or
interfere with maintenance by, one or more other States with respect to
the 8-hour ozone NAAQS.
(b)(1) For each jurisdiction listed in paragraph (c) of this
section, the SIP revision required under paragraph (a) of this section
will contain adequate provisions, for purposes of complying with
section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I),
only if the SIP revision:

[[Page 57492]]

(i) Contains control measures adequate to prohibit emissions of
NO_X that would otherwise be projected, in accordance with
paragraph (g) of this section, to cause the jurisdiction's overall
NO_X emissions to be in excess of the budget for that
jurisdiction described in paragraph (e) of this section (except as
provided in paragraph (b)(2) of this section),
(ii) Requires full implementation of all such control measures by
no later than May 1, 2003, and
(iii) Meets the other requirements of this section. The SIP
revision's compliance with the requirement of paragraph (b)(1)(i) of
this section shall be considered compliance with the jurisdiction's
budget for purposes of this section.
(2) The requirements of paragraph (b)(1)(i) of this section shall
be deemed satisfied, for the portion of the budget covered by an
interstate trading program, if the SIP revision:
(i) Contains provisions for an interstate trading program that EPA
determines will, in conjunction with interstate trading programs for
one or more other jurisdictions, prohibit NO_X emissions in
excess of the sum of the portion of the budgets covered by the trading
programs for those jurisdictions; and
(ii) Conforms to the following criteria:
(A) Emissions reductions used to demonstrate compliance with the
revision must occur during the ozone season.
(B) Emissions reductions occurring prior to the year 2003 may be
used by a source to demonstrate compliance with the SIP revision for
the 2003 and 2004 ozone seasons, provided the SIP's provisions
regarding such use comply with the requirements of paragraph (e)(3) of
this section.
(C) Emissions reduction credits or emissions allowances held by a
source or other person following the 2003 ozone season or any ozone
season thereafter that are not required to demonstrate compliance with
the SIP for the relevant ozone season may be banked and used to
demonstrate compliance with the SIP in a subsequent ozone season.
(D) Early reductions created according to the provisions in
paragraph (b)(2)(ii)(B) of this section and used in the 2003 ozone
season are not subject to the flow control provisions set forth in
paragraph (b)(2)(ii)(E) of this section.
(E) Starting with the 2004 ozone season, the SIP shall include
provisions to limit the use of banked emissions reduction credits or
emissions allowances beyond a predetermined amount as calculated by one
of the following approaches:
(1) Following the determination of compliance after each ozone
season, if the total number of emissions reduction credits or banked
allowances held by sources or other persons subject to the trading
program exceeds 10 percent of the sum of the allowable ozone season
NO_X emissions for all sources subject to the trading
program, then all banked allowances used for compliance for the
following ozone season shall be subject to the following:
(i) A ratio will be established according to the following formula:
(0.10) x (the sum of the allowable ozone season NO_X
emissions for all sources subject to the trading program) (the
total number of banked emissions reduction credits or emissions
allowances held by all sources or other persons subject to the trading
program).
(ii) The ratio, determined using the formula specified in paragraph
(b)(2)(ii)(E)(1)(i) of this section, will be multiplied by the number
of banked emissions reduction credits or emissions allowances held in
each account at the time of compliance determination. The resulting
product is the number of banked emissions reduction credits or
emissions allowances in the account which can be used in the current
year's ozone season at a rate of 1 credit or allowance for every 1 ton
of emissions. The SIP shall specify that banked emissions reduction
credits or emissions allowances in excess of the resulting product
either may not be used for compliance, or may only be used for
compliance at a rate no less than 2 credits or allowances for every 1
ton of emissions.
(2) At the time of compliance determination for each ozone season,
if the total number of banked emissions reduction credits or emissions
allowances held by a source subject to the trading program exceeds 10
percent of the source's allowable ozone season NO_X
emissions, all banked emissions reduction credits or emissions
allowances used for compliance in such ozone season by the source shall
be subject to the following:
(i) The source may use an amount of banked emissions reduction
credits or emissions allowances not greater than 10 percent of the
source's allowable ozone season NO_X emissions for compliance
at a rate of 1 credit or allowance for every 1 ton of emissions.
(ii) The SIP shall specify that banked emissions reduction credits
or emissions allowances in excess of 10 percent of the source's
allowable ozone season NO_X emissions may not be used for
compliance, or may only be used for compliance at a rate no less than 2
credits or allowances for every 1 ton of emissions.
(c) The following jurisdictions (hereinafter referred to as
``States'') are subject to the requirements of this section: Alabama,
Connecticut, Delaware, Georgia, Illinois, Indiana, Kentucky, Maryland,
Massachusetts, Michigan, Missouri, New Jersey, New York, North
Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee,
Virginia, West Virginia, Wisconsin, and the District of Columbia.
(d)(1) The SIP submissions required under paragraph (a) of this
section must be submitted to EPA by no later than September 30, 1999.
(2) The State makes an official submission of its SIP revision to
EPA only when:
(i) The submission conforms to the requirements of appendix V to
this part; and
(ii) The State delivers five copies of the plan to the appropriate
Regional Office, with a letter giving notice of such action.
(e)(1) The NO_X budget for a State listed in paragraph
(c) of this section is defined as the total amount of NO_X
emissions from all sources in that State, as indicated in paragraph
(e)(2) of this section with respect to that State, which the State must
demonstrate that it will not exceed in the 2007 ozone season pursuant
to paragraph (g)(1) of this section.
(2) The State-by-State amounts of the NO_X budget,
expressed in tons, are as follows:

------------------------------------------------------------------------
State Budget
------------------------------------------------------------------------
Alabama.................................................... 158,677
Connecticut................................................ 40,573
Delaware................................................... 18,523
District of Columbia....................................... 6,792
Georgia.................................................... 177,381
Illinois................................................... 210,210
Indiana.................................................... 202,584
Kentucky................................................... 155,698
Maryland................................................... 71,388
Massachusetts.............................................. 78,168
Michigan................................................... 212,199
Missouri................................................... 114,532
New Jersey................................................. 97,034
New York................................................... 179,769
North Carolina............................................. 151,847
Ohio....................................................... 239,898
Pennsylvania............................................... 252,447
Rhode Island............................................... 8,313
South Carolina............................................. 109,425
Tennessee.................................................. 182,476
Virginia................................................... 155,718
West Virginia.............................................. 92,920
Wisconsin.................................................. 106,540
------------
Total.................................................. 3,023,113
------------------------------------------------------------------------

[[Page 57493]]

(3)(i) Notwithstanding the State's obligation to comply with the
budgets set forth in paragraph (e)(2) of this section, a SIP revision
may allow sources required by the revision to implement NO_X
emission control measures by May 1, 2003 to demonstrate compliance in
the 2003 and 2004 ozone seasons using credit issued from the State's
compliance supplement pool, as set forth in paragraph (e)(3)(iii) of
this section.
(ii) A source may not use credit from the compliance supplement
pool to demonstrate compliance after the 2004 ozone season.
(iii) The State-by-State amounts of the compliance supplement pool
are as follows:

------------------------------------------------------------------------
Compliance
supplement
State pool (tons
of NO_X)
------------------------------------------------------------------------
Alabama.................................................... 10,361
Connecticut................................................ 559
Delaware................................................... 417
District of Columbia....................................... 0
Georgia.................................................... 10,919
Illinois................................................... 17,455
Indiana.................................................... 19,738
Kentucky................................................... 13,018
Maryland................................................... 3,662
Massachusetts.............................................. 285
Michigan................................................... 15,359
Missouri................................................... 10,469
New Jersey................................................. 1,722
New York................................................... 1,831
North Carolina............................................. 10,624
Ohio....................................................... 22,947
Pennsylvania............................................... 13,716
Rhode Island............................................... 0
South Carolina............................................. 5,062
Tennessee.................................................. 12,093
Virginia................................................... 6,108
West Virginia.............................................. 16,937
Wisconsin.................................................. 6,717
------------
Total.................................................. 200,000
------------------------------------------------------------------------

