[Federal Register Volume 60, Number 71 (Thursday, April 13, 1995)]
[Rules and Regulations]
[Pages 18751-18777]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-8742]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 76
[AD-FRL-5186-5]
RIN 2060-AD45
Acid Rain Program: Nitrogen Oxides Emission Reduction Program
AGENCY: Environmental Protection Agency (EPA).
ACTION: Direct final rule; response to court remand.
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SUMMARY: The EPA is today issuing this final rule in response to a
remand by a U.S. Court of Appeals. The rule reinstates emission
limitations for nitrogen oxides (NOX) from coal-fired utility
units under section 407 of the Clean Air Act (``the Act''). The
emission limitations for NOX, along with emission limitations for
sulfur dioxide from utility plants, will reduce acidic deposition and
its serious adverse effects on natural resources, ecosystems,
materials, visibility, and public health.
On March 22, 1994, EPA promulgated a rule establishing NOX
emission limitations. The rule established emission limits generally
achievable using ``low NOX burner technology'' and established a
procedure for obtaining an alternative emission limitation (AEL) if a
unit could not achieve the prescribed limit using such technology. On
November 29, 1994, the U.S. Court of Appeals for the District of
Columbia Circuit ruled that the definition of ``low NOX burner
technology'' in the March 22, 1994 rule exceeded EPA's statutory
authority. The Court vacated the rule and remanded it to the Agency for
further proceedings. On March 28, 1995, EPA and environmental and
utility-industry parties signed an agreement addressing the March 22,
1994 regulations, including issues raised by the Court's remand.
Based on the Court's decision and a review of the record, the
Agency is now revising the March 22, 1994 regulations. The low-
NOX-burner-technology definition is revised to comply with the
Court's decision. Other provisions concerning the compliance date for