(iv) The SIP revision may provide for the distribution of the
compliance supplement pool to sources that are required to implement
control measures using one or both of the following two mechanisms:
(A) The State may issue some or all of the compliance supplement
pool to sources that implement emissions reductions during the ozone
season beyond all applicable requirements in years prior to the year
2003 according to the following provisions:
(1) The State shall complete the issuance process by no later than
May 1, 2003.
(2) The emissions reduction may not be required by the State's SIP
or be otherwise required by the CAA.
(3) The emissions reduction must be verified by the source as
actually having occurred during an ozone season between September 30,
1999 and May 1, 2003.
(4) The emissions reduction must be quantified according to
procedures set forth in the SIP revision and approved by EPA. Emissions
reductions implemented by sources serving electric generators with a
nameplate capacity greater than 25 MWe, or boilers, combustion turbines
or combined cycle units with a maximum design heat input greater than
250 mmBtu/hr, must be quantified according to the requirements in
paragraph (i)(4) of this section.
(5) If the SIP revision contains approved provisions for an
emissions trading program, sources that receive credit according to the
requirements of this paragraph may trade the credit to other sources or
persons according to the provisions in the trading program.
(B) The State may issue some or all of the compliance supplement
pool to sources that demonstrate a need for an extension of the May 1,
2003 compliance deadline according to the following provisions:
(1) The State shall initiate the issuance process by the later date
of September 30, 2002 or after the State issues credit according to the
procedures in paragraph (e)(3)(iv)(A) of this section.
(2) The State shall complete the issuance process by no later than
May 1, 2003.
(3) The State shall issue credit to a source only if the source
demonstrates the following:
(i) For a source used to generate electricity, compliance with the
SIP revision's applicable control measures by May 1, 2003, would create
undue risk for the reliability of the electricity supply. This
demonstration must include a showing that it would not be feasible to
import electricity from other electricity generation systems during the
installation of control technologies necessary to comply with the SIP
revision.
(ii) For a source not used to generate electricity, compliance with
the SIP revision's applicable control measures by May 1, 2003, would
create undue risk for the source or its associated industry to a degree
that is comparable to the risk described in paragraph
(e)(3)(iv)(B)(3)(i) of this section.
(iii) For a source subject to an approved SIP revision that allows
for early reduction credits in accordance with paragraph (e)(3)(iv)(A)
of this section, it was not possible for the source to comply with
applicable control measures by generating early reduction credits or
acquiring early reduction credits from other sources.
(iv) For a source subject to an approved emissions trading program,
it was not possible to comply with applicable control measures by
acquiring sufficient credit from other sources or persons subject to
the emissions trading program.
(4) The State shall ensure the public an opportunity, through a
public hearing process, to comment on the appropriateness of allocating
compliance supplement pool credits to a source under paragraph
(e)(3)(iv)(B) of this section.
(4) If, no later than November 23, 1998, any member of the public
requests revisions to the source-specific data used to establish the
State budgets set forth in paragraph (e)(2) of this section or the 2007
baseline sub-inventory information set forth in paragraph (g)(2)(ii) of
this section, then EPA will act on that request no later than January
22, 1999, provided:
(i) The request is submitted in electronic format;
(ii) Information is provided to corroborate and justify the need
for the requested modification;
(iii) The request includes the following data information regarding
any electricity-generating source at issue:
(A) Federal Information Placement System (FIPS) State Code;
(B) FIPS County Code;
(C) Plant name;
(D) Plant ID numbers (ORIS code preferred, State agency tracking
number also or otherwise);
(E) Unit ID numbers (a unit is a boiler or other combustion device);
(F) Unit type;
(G) Primary fuel on a heat input basis;
(H) Maximum rated heat input capacity of unit;
(I) Nameplate capacity of the largest generator the unit serves;
(J) Ozone season heat inputs for the years 1995 and 1996;
(K) 1996 (or most recent) average NO_X rate for the ozone
season;
(L) Latitude and longitude coordinates;
(M) Stack parameter information ;
(N) Operating parameter information;
(o) Identification of specific change to the inventory; and
(p) Reason for the change;
(iv) The request includes the following data information regarding
any non-electricity generating point source at issue:
(A) FIPS State Code;
(B) FIPS County Code;
(C) Plant name;
(D) Facility primary standard industrial classification code (SIC);

[[Page 57494]]

(E) Plant ID numbers (NEDS, AIRS/AFS, and State agency tracking
number also or otherwise);
(F) Unit ID numbers (a unit is a boiler or other combustion device);
(G) Primary source classification code (SCC);
(H) Maximum rated heat input capacity of unit;
(I) 1995 ozone season or typical ozone season daily NO_X
emissions;
(J) 1995 existing NO_X control efficiency;
(K) Latitude and longitude coordinates;
(L) Stack parameter information;
(M) Operating parameter information;
(N) Identification of specific change to the inventory; and
(O) Reason for the change;
(v) The request includes the following data information regarding
any stationary area source or nonroad mobile source at issue:
(A) FIPS State Code;
(B) FIPS County Code;
(C) Primary source classification code (SCC);
(D) 1995 ozone season or typical ozone season daily NO_X
emissions;
(E) 1995 existing NO_X control efficiency;
(F) Identification of specific change to the inventory; and
(G) Reason for the change;
(vi) The request includes the following data information regarding
any highway mobile source at issue:
(A) FIPS State Code;
(B) FIPS County Code;
(C) Primary source classification code (SCC) or vehicle type;
(D) 1995 ozone season or typical ozone season daily vehicle miles
traveled (VMT);
(E) 1995 existing NO_X control programs;
(F) identification of specific change to the inventory; and
(G) reason for the change.
(f) Each SIP revision must set forth control measures to meet the
NO_X budget in accordance with paragraph (b)(1)(i) of this
section, which include the following:
(1) A description of enforcement methods including, but not limited to:
(i) Procedures for monitoring compliance with each of the selected
control measures;
(ii) Procedures for handling violations; and
(iii) A designation of agency responsibility for enforcement of
implementation.
(2) Should a State elect to impose control measures on fossil fuel-
fired NO_X sources serving electric generators with a
nameplate capacity greater than 25 MWe or boilers, combustion turbines
or combined cycle units with a maximum design heat input greater than
250 mmBtu/hr as a means of meeting its NO_X budget, then
those measures must:
(i)(A) Impose a NO_X mass emissions cap on each source;
(B) Impose a NO_X emissions rate limit on each source and
assume maximum operating capacity for every such source for purposes of
estimating mass NO_X emissions; or
(C) Impose any other regulatory requirement which the State has
demonstrated to EPA provides equivalent or greater assurance than
options in paragraphs (f)(2)(i)(A) or (f)(2)(i)(B) of this section that
the State will comply with its NO_X budget in the 2007 ozone
season; and
(ii) Impose enforceable mechanisms to assure that collectively all
such sources, including new or modified units, will not exceed in the
2007 ozone season the total NO_X emissions projected for such
sources by the State pursuant to paragraph (g) of this section.
(3) For purposes of paragraph (f)(2) of this section, the term
``fossil fuel-fired'' means, with regard to a NO_X source:
(i) The combustion of fossil fuel, alone or in combination with any
other fuel, where fossil fuel actually combusted comprises more than 50
percent of the annual heat input on a Btu basis during any year
starting in 1995 or, if a NO_X source had no heat input
starting in 1995, during the last year of operation of the
NO_X source prior to 1995; or
(ii) The combustion of fossil fuel, alone or in combination with
any other fuel, where fossil fuel is projected to comprise more than 50
percent of the annual heat input on a Btu basis during any year;
provided that the NO_X source shall be ``fossil fuel-fired''
as of the date, during such year, on which the NO_X source
begins combusting fossil fuel.
(g)(1) Each SIP revision must demonstrate that the control measures
contained in it are adequate to provide for the timely compliance with
the State's NO_X budget during the 2007 ozone season.
(2) The demonstration must include the following:
(i) Each revision must contain a detailed baseline inventory of
NO_X mass emissions from the following sources in the year
2007, absent the control measures specified in the SIP submission:
electric generating units (EGU), non-electric generating units (non-
EGU), area, nonroad and highway sources. The State must use the same
baseline emissions inventory that EPA used in calculating the State's
NO_X budget, as set forth for the State in paragraph
(g)(2)(ii) of this section, except that EPA may direct the State to use
different baseline inventory information if the State fails to certify
that it has implemented all of the control measures assumed in
developing the baseline inventory.
(ii) The base year 2007 NO_X emissions sub-inventories
for each State, expressed in tons per ozone season, are as follows:

--------------------------------------------------------------------------------------------------------------------------------------------------------
State EGU Non-EGU Area Nonroad Highway Total
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama................................................. 76,900 49,781 25,225 16,594 50,111 218,610
Connecticut............................................. 5,600 5,273 4,588 9,584 18,762 43,807
Delaware................................................ 5,800 1,781 963 4,261 8,131 20,936
District of Columbia.................................... \1\ 0 310 741 3,470 2,082 6,603
Georgia................................................. 86,500 33,939 11,902 21,588 86,611 240,540
Illinois................................................ 119,300 55,721 7,822 47,035 81,297 311,174
Indiana................................................. 136,800 71,270 25,544 22,445 60,694 316,753
Kentucky................................................ 107,800 18,956 38,773 19,627 45,841 230,997
Maryland................................................ 32,600 10,982 4,105 17,249 27,634 92,570
Massachusetts........................................... 16,500 9,943 10,090 18,911 24,371] 79,815
Michigan................................................ 86,600 79,034 28,128 23,495 83,784 301,042
Missouri................................................ 82,100 13,433 6,603 17,723 55,230 175,089
New Jersey.............................................. 18,400 22,228 11,098 21,163 34,106 106,995
New York................................................ 39,200 25,791 15,587 29,260 80,521 190,358
North Carolina.......................................... 84,800 34,027 10,651 17,799 66,019 213,296
Ohio.................................................... 163,100 53,241 19,425 37,781 99,079 372,626
Pennsylvania............................................ 123,100 73,748 17,103 25,554 92,280 331,785

[[Page 57495]]

Rhode Island............................................ 1,100 327 420 2,073 4,375 8,295
South Carolina.......................................... 36,300 34,740 8,359 11,903 47,404 138,706
Tennessee............................................... 70,900 60,004 11,990 44,567 64,965 252,426
Virginia................................................ 40,900 39,765 18,622 21,551 70,212 191,050
West Virginia........................................... 115,500 40,192 4,790 10,220 20,185 190,887
Wisconsin............................................... 52,000 22,796 8,160 12,965 49,470 145,391
-----------------------------------------------------------------------------------------------
Total............................................. 1,501,800 757,281 290,689 456,818 1,173,163 4,179,751
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ The base case for the District of Columbia is actually projected to be 30 tons per season. The base case values in this table are rounded to the
nearest 100 tons.

(iii) Each revision must contain a summary of NO_X mass
emissions in 2007 projected to result from implementation of each of
the control measures specified in the SIP submission and from all
NO_X sources together following implementation of all such
control measures, compared to the baseline 2007 NO_X
emissions inventory for the State described in paragraph (g)(2)(i) of
this section. The State must provide EPA with a summary of the
computations, assumptions, and judgments used to determine the degree
of reduction in projected 2007 NO_X emissions that will be
achieved from the implementation of the new control measures compared
to the baseline emissions inventory.
(iv) Each revision must identify the sources of the data used in
the projection of emissions.
(h) Each revision must comply with Sec. 51.116 of this part
(regarding data availability).
(i) Each revision must provide for monitoring the status of
compliance with any control measures adopted to meet the NO_X
budget. Specifically, the revision must meet the following requirements:
(1) The revision must provide for legally enforceable procedures
for requiring owners or operators of stationary sources to maintain
records of and periodically report to the State:
(i) Information on the amount of NO_X emissions from the
stationary sources; and
(ii) Other information as may be necessary to enable the State to
determine whether the sources are in compliance with applicable
portions of the control measures;
(2) The revision must comply with Sec. 51.212 of this part
(regarding testing, inspection, enforcement, and complaints);
(3) If the revision contains any transportation control measures,
then the revision must comply with Sec. 51.213 of this part (regarding
transportation control measures);
(4) If the revision contains measures to control fossil fuel-fired
NO_X sources serving electric generators with a nameplate
capacity greater than 25 MWe or boilers, combustion turbines or
combined cycle units with a maximum design heat input greater than 250
mmBtu/hr, then the revision must require such sources to comply with
the monitoring provisions of part 75, subpart H.
(5) For purposes of paragraph (i)(4) of this section, the term
``fossil fuel-fired'' means, with regard to a NO_X source:
(i) The combustion of fossil fuel, alone or in combination with any
other fuel, where fossil fuel actually combusted comprises more than 50
percent of the annual heat input on a Btu basis during any year
starting in 1995 or, if a NO_X source had no heat input
starting in 1995, during the last year of operation of the
NO_X source prior to 1995; or
(ii) The combustion of fossil fuel, alone or in combination with
any other fuel, where fossil fuel is projected to comprise more than 50
percent of the annual heat input on a Btu basis during any year,
provided that the NO_X source shall be ``fossil fuel-fired''
as of the date, during such year, on which the NO_X source
begins combusting fossil fuel.
(j) Each revision must show that the State has legal authority to
carry out the revision, including authority to:
(1) Adopt emissions standards and limitations and any other
measures necessary for attainment and maintenance of the State's
NO_X budget specified in paragraph (e) of this section;
(2) Enforce applicable laws, regulations, and standards, and seek
injunctive relief;
(3) Obtain information necessary to determine whether air pollution
sources are in compliance with applicable laws, regulations, and
standards, including authority to require recordkeeping and to make
inspections and conduct tests of air pollution sources;
(4) Require owners or operators of stationary sources to install,
maintain, and use emissions monitoring devices and to make periodic
reports to the State on the nature and amounts of emissions from such
stationary sources; also authority for the State to make such data
available to the public as reported and as correlated with any
applicable emissions standards or limitations.
(k)(1) The provisions of law or regulation which the State
determines provide the authorities required under this section must be
specifically identified, and copies of such laws or regulations must be
submitted with the SIP revision.
(2) Legal authority adequate to fulfill the requirements of
paragraphs (j)(3) and (4) of this section may be delegated to the State
under section 114 of the CAA.
(l)(1) A revision may assign legal authority to local agencies in
accordance with Sec. 51.232 of this part.
(2) Each revision must comply with Sec. 51.240 of this part
(regarding general plan requirements).
(m) Each revision must comply with Sec. 51.280 of this part
(regarding resources).
(n) For purposes of the SIP revisions required by this section, EPA
may make a finding as applicable under section 179(a)(1)-(4) of the
CAA, 42 U.S.C. 7509(a)(1)-(4), starting the sanctions process set forth
in section 179(a) of the CAA. Any such finding will be deemed a finding
under Sec. 52.31(c) of this part and sanctions will be imposed in
accordance with the order of sanctions and the terms for such sanctions
established in Sec. 52.31 of this part.
(o) Each revision must provide for State compliance with the
reporting requirements set forth in Sec. 51.122 of this part.
(p)(1) Notwithstanding any other provision of this section, if a
State adopts regulations substantively identical to 40 CFR part 96 (the
model NO_X budget trading program for SIPs), incorporates
such part by reference into its regulations, or adopts regulations that
differ substantively from such part only as set forth in paragraph
(p)(2) of this section, then that portion of the State's SIP revision
is automatically approved as satisfying the same portion of the State's
NO_X emission reduction obligations as the State projects
such regulations will satisfy, provided that:

[[Page 57496]]

(i) The State has the legal authority to take such action and to
implement its responsibilities under such regulations, and
(ii) The SIP revision accurately reflects the NO_X
emissions reductions to be expected from the State's implementation of
such regulations.
(2) If a State adopts an emissions trading program that differs
substantively from 40 CFR part 96 in only the following respects, then
such portion of the State's SIP revision is approved as set forth in
paragraph (p)(1) of this section:
(i) The State may expand the applicability provisions of the
trading program to include units (as defined in 40 CFR 96.2) that are
smaller than the size criteria thresholds set forth in 40 CFR 96.4(a);
(ii) The State may decline to adopt the exemption provisions set
forth in 40 CFR 96.4(b);
(iii) The State may decline to adopt the opt-in provisions set
forth in subpart I of 40 CFR part 96;
(iv) The State may decline to adopt the allocation provisions set
forth in subpart E of 40 CFR part 96 and may instead adopt any
methodology for allocating NO_X allowances to individual
sources, provided that:
(A) The State's methodology does not allow the State to allocate
NO_X allowances in excess of the total amount of
NO_X emissions which the State has assigned to its trading
program; and
(B) The State's methodology conforms with the timing requirements
for submission of allocations to the Administrator set forth in 40 CFR
96.41; and
(v) The State may decline to adopt the early reduction credit
provisions set forth in 40 CFR 96.55(c) and may instead adopt any
methodology for issuing credit from the State's compliance supplement
pool that complies with paragraph (e)(3) of this section.
(3) If a State adopts an emissions trading program that differs
substantively from 40 CFR part 96 other than as set forth in paragraph
(p)(2) of this section, then such portion of the State's SIP revision
is not automatically approved as set forth in paragraph (p)(1) of this
section but will be reviewed by the Administrator for approvability in
accordance with the other provisions of this section.

Sec. 51.122 Emissions reporting requirements for SIP revisions
relating to budgets for NO_X emissions

(a) For its transport SIP revision under Sec. 51.121 of this part,
each State must submit to EPA NO_X emissions data as
described in this section.
(b) Each revision must provide for periodic reporting by the State
of NO_X emissions data to demonstrate whether the State's
emissions are consistent with the projections contained in its approved
SIP submission.
(1) Annual reporting. Each revision must provide for annual
reporting of NO_X emissions data as follows:
(i) The State must report to EPA emissions data from all
NO_X sources within the State for which the State specified
control measures in its SIP submission under Sec. 51.121(g) of this
part. This would include all sources for which the State has adopted
measures that differ from the measures incorporated into the baseline
inventory for the year 2007 that the State developed in accordance with
Sec. 51.121(g) of this part.
(ii) If sources report NO_X emissions data to EPA
annually pursuant to a trading program approved under Sec. 51.121(p) of
this part or pursuant to the monitoring and reporting requirements of
subpart H of 40 CFR part 75, then the State need not provide annual
reporting to EPA for such sources.
(2) Triennial reporting. Each plan must provide for triennial
(i.e., every third year) reporting of NO_X emissions data
from all sources within the State.
(3) Year 2007 reporting. Each plan must provide for reporting of
year 2007 NO_X emissions data from all sources within the State.
(4) The data availability requirements in Sec. 51.116 of this part
must be followed for all data submitted to meet the requirements of
paragraphs (b)(1),(2) and (3) of this section.
(c) The data reported in paragraph (b) of this section for
stationary point sources must meet the following minimum criteria:
(1) For annual data reporting purposes the data must include the
following minimum elements:
(i) Inventory year.
(ii) State Federal Information Placement System code.
(iii) County Federal Information Placement System code.
(iv) Federal ID code (plant).
(v) Federal ID code (point).
(vi) Federal ID code (process).
(vii) Federal ID code (stack).
(vii) Site name.
(viii) Physical address.
(ix) SCC.
(x) Pollutant code.
(xi) Ozone season emissions.
(xii) Area designation.
(2) In addition, the annual data must include the following minimum
elements as applicable to the emissions estimation methodology.
(i) Fuel heat content (annual).
(ii) Fuel heat content (seasonal).
(iii) Source of fuel heat content data.
(iv) Activity throughput (annual).
(v) Activity throughput (seasonal).
(vi) Source of activity/throughput data.
(vii) Spring throughput (%).
(viii) Summer throughput (%).
(ix) Fall throughput (%).
(x) Work weekday emissions.
(xi) Emission factor.
(xii) Source of emission factor.
(xiii) Hour/day in operation.
(xiv) Operations Start time (hour).
(xv) Day/week in operation.
(xvi) Week/year in operation.
(3) The triennial and 2007 inventories must include the following
data elements:
(i) The data required in paragraphs (c)(1) and (c)(2) of this section.
(ii) X coordinate (latitude).
(iii) Y coordinate (longitude).
(iv) Stack height.
(v) Stack diameter.
(vi) Exit gas temperature.
(vii) Exit gas velocity.
(viii) Exit gas flow rate.
(ix) SIC.
(x) Boiler/process throughput design capacity.
(xi) Maximum design rate.
(xii) Maximum capacity.
(xiii) Primary control efficiency.
(xiv) Secondary control efficiency.
(xv) Control device type.
(d) The data reported in paragraph (b) of this section for area
sources must include the following minimum elements:
(1) For annual inventories it must include:
(i) Inventory year.
(ii) State FIPS code.
(iii) County FIPS code.
(iv) SCC.
(v) Emission factor.
(vi) Source of emission factor.
(vii) Activity/throughput level (annual).
(viii) Activity throughput level (seasonal).
(ix) Source of activity/throughput data.
(x) Spring throughput (%).
(xi) Summer throughput (%).
(xii) Fall throughput (%).
(xiii) Control efficiency (%).
(xiv) Pollutant code.
(xv) Ozone season emissions.
(xvi) Source of emissions data.
(xvii) Hour/day in operation.
(xviii) Day/week in operation.
(xix) Week/year in operations.
(2) The triennial and 2007 inventories must contain, at a minimum,
all the data required in paragraph (d)(1) of this section.

[[Page 57497]]

(e) The data reported in paragraph (b) of this section for mobile
sources must meet the following minimum criteria:
(1) For the annual, triennial, and 2007 inventory purposes, the
following data must be reported:
(i) Inventory year.
(ii) State FIPS code.
(iii) County FIPS code.
(iv) SCC.
(v) Emission factor.
(vi) Source of emission factor.
(vii) Activity (this must be reported for both highway and nonroad
activity. Submit nonroad activity in the form of hours of activity at
standard load (either full load or average load) for each engine type,
application, and horsepower range. Submit highway activity in the form
of vehicle miles traveled (VMT) by vehicle class on each roadway type.
Report both highway and nonroad activity for a typical ozone season
weekday day, if the State uses EPA's default weekday/weekend activity
ratio. If the State uses a different weekday/weekend activity ratio,
submit separate activity level information for weekday days and weekend days).
(viii) Source of activity data.
(ix) Pollutant code.
(x) Summer work weekday emissions.
(xi) Ozone season emissions.
(xii) Source of emissions data.
(2) [Reserved]
(f) Approval of ozone season calculation by EPA. Each State must
submit for EPA approval an example of the calculation procedure used to
calculate ozone season emissions along with sufficient information for
EPA to verify the calculated value of ozone season emissions.
(g) Reporting schedules. (1) Annual reports are to begin with data
for emissions occurring in the year 2003.
(2) Triennial reports are to begin with data for emissions
occurring in the year 2002.
(3) Year 2007 data are to be submitted for emissions occurring in
the year 2007.
(4) States must submit data for a required year no later than 12
months after the end of the calendar year for which the data are collected.
(h) Data reporting procedures. When submitting a formal
NO_X budget emissions report and associated data, States
shall notify the appropriate EPA Regional Office.
(1) States are required to report emissions data in an electronic
format to one of the locations listed in this paragraph (h). Several
options are available for data reporting.
(2) An agency may choose to continue reporting to the EPA
Aerometric Information Retrieval System (AIRS) system using the AIRS
facility subsystem (AFS) format for point sources. (This option will
continue for point sources for some period of time after AIRS is
reengineered (before 2002), at which time this choice may be
discontinued or modified.)
(3) An agency may convert its emissions data into the Emission
Inventory Improvement Program/Electronic Data Interchange (EIIP/EDI)
format. This file can then be made available to any requestor, either
using E-mail, floppy disk, or value added network (VAN), or can be
placed on a file transfer protocol (FTP) site.
(4) An agency may submit its emissions data in a proprietary format
based on the EIIP data model.
(5) For options in paragraphs (h)(3) and (4) of this section, the
terms submitting and reporting data are defined as either providing the
data in the EIIP/EDI format or the EIIP based data model proprietary
format to EPA, Office of Air Quality Planning and Standards, Emission
Factors and Inventory Group, directly or notifying this group that the
data are available in the specified format and at a specific electronic
location (e.g., FTP site).
(6) For annual reporting (not for triennial reports), a State may
have sources submit the data directly to EPA to the extent the sources
are subject to a trading program that qualifies for approval under
Sec. 51.121(q) of this part, and the State has agreed to accept data in
this format. The EPA will make both the raw data submitted in this
format and summary data available to any State that chooses this option.
(i) Definitions. As used in this section, the following words and
terms shall have the meanings set forth below:
(1) Annual emissions. Actual emissions for a plant, point, or
process, either measured or calculated.
(2) Ash content. Inert residual portion of a fuel.
(3) Area designation. The designation of the area in which the
reporting source is located with regard to the ozone NAAQS. This would
include attainment or nonattainment designations. For nonattainment
designations, the classification of the nonattainment area must be
specified, i.e., transitional, marginal, moderate, serious, severe, or
extreme.
(4) Boiler design capacity. A measure of the size of a boiler,
based on the reported maximum continuous steam flow. Capacity is
calculated in units of MMBtu/hr.
(5) Control device type. The name of the type of control device
(e.g., wet scrubber, flaring, or process change).
(6) Control efficiency. The emissions reduction efficiency of a
primary control device, which shows the amount of reductions of a
particular pollutant from a process' emissions due to controls or
material change. Control efficiency is usually expressed as a
percentage or in tenths.
(7) Day/week in operations. Days per week that the emitting process
operates.
(8) Emission factor. Ratio relating emissions of a specific
pollutant to an activity or material throughput level.
(9) Exit gas flow rate. Numeric value of stack gas flow rate.
(10) Exit gas temperature. Numeric value of an exit gas stream
temperature.
(11) Exit gas velocity. Numeric value of an exit gas stream velocity.
(12) Fall throughput (%). Portion of throughput for the 3 fall
months (September, October, November). This represents the expression
of annual activity information on the basis of four seasons, typically
spring, summer, fall, and winter. It can be represented either as a
percentage of the annual activity (e.g., production in summer is 40
percent of the year's production), or in terms of the units of the
activity (e.g., out of 600 units produced, spring = 150 units, summer =
250 units, fall = 150 units, and winter = 50 units).
(13) Federal ID code (plant). Unique codes for a plant or facility,
containing one or more pollutant-emitting sources.
(14) Federal ID code (point). Unique codes for the point of
generation of emissions, typically a physical piece of equipment.
(15) Federal ID code (stack number). Unique codes for the point
where emissions from one or more processes are released into the atmosphere.
(16) Federal Information Placement System (FIPS). The system of
unique numeric codes developed by the government to identify States,
counties, towns, and townships for the entire United States, Puerto
Rico, and Guam.
(17) Heat content. The thermal heat energy content of a solid,
liquid, or gaseous fuel. Fuel heat content is typically expressed in
units of Btu/lb of fuel, Btu/gal of fuel, joules/kg of fuel, etc.
(18) Hr/day in operations. Hours per day that the emitting process
operates.
(19) Maximum design rate. Maximum fuel use rate based on the
equipment's or process' physical size or operational capabilities.
(20) Maximum nameplate capacity. A measure of the size of a
generator which is put on the unit's nameplate by the manufacturer. The
data element is reported in megawatts (MW) or kilowatts (KW).

[[Page 57498]]

(21) Mobile source. A motor vehicle, nonroad engine or nonroad
vehicle, where:
(i) Motor vehicle means any self-propelled vehicle designed for
transporting persons or property on a street or highway;
(ii) Nonroad engine means an internal combustion engine (including
the fuel system) that is not used in a motor vehicle or a vehicle used
solely for competition, or that is not subject to standards promulgated
under section 111 or section 202 of the CAA;
(iii) Nonroad vehicle means a vehicle that is powered by a nonroad
engine and that is not a motor vehicle or a vehicle used solely for
competition.
(22) Ozone season. The period May 1 through September 30 of a year.
(23) Physical address. Street address of facility.
(24) Point source. A non-mobile source which emits 100 tons of
NO_X or more per year unless the State designates as a point
source a non-mobile source emitting at a specified level lower than 100
tons of NO_X per year. A non-mobile source which emits less
NO_X per year than the point source threshold is an area source.
(25) Pollutant code. A unique code for each reported pollutant that
has been assigned in the EIIP Data Model. Character names are used for
criteria pollutants, while Chemical Abstracts Service (CAS) numbers are
used for all other pollutants. Some States may be using storage and
retrieval of aerometric data (SAROAD) codes for pollutants, but these
should be able to be mapped to the EIIP Data Model pollutant codes.
(26) Process rate/throughput. A measurable factor or parameter that
is directly or indirectly related to the emissions of an air pollution
source. Depending on the type of source category, activity information
may refer to the amount of fuel combusted, the amount of a raw material
processed, the amount of a product that is manufactured, the amount of
a material that is handled or processed, population, employment, number
of units, or miles traveled. Activity information is typically the
value that is multiplied against an emission factor to generate an
emissions estimate.
(27) SCC. Source category code. A process-level code that describes
the equipment or operation emitting pollutants.
(28) Secondary control efficiency (%). The emissions reductions
efficiency of a secondary control device, which shows the amount of
reductions of a particular pollutant from a process' emissions due to
controls or material change. Control efficiency is usually expressed as
a percentage or in tenths.
(29) SIC. Standard Industrial Classification code. U.S. Department
of Commerce's categorization of businesses by their products or services.
(30) Site name. The name of the facility.
(31) Spring throughput (%). Portion of throughput or activity for
the 3 spring months (March, April, May). See the definition of Fall
Throughput.
(32) Stack diameter. Stack physical diameter.
(33) Stack height. Stack physical height above the surrounding terrain.
(34) Start date (inventory year). The calendar year that the
emissions estimates were calculated for and are applicable to.
(35) Start time (hour). Start time (if available) that was
applicable and used for calculations of emissions estimates.
(36) Summer throughput (%). Portion of throughput or activity for
the 3 summer months (June, July, August). See the definition of Fall
Throughput.
(37) Summer work weekday emissions. Average day's emissions for a
typical day.
(38) VMT by Roadway Class. This is an expression of vehicle
activity that is used with emission factors. The emission factors are
usually expressed in terms of grams per mile of travel. Since VMT does
not directly correlate to emissions that occur while the vehicle is not
moving, these non-moving emissions are incorporated into EPA's MOBILE
model emission factors.
(39) Week/year in operation. Weeks per year that the emitting
process operates.
(40) Work Weekday. Any day of the week except Saturday or Sunday.
(41) X coordinate (latitude). East-west geographic coordinate of an
object.
(42) Y coordinate (longitude). North-south geographic coordinate of
an object.

PART 72--PERMITS REGULATION

1. The authority for part 72 continues to read as follows:

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

2. Section 72.2 is amended by revising the definition for
``excepted monitoring system,'' and adding new definitions in
alphabetical order for ``low mass emissions unit'', ``maximum potential
hourly heat input'', ``maximum rated hourly heat input,'' and ``ozone
season'' to read as follows:

Sec. 72.2 Definitions.

* * * * *
Excepted monitoring system means a monitoring system that follows
the procedures and requirements of Sec. 75.19 of this chapter or of
appendix D or E to part 75 for approved exceptions to the use of
continuous emission monitoring systems.
* * * * *
Low mass emissions unit means an affected unit that is a gas-fired
or oil-fired unit, burns only natural gas or fuel oil and qualifies
under Sec. 75.19 of this chapter.
* * * * *
Maximum potential hourly heat input means an hourly heat input used
for reporting purposes when a unit lacks certified monitors to report
heat input. If the unit intends to use appendix D of part 75 of this
chapter to report heat input, this value should be calculated, in
accordance with part 75 of this chapter, using the maximum fuel flow
rate and the maximum gross calorific value. If the unit intends to use
a flow monitor and a diluent gas monitor, this value should be
reported, in accordance with part 75 of this chapter, using the maximum
potential flow rate and either the maximum carbon dioxide concentration
(in percent CO₂) or the minimum oxygen concentration (in
percent O₂).
* * * * *
Maximum rated hourly heat input means a unit-specific maximum
hourly heat input (mmBtu) which is the higher of the manufacturer's
maximum rated hourly heat input or the highest observed hourly heat input.
* * * * *
Ozone season means the period of time beginning May 1 of a year and
ending on September 30 of the same year, inclusive.
* * * * *

PART 75--CONTINUOUS EMISSION MONITORING

3. The authority citation for part 75 continues to read as follows:

Authority: 42 U.S.C. 7601 and 7651k, 7651 and note.

4. Section 75.1 is amended by revising paragraph (a) to read as
follows:

Sec. 75.1 Purpose and scope.

(a) Purpose. The purpose of this part is to establish requirements
for the monitoring, recordkeeping, and reporting of sulfur dioxide
(SO₂), nitrogen oxides (NO_X), and carbon dioxide
(CO₂) emissions, volumetric flow, and opacity data from
affected units under the Acid Rain Program pursuant to sections 412 and
821 of the CAA, 42 U.S.C. 7401-7671q as amended by Public Law 101-549
(November 15, 1990). In addition, this part sets forth

[[Page 57499]]

provisions for the monitoring, recordkeeping, and reporting of
NO_X mass emissions with which EPA, individual States, or
groups of States may require sources to comply in order to demonstrate
compliance with a NO_X mass emission reduction program, to
the extent these provisions are adopted as requirements under such a
program.
* * * * *
5. Section 75.2 is amended by revising paragraph (a) and adding a
new paragraph (c) to read as follows:

Sec. 75.2 Applicability.

(a) Except as provided in paragraphs (b) and (c) of this section,
the provisions of this part apply to each affected unit subject to Acid
Rain emission limitations or reduction requirements for SO₂
or NO_X.
* * * * *
(c) The provisions of this part apply to sources subject to a State
or federal NO_X mass emission reduction program, to the
extent these provisions are adopted as requirements under such a program.
6. Section 75.4 is amended by revising paragraph (a) introductory
text to read as follows:

Sec. 75.4 Compliance dates.

(a) The provisions of this part apply to each existing Phase I and
Phase II unit on February 10, 1993. For substitution or compensating
units that are so designated under the Acid Rain permit which governs
that unit and contains the approved substitution or reduced utilization
plan, pursuant to Sec. 72.41 or Sec. 72.43 of this chapter, the
provisions of this part become applicable upon the issuance date of the
Acid Rain permit. For combustion sources seeking to enter the Opt-in
Program in accordance with part 74 of this chapter, the provisions of
this part become applicable upon the submission of an opt-in permit
application in accordance with Sec. 74.14 of this chapter. The
provisions of this part for the monitoring, recording, and reporting of
NO_X mass emissions become applicable on the deadlines
specified in the applicable State or federal NO_X mass
emission reduction program, to the extent these provisions are adopted
as requirements under such a program. In accordance with Sec. 75.20,
the owner or operator of each existing affected unit shall ensure that
all monitoring systems required by this part for monitoring
SO₂, NO_X, CO₂, opacity, and volumetric
flow are installed and that all certification tests are completed no
later than the following dates (except as provided in paragraphs (d)
through (h) of this section):
* * * * *
7. Section 75.6 is amended by adding paragraph (f) to read as follows:

Sec. 75.6 Incorporation by reference.

* * * * *
(f) The following materials are available for purchase from the
following address: American Petroleum Institute, Publications
Department, 1220 L Street NW, Washington, DC 20005-4070.
(1) American Petroleum Institute (API) Petroleum Measurement
Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for
the Manual Gauging of Petroleum and Petroleum Products, December 1994;
Section 1B, Standard Practice for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992
(reaffirmed January 1997); Section 2, Standard Practice for Gauging
Petroleum and Petroleum Products in Tank Cars, September 1995; Section
3, Standard Practice for Level Measurement of Liquid Hydrocarbons in
Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June
1996; Section 4, Standard Practice for Level Measurement of Liquid
Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995;
and Section 5, Standard Practice for Level Measurement of Light
Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging,
March 1997; for Sec. 75.19.
(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B,
December 1961 (Reaffirmed August 1987, October 1992), for Sec. 75.19.
8. Section 75.11 is amended by removing the period at the end of
paragraph (d)(2) and replacing it with ``; or'' and adding paragraph
(d)(3), to read as follows:

Sec. 75.11 Specific provisions for monitoring SO₂ emissions
(SO₂ and flow monitors).

* * * * *
(d)* * *
(3) By using the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly SO₂ mass emissions if
the affected unit qualifies as a low mass emissions unit under
Sec. 75.19(a) and (b).
* * * * *
9. Section 75.12 is amended by revising the section heading, by
redesignating paragraph (d) as paragraph (e), and by adding new
paragraph (d) to read as follows:

Sec. 75.12 Specific provisions for monitoring NO_X emission
rate (NO_X and diluent gas monitors).

* * * * *
(d) Low mass emissions units. Notwithstanding the requirements of
paragraphs (a) and (c) of this section, the owner or operator of an
affected unit that qualifies as a low mass emissions unit under
Sec. 75.19(a) and (b) shall comply with one of the following:
(1) Meet the general operating requirements in Sec. 75.10 for a
NO_X continuous emission monitoring system;
(2) Meet the requirements specified in paragraph (d)(2) of this
section for using the excepted monitoring procedures in appendix E to
this part, if applicable; or
(3) Use the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly NO_X emission rate and
hourly NO_X mass emissions, if applicable under Sec. 75.19(a)
and (b).
* * * * *
10. Section 75.13 is amended by adding paragraph (d) to read as
follows:

Sec. 75.13 Specific provisions for monitoring CO₂ emissions.

* * * * *
(d) Determination of CO₂ mass emissions from low mass
emissions units. The owner or operator of a unit that qualifies as a
low mass emissions unit under Sec. 75.19(a) and (b) shall comply with
one of the following:
(1) Meet the general operating requirements in Sec. 75.10 for a
CO₂ continuous emission monitoring system and flow
monitoring system;
(2) Meet the requirements specified in paragraph (b) or (c) of this
section for use of the methods in appendix G or F to this part,
respectively; or
(3) Use the low mass emissions excepted methodology in
Sec. 75.19(c) for estimating hourly CO₂ mass emissions, if
applicable under Sec. 75.19(a) and (b).
* * * * *
11. Section 75.17 is amended by adding introductory text before
paragraph (a) to read as follows:

Sec. 75.17 Specific provisions for monitoring emissions from common,
by-pass, and multiple stacks for NO_X emission rate.

Notwithstanding the provisions of paragraphs (a), (b), and (c) of
this section, the owner or operator of an affected unit that is using
the procedures in this part to meet the monitoring and reporting
requirements of a State or federal NO_X mass emission
reduction program must also meet the provisions for monitoring
NO_X emission rate in Secs. 75.71 and 75.72.
* * * * *
12. Section 75.19 is added to subpart B to read as follows:

[[Page 57500]]

Sec. 75.19 Optional SO₂, NO_X, and CO₂
emissions calculation for low mass emissions units.

(a) Applicability. (1) Consistent with the requirements of
paragraphs (a)(2) and (b) of this section, the low mass emissions
excepted methodology in paragraph (c) of this section may be used in
lieu of continuous emission monitoring systems or, if applicable, in
lieu of excepted methods under appendix D or E to this part, for the
purpose of determining hourly heat input and hourly NO_X,
SO₂, and CO₂ mass emissions from a low mass
emissions unit.
(i) A low mass emissions unit is an affected unit that is gas-
fired, or oil-fired unit, that burns only natural gas or fuel oil and
for which:
(A) An initial demonstration is provided, in accordance with
paragraph (a)(2) of this section, which shows that the unit emits no
more than 25 tons of SO₂ annually and no more than 50 tons
of NO_X annually; and
(B) An annual demonstration is provided thereafter, using one of
the allowable methodologies in paragraph (c) of this section, showing
that the low mass emission unit continues to emit no more than 25 tons
of SO₂ annually and no more than 50 tons of NO_X
annually.
(ii) Any qualifying unit must start using the low mass emissions
excepted methodology in the first hour in which the unit operates in a
calendar year. Notwithstanding, the earliest date for which a unit that
meets the eligibility requirements of this section may begin to use
this methodology is January 1, 2000.
(2) A unit may initially qualify as a low mass emissions unit only
under the following circumstances:
(i) If the designated representative submits a certification
application to use the low mass emissions excepted methodology and the
Administrator certifies the use of such methodology. The certification
application must contain:
(A) Actual SO₂ and NO_X mass emissions data
for each of the three calendar years prior to the calendar year in
which the certification application is submitted demonstrating to the
satisfaction of the Administrator that the unit emits less than 25 tons
of SO₂ and less than 50 tons of NO_X annually; and
(B) Calculated SO₂ and NO_X mass emissions,
for each of the three calendar years prior to the calendar year in
which the certification application is submitted, demonstrating to the
satisfaction of the Administrator that the unit emits less than 25 tons
of SO₂ and less than 50 tons of NO_X annually. The
calculated emissions for each year shall be determined using either the
maximum rated heat input methodology described in paragraph (c)(3)(i)
of this section or the long term fuel flow heat input methodology
described in paragraph (c)(3)(ii) of this section, in conjunction with
the appropriate SO₂, NO_X, and CO₂
emission rate from paragraph (c)(1)(i) of this section for
SO₂, paragraph (c)(1)(ii) or (c)(1)(iv) of this section for
NO_X and paragraph (c)(1)(iii) of this section for
CO₂; or
(ii) When the three full years of actual, historical SO₂
and NO_X mass emissions data required under paragraph
(a)(2)(i) of this section are not available, the designated
representative may submit an application to use the low mass emissions
excepted methodology based upon a combination of historical
SO₂ and NO_X mass emissions data and projected
SO₂ and NO_X mass emissions, totaling three years.
Historical data must be used for any years in which historical data
exists and projected data should be used for any remaining future years
needed to provide capacity factor data for three consecutive calender
years. For example, if a unit commenced operation two years ago, the
designated representative may submit actual, historical data for the
previous two years and one year of projected emissions for the current
calendar year or, for unit that commenced operation after January 1,
1997, the designated representative may submit three years of projected
emissions, beginning with the current calendar year. Any actual or
projected annual emissions must demonstrate to the satisfaction of the
Administrator that the unit will emit less than 25 tons of
SO₂ and less than 50 tons of NO_X annually.
Projected emissions shall be calculated using either the default
emission rates in tables 1,2 and 3 of this section, or for
NO_X emission rate a fuel-and-unit-specific NO_X
emission rate determined in accordance with the testing procedures in
paragraph (c)(1)(iv) of this section, in conjunction with projections
of unit operating hours or fuel type and fuel usage, according to one
of the allowable calculation methodologies in paragraph (c) of this
section.
(b) On-going qualification and disqualification. (1) Once a low
mass emission unit has qualified for and has started using the low mass
emissions excepted methodology, an annual demonstration is required,
showing that the unit continues to emit less than 25 tons of
SO₂ annually and less than 50 tons of NO_X
annually. The calculation methodology used for the annual demonstration
shall be the same methodology, from paragraph (c) of this section, by
which the unit initially qualified to use the low mass emissions
excepted methodology.
(2) If any low mass emission unit fails to provide the required
annual demonstration under paragraph (b)(1) of this section, such that
the calculated cumulative year-to-date emissions for the unit exceed 25
tons of SO₂ or 50 tons of NO_X in any calendar
quarter of any calendar year, then;
(i) The low mass emission unit shall be disqualified from using the
low mass emissions excepted methodology as of the end of the second
calendar quarter following such quarter in which either the 25 ton
limit for SO₂ or the 50 ton limit for NO_X was
exceeded; and
(ii) The owner or operator of the low mass emission unit shall have
two calendar quarters from the end of the quarter in which the unit
exceeded the 25 ton limit for SO₂ or the 50 ton limit for
NO_X to install, certify, and report SO₂,
NO_X, and CO₂ emissions from monitoring systems
that meet the requirements of Secs. 75.11, 75.12, and 75.13.
(3) If a low mass emission unit that initially qualifies to use the
low mass emissions excepted methodology under this section changes
fuels, such that a fuel other than those allowed for use in the low
mass emissions methodology (e.g. natural gas or fuel oil) is combusted
in the unit, the unit shall be disqualified from using the low mass
emissions excepted methodology as of the first hour that the new fuel
is combusted in the unit. The owner or operator shall install, certify,
and report SO₂, NO_X, and CO₂ from
monitoring systems that meet the requirements of Secs. 75.11, 75.12,
and 75.13 prior to a change to such fuel. The owner or operator must
notify the Administrator in the case where a unit switches fuels
without previously having installed and certified a SO₂,
NO_X and CO₂ monitoring system meeting the
requirements of Secs. 75.11, 75.12, and 75.13.
(4) If a unit commencing operation after January 1, 1997 initially
qualifies to use the low mass emissions excepted methodology under this
section and the owner or operator wants to use a low mass emissions
methodology for the unit, he or she must:
(i) Keep the records specified in paragraph (c)(2) of this section,
beginning with the date and hour of commencement of commercial
operation, for a unit subject to an Acid Rain emission limitation, and
beginning with the date and hour of the commencement of operation, for
a unit subject to a NO_X mass reduction program;

[[Page 57501]]

(ii) Use these records to determine the cumulative heat input and
SO₂, NO_X, and CO₂ mass emissions in
order to continue to qualify as a low mass emission unit; and
(iii) Determine the cumulative SO₂ and NO_X
mass emissions according to paragraph (c) of this section using the
same procedures used after the certification deadline for the unit, for
purposes of demonstrating eligibility to use the excepted methodology
set forth in this section. For example, use the default emission rates
in tables 1, 2 and 3 of this section or use the fuel-and-unit-specific
NO_X emission rate determined according to paragraph
(c)(1)(iv) of this section. The Administrator will not count
SO₂ mass emissions calculated for the period between
commencement of commercial operation and the certification deadline for
the unit under Sec. 75.4 against SO₂ allowances to be held
in the unit account.
(5) A low mass emission unit that has been disqualified from using
the low mass emissions excepted methodology may subsequently qualify
again to use the low mass emissions methodology under paragraph (a)(2)
of this section, provided that if such unit qualified under paragraph
(a)(2)(ii) of this section, the unit may subsequently qualify again
only if the unit meets the requirements of paragraph (a)(2)(i) of this
section.
(c) Low mass emissions excepted methodology, calculations, and values.
(1) Determination of SO₂, NO_X, and
CO₂ emission rates.
(i) Use Table 1 of this section to determine the appropriate
SO₂ emission rate for use in calculating hourly
SO₂ mass emissions under this section.
(ii) Use either the appropriate NO_X emission factor from
Table 2 of this section, or a fuel-and-unit-specific NO_X
emission rate determined according to paragraph (c)(1)(iv) of this
section, to calculate hourly NO_X mass emissions under this section.
(iii) Use Table 3 of this section to determine the appropriate
CO₂ emission rate for use in calculating hourly
CO₂ mass emissions under this section.
(iv) In lieu of using the default NO_X emission rate from
Table 2 of this section, the owner or operator may, for each fuel
combusted by a low mass emission unit, determine a fuel-and-unit-
specific NO_X emission rate for the purpose of calculating
NO_X mass emissions under this section. This option may be
used by any unit which qualifies to use the low mass emission excepted
methodology under paragraph (a) of this section, and also by groups of
units which combust fuel from a common source of supply and which use
the long term fuel flow methodology under paragraph (c)(3)(ii) of this
section to determine heat input. If this option is chosen, the
following procedures shall be used.
(A) Except as otherwise provided in paragraphs (c)(1)(iv)(F) and
(G) of this paragraph, determine a fuel-and-unit-specific
NO_X emission rate by conducting a four load NO_X
emission rate test procedure as specified in section 2.1 of appendix E
to this part, for each type of fuel combusted in the unit. For a group
of units sharing a common fuel supply, the appendix E testing must be
performed on each individual unit in the group, unless some or all of
the units in the group belong to an identical group of units, as
defined in paragraph (c)(1)(iv)(B) of this section, in which case,
representative testing may be conducted on units in the identical group
of units, as described in paragraph (c)(1)(iv)(B) of this section. For
the purposes of this section, make the following modifications to the
appendix E test procedures:
(1) Do not measure the heat input as required under 2.1.3 of
appendix E to this part.
(2) Do not plot the test results as specified under 2.1.6 of
appendix E to this part.
(B) Representative appendix E testing may be done on low mass
emission units in a group of identical units. All of the units in a
group of identical units must combust the same fuel type but do not
have to share a common fuel supply.
(1) To be considered identical, all low mass emission units must be
of the same size (based on maximum rated hourly heat input),
manufacturer and model, and must have the same history of modifications
(e.g., have the same controls installed, the same types of burners and
have undergone major overhauls at the same frequency (based on hours of
operation)). Also, under similar operating conditions, the stack or
turbine outlet temperature of each unit must be within 50
degrees Fahrenheit of the average stack or turbine outlet temperature
for all of the units.
(2) If all of the low mass emission units in the group qualify as
identical, then representative testing of the units in the group may be
performed according to Table 4 of this section.
(3) If there are only two low mass emission units in the group of
identical units, the results of the representative testing under
paragraph (c)(1)(iv)(B)(1) of this section may be used to establish the
fuel-and-unit-specific NO_X emission rate(s) for the units.
However, if there are more than two low mass emission units in the
group, the testing must confirm that the units are identical by meeting
the following criteria. The results of the representative testing may
only be used to establish the fuel-and-unit-specific NO_X
emission rate(s) for such units if the following criteria are met:
(i) at each of the four load levels tested, the NO_X
emission rate for each tested low mass emission unit does not differ by
more than 10% from the average of the NO_X
emission rates for all units tested, or;
(ii) if the average NO_X emission rate of all low mass
emission units tested at all four load levels is less than 0.20 lb/
mmBtu, an alternative criteria of 0.020 lb/mmBtu may be use
in lieu of the 10% criteria. Units must all be within +0.020 lb/mmBtu
of the average from the test to be considered identical units under
this section.
(4) If the acceptance criteria in paragaph (c)(1)(iv)(B)(3) of this
section are not met then the group of low mass emission units is not
considered an identical group of units and individual appendix E
testing of each unit is required.
(5) Fuel and unit specific NO_X emission rates determined
according to paragraphs (c)(1)(iv)(F) and (c)(1)(iv)(G) of this section
may be used in lieu of appendix E testing for one or more low mass
emission units in a group of identical units.
(C) Based on the results of the appendix E testing, determine the
fuel-and-unit-specific NO_X emission rate as follows:
(1) For an individual low mass emission unit with no NO_X
emissions controls of any kind, the highest NO_X emission
rate obtained for a particular type of fuel in the appendix E test
multiplied by 1.15 shall be the fuel-and-unit-specific NO_X
emission rate, for that type of fuel.
(2) For a group of low mass emission units sharing a common fuel
supply with no NO_X controls of any kind on any of the units,
the highest NO_X emission rate obtained for a particular type
of fuel in all of the appendix E tests of all units in the group of
units sharing a common fuel supply multiplied by 1.15 shall be the
fuel-and-unit-specific NO_X emission rate for each unit in
the group, for that type of fuel.
(3) For a group of identical low mass emission units which perform
representative testing according to paragraph (c)(1)(iv)(B) of this
section with no NO_X controls of any kind on any of the
units, the fuel-and-unit-specific NO_X emission rate for all
units, for a particular type of fuel, multiplied by 1.15 shall be the
highest NO_X

[[Page 57502]]

emission rate from any unit tested in the group, for that type of fuel.
(4) For an individual low mass emission unit which has
NO_X emission controls of any kind, the fuel-and-unit-
specific NO_X emission rate for each type of fuel combusted
in the unit shall be the higher of:
(i) The highest emission rate from the appendix E test for that
type of fuel multiplied by 1.15; or
(ii) 0.15 lb/mmBtu.
(5) For a group of low mass emission units sharing a common fuel
supply, one or more of which has NO_X controls of any kind,
the fuel-and-unit-specific NO_X emission rate for each unit
in the group of units sharing a common fuel supply shall, for a
particular type of fuel combusted by the group of units sharing a
common fuel supply, shall be the higher of:
(i) The highest NO_X emission rate from all appendix E
tests of all low mass emission units in the group for that type of fuel
multiplied by 1.15; or
(ii) 0.15 lb/mmBtu.
(6) For a group of identical low mass emission units, which perform
representative testing according to paragraph (c)(1)(iv)(B) of this
section and have identical NO_X controls, the fuel-and-unit-
specific NO_X emission rate for each unit in the group of
units, for a particular type of fuel, shall be the higher of:
(i) The highest NO_X emission rate from all appendix E
tests of all tested low mass emission units in the group of identical
units for that type of fuel multiplied by 1.15; or
(ii) 0.15 lb/mmBtu.
(D) For each low mass emission unit, each unit in a group of units
sharing a common fuel supply, or identical units for which the
provisions of paragraph (c)(1)(iv) of this section are used to account
for NO_X emission rate, the owner or operator shall determine
a new fuel-and-unit-specific NO_X emission rate every five
years, unless changes in the fuel supply, physical changes to the unit,
changes in the manner of unit operation, or changes to the emission
controls occur which may cause a significant increase in the unit's
actual NO_X emission rate. If such changes occur, the fuel-
and-unit-specific NO_X emission rate(s) shall be re-
determined according to paragraph (c)(1)(iv) of this section. If a low
mass emission unit belongs to a group of identical units and it is
required to retest to determine a new fuel-and-unit-specific
NO_X emission rate because of changes in the fuel supply,
physical changes to the unit, changes in the manner of unit operation
or changes to the emission controls occur which may cause a significant
increase in the unit's actual NO_X emission rate, any other
unit in that group of identical units is not required to re-determine
the fuel-and-unit-specific NO_X emission rate unless such
unit also undergoes changes in the fuel supply, physical changes to the
unit, changes in the manner of unit operation or changes to the
emission controls occur which may cause a significant increase in the
unit's actual NO_X emission rates.
(E) Each low mass emission unit, each low mass emission unit in a
group of units combusting a common fuel, or each low mass emission unit
in a group of identical units for which a fuel-and-unit-specific
NO_X emission rate(s) are determined shall meet the quality
assurance and quality control provisions of paragraph (e) of this section.
(F) Low mass emission units may use the results of appendix E
testing, if such test results are available from a test conducted no
more than five years prior to the time of initial certification, to
determine the appropriate fuel-and-unit-specific NO_X
emission rate(s). However, fuel-and-unit-specific NO_X
emission rates from historical testing may not be used longer than five
years after the appendix E testing was conducted.
(G) Low mass emission units for which at least 3 years of
NO_X emission rate continuous emissions monitoring system
data and corresponding fuel usage data are available may determine
fuel-and-unit-specific NO_X emission rates from the actual
data using the following procedure. Separate the actual NO_X
emission rate data into groups, according to the type of fuel
combusted. Discard data from periods when multiple fuels were
combusted. Each fuel-specific data set must contain at least 168 hours
of data and must represent all normal operating ranges of the unit when
combusting the fuel. Sort the data in each fuel-specific data set in
ascending order according to NO_X emission rate. Determine
the 95th percentile NO_X emission rate for each data set as
defined in Sec. 72.2 of this chapter. Use the 95th percentile value for
each data set as the fuel-and-unit-specific NO_X emission
rate, except that for a unit with NO_X emission controls of
any kind, if the 95th percentile value is less than 0.15 lb/mmBtu, a
value of 0.15 lb/mmBtu shall be used as the fuel-and-unit-specific
NO_X emission rate.
(H) For low mass emission units with NO_X emission
controls, the owner or operator shall, during every hour of unit
operation during the test period, monitor and record parameters, as
required under paragraph (e)(5) of this section, which indicate that
the NO_X emission controls are operating properly. After the
test period, these same parameters shall be monitored and recorded and
kept for all operating hours in order to determine whether the
NO_X controls are operating properly and to allow the
determination of the correct NO_X emission rate as required
under paragraph (c)(1)(iv) of this section.
(1) For low mass emission units with steam or water injection, the
steam-to-fuel or water-to-fuel ratio used during the testing must be
documented. The water-to-fuel or steam-to-fuel ratio must be maintained
during unit operations for a unit to use the fuel and unit specific
NO_X emission rate determined during the test. Owners or
operators must include in the monitoring plan the acceptable range of
the water-to-fuel or steam-to-fuel ratio, which will be used to
indicate hourly, proper operation of the NO_X controls for
each unit. The water-to-fuel or steam-to-fuel ratio shall be monitored
and recorded during each hour of unit operation. If the water-to-fuel
or steam-to-fuel ratio is not within the acceptable range in a given
hour the fuel and unit specific NO_X emission rate may not be
used for that hour.
(2) For low mass emission units with other types of NO_X
controls, appropriate parameters and the acceptable range of the
parameters which indicate hourly proper operation of the NO_X
controls must be specified in the monitoring plan. These parameters
shall be monitored during each subsequent operating hour. If any of
these parameters are not within the acceptable range in a given
operating hour, the fuel and unit specific NO_X emission
rates may not be used in that hour.
(2) Records of operating time, fuel usage, unit output and
NO_X emission control operating status. The owner or operator
shall keep the following records on-site, for three years, in a form
suitable for inspection:
(i) For each low mass emission unit, the owner or operator shall
keep hourly records which indicate whether or not the unit operated
during each clock hour of each calendar year. The owner or operator may
report partial operating hours or may assume that for each hour the
unit operated the operating time is a whole hour. Units using partial
operating hours and the maximum rated hourly heat input to calculate
heat input for each hour must report partial operating hours.
(ii) For each low mass emissions unit, the owner or operator shall
keep hourly records indicating the type(s) of fuel(s) combusted in the
unit during each hour of unit operation.
(iii) For each low mass emission unit using the long term fuel flow
methodology under paragraph (c)(3)(ii)

[[Page 57503]]

of this section to determine hourly heat input, the owner or operator
shall keep hourly records of unit output (in megawatts or thousands of
pounds of steam), for the purpose of apportioning heat input to the
individual unit operating hours.
(iv) For each low mass emission unit with NO_X emission
controls of any kind, the owner or operator shall keep hourly records
of the hourly value of the parameter(s) specified in (c)(1)(iv)(H) of
this section used to indicate proper operation of the unit's
NO_X controls.
(3) Heat input. Hourly, quarterly and annual heat input for a low
mass emission unit shall be determined using either the maximum rated
hourly heat input method under paragraph (c)(3)(i) of this section or
the long term fuel flow method under paragraph (c)(3)(ii) of this section.
(i) Maximum rated hourly heat input method. (A) For the purposes of
the mass emission calculation methodology of paragraph (c)(3) of this
section, the hourly heat input (mmBtu) to a low mass emission unit
shall be deemed to equal the maximum rated hourly heat input, as
defined in Sec. 72.2 of this chapter, multiplied by the operating time
of the unit for each hour. The owner or operator may choose to record
and report partial operating hours or may assume that a unit operated
for a whole hour for each hour the unit operated. However, the owner or
operator of a unit may petition the Administrator under Sec. 75.66 for
a lower value for maximum rated hourly heat input than that defined in
Sec. 72.2 of this chapter. The Administrator may approve such lower
value if the owner or operator demonstrates that either the maximum
hourly heat input specified by the manufacturer or the highest observed
hourly heat input, or both, are not representative, and such a lower
value is representative, of the unit's current capabilities because
modifications have been made to the unit, limiting its capacity permanently.
(B) The quarterly heat input, HI_qtr, in mmBtu, shall be
determined using Equation LM-1:

HI_qtr = T_qtr x HI_hr (Eq. LM-1)

Where:

T_qtr = Actual number of operating hours in the quarter (hr).
HI_hr = Hourly heat input under paragraph (c)(3)(i)(A) of
this section (mmBtu).
(C) The year-to-date cumulative heat input (mmBtu) shall be the sum
of the quarterly heat input values for all of the calendar quarters in
the year to date.
(ii) Long term fuel flow heat input method. The owner or operator
may, for the purpose of demonstrating that a low mass emission unit or
group of low mass emission units sharing a common fuel supply meets the
requirements of this section, use records of long-term fuel flow, to
calculate hourly heat input to a low mass emission unit.
(A) This option may be used for a group of low mass emission units
only if:
(1) The low mass emission units combust fuel from a common source
of supply; and
(2) Records are kept of the total amount of fuel combusted by the
group of low mass emission units and the hourly output (in megawatts or
pounds of steam) from each unit in the group; and
(3) All of the units in the group are low mass emission units.
(B) For each fuel used during the quarter, the volume in standard
cubic feet (for gas) or gallons (for oil) may be determined using any
of the following methods;
(1) Fuel billing records (for low mass emission units, or groups of
low mass emission units, which purchase fuel from non-affiliated sources);
(2) American Petroleum Institute (API) standard, American Petroleum
Institute (API) Petroleum Measurement Standards, Chapter 3, Tank
Gauging: Section 1A, Standard Practice for the Manual Gauging of
Petroleum and Petroleum Products, December 1994; Section 1B, Standard
Practice for Level Measurement of Liquid Hydrocarbons in Stationary
Tanks by Automatic Tank Gauging, April 1992 (reaffirmed January 1997);
Section 2, Standard Practice for Gauging Petroleum and Petroleum
Products in Tank Cars, September 1995; Section 3, Standard Practice for
Level Measurement of Liquid Hydrocarbons in Stationary Pressurized
Storage Tanks by Automatic Tank Gauging, June 1996; Section 4, Standard
Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels
by Automatic Tank Gauging, April 1995; and Section 5, Standard Practice
for Level Measurement of Light Hydrocarbon Liquids Onboard Marine
Vessels by Automatic Tank Gauging, March 1997; Shop Testing of
Automatic Liquid Level Gages, Bulletin 2509 B, December 1961
(Reaffirmed August 1987, October 1992) (incorporated by reference under
Sec. 75.6); or;
(3) A fuel flow meter certified and maintained according to
appendix D to this part.
(C) For each fuel combusted during a quarter, the gross calorific
value of the fuel shall be determined by either:
(1) Using the applicable procedures for gas and oil analysis in
sections 2.2 and 2.3 of appendix D to this part. If this option is
chosen the highest gross calorific value recorded during the previous
calendar year shall be used; or
(2) Using the appropriate default gross calorific value listed in
Table 5 of this section.
(D) For each type of fuel oil combusted during the quarter, the
specific gravity of the oil shall be determined either by:
(1) Using the procedures in section 2.2.6 of appendix D to this
part. If this option is chosen, use the highest specific gravity value
recorded during the previous calendar year shall be used; or
(2) Using the appropriate default specific gravity value in Table 5
of this section.
(E) The quarterly heat input from each type of fuel combusted
during the quarter by a low mass emission unit or group of low mass
emission units sharing a common fuel supply shall be determined using
Equation LM-2 for oil and LM-3 for natural gas.

[GRAPHIC] [TIFF OMITTED] TR27OC98.001

Eq LM-2 (for fuel oil or diesel fuel)

Where:

HI_fuel-qtr = Quarterly total heat input from oil (mmBtu).
M_qtr = Mass of oil consumed during the entire quarter,
determined as the product of the volume of oil under paragraph
(c)(3)(ii)(B) of this section and the specific gravity under paragraph
(c)(3)(ii)(D) of this section (lb)
GCV_max = Gross calorific value of oil, as determined under
paragraph (c)(3)(ii)(C) of this section (Btu/lb)
10\6\ = Conversion of Btu to mmBtu.

[GRAPHIC] [TIFF OMITTED] TR27OC98.002

Eq LM-3 (for natural gas)

Where:

HI_fuel-qtr = Quarterly heat input from natural gas (mmBtu).
Q_g = Value of natural gas combusted during the quarter, as
determined under paragraph (c)(3)(ii)(B) of this section standard cubic
feet (scf).
GCV_g = Gross calorific value of the natural gas combusted
during the quarter, as determined under paragraph (c)(3)(ii)(C) of this
section (Btu/scf)
10\6\ = Conversion of Btu to mmBtu.

(F) The quarterly heat input (mmBtu) for all fuels for the quarter,
HI_qtr-total,shall be the sum of the
HI_fuel-qtrvalues determined using Equations LM-2 and LM-3.

[[Page 57504]]
[GRAPHIC] [TIFF OMITTED] TR27OC98.003

(Eq. LM-4)

(G) The year-to-date cumulative heat input (mmBtu) for all fuels
shall be the sum of all quarterly total heat input
(HI_qtr-total) values for all calendar quarters in the year
to date.
(H) For each low mass emission unit, each low mass emission unit of
an identical group of units, or each low mass emission unit in a group
of units sharing a common fuel supply, the owner or operator shall
determine the quarterly unit output in megawatts or pounds of steam.
The quarterly unit output shall be the sum of the hourly unit output
values recorded under paragraph (c)(2) of this section and shall be
determined using Equations LM-5 or LM-6.

[GRAPHIC] [TIFF OMITTED] TR27OC98.004

Eq LM-5 (for MW output)

[GRAPHIC] [TIFF OMITTED] TR27OC98.005

Eq LM-6 (for steam output)

Where:

MW_qtr = the power produced during all hours of operation
during the quarter by the unit (MW)
ST_fuel-qtr = the total quarterly steam output produced
during all hours of operation during the quarter by the unit (klb)
MW = the power produced during each hour in which the unit operated
during the quarter (MW).
ST = the steam output produced during each hour in which the unit
operated during the quarter (klb)

(I) For a low mass emission unit that is not included in a group of
low mass emission units sharing a common fuel supply, apportion the
total heat input for the quarter, HI_qtr-totalto each hour
of unit operation using either Equation LM-7 or LM-8:

[GRAPHIC] [TIFF OMITTED] TR27OC98.006

(Eq LM-7 for MW output)

[GRAPHIC] [TIFF OMITTED] TR27OC98.007

(Eq LM-8 for steam output)

Where:

HI_hr = hourly heat input to the unit (mmBtu)
MW_hr = hourly output from the unit (MW)
ST_hr = hourly steam output from the unit (klb)

(J) For each low mass emission unit that is included in a group of
units sharing a common fuel supply, apportion the total heat input for
the quarter, HI_qtr-total to each hour of operation using
either Equation LM-7a or LM-8a:

[GRAPHIC] [TIFF OMITTED] TR27OC98.008

(Eq LM-7a for MW output)

[GRAPHIC] [TIFF OMITTED] TR27OC98.009

(Eq LM-8a for steam output)

Where:
HI_hr = hourly heat input to the individual unit (mmBtu)
MW_hr = hourly output from the individual unit (MW)
ST_hr = hourly steam output from the individual unit (klb)
[GRAPHIC] [TIFF OMITTED] TR27OC98.010

(4) Calculation of SO₂, NO_X and
CO₂ mass emissions. The owner or operator shall, for the
purpose of demonstrating that a low mass emission unit meets the
requirements of this section, calculate SO₂, NO_X
and CO₂ mass emissions in accordance with the following.
(i) SO₂ mass emissions. (A) The hourly SO₂
mass emissions (lbs) for a low mass emission unit shall be determined
using Equation LM-9 and the appropriate fuel-based SO₂
emission factor from Table 1 of this section for the fuels combusted in
that hour. If more than one fuel is combusted in the hour, use the
highest emission factor for all of the fuels combusted in the hour. If
records are missing as to which fuel was combusted in the hour, use the
highest emission factor for all of the fuels capable of being combusted
in the unit.

W_SO2=EF_SO2 x HI_hr (Eq. LM-9)

where:

W_SO2=Hourly SO₂ mass emissions (lbs).
EF_SO2=SO₂ emission factor from Table 1 of this
section (lb/mmBtu).
HI_hr=Either the maximum rated hourly heat input under
paragraph (c)(3)(i)(A) of this section or the hourly heat input under
paragraph (c)(3)(ii) of this section (mmBtu).

(B) The quarterly SO₂ mass emissions (tons) for the low
mass emission unit shall be the sum of all the hourly SO₂
mass emissions in the quarter, as determined under paragraph
(c)(4)(i)(A) of this section, divided by 2000 lb/ton.
(C) The year-to-date cumulative SO₂ mass emissions
(tons) for the low mass emission unit shall be the sum of the quarterly
SO₂ mass emissions, as determined under paragraph
(c)(4)(i)(B) of this section, for all of the calendar quarters in the
year to date.
(ii) NO_X mass emissions. (A) The hourly NO_X
mass emissions for the low mass emission unit (lbs) shall be determined
using Equation LM-10. If more than one fuel is combusted in the hour,
use the highest emission rate for all of the fuels combusted in the
hour. If records are missing as to which fuel was combusted in the
hour, use the highest emission factor for all of the fuels capable of
being combusted in the unit. For low mass emission units with
NO_X emission controls of any kind and for which a fuel-and-
unit-specific NO_X emission rate is determined under
paragraph (c)(1)(iv) of this section, for any hour in which the
parameters under paragraph (c)(1)(iv)(A) of this section do not show
that the NO_X emission controls are operating properly, use
the NO_X emission rate from Table 2 of this section for the
fuel combusted during the hour with the highest NO_X emission rate.

W_NOx=EF_{NOx x}HI_hr (Eq. LM-10)

Where:

WNO_X=Hourly NO_X mass emissions (lbs).
EFNO_X=Either the NO_X emission factor from Table
1b of paragraph (c)(1)(ii) of this section of this section or the fuel-
and-unit-specific NO_X emission rate determined under
paragraph (c)(1)(iv) of this section (lb/mmBtu).
HI_hr=Either the maximum rated hourly heat input from
paragraph (c)(3)(i)(A) of this section or the hourly heat input as
determined under paragraph(c)(3)(ii) of this section (mmBtu).

(B) The quarterly NO_X mass emissions (tons) for the low
mass emission unit shall be the sum of all of the hourly NO_X
mass emissions in the quarter, as determined under paragraph
(c)(4)(ii)(A) of this section, divided by 2000 lb/ton.
(C) The year-to-date cumulative NO_X mass emissions
(tons) for the low mass emission unit shall be the sum of the

[[Continued on page 57505]]

Notices For
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994

[[pp. 57455-57504]] Finding of Significant Contribution and Rulemaking for Certain

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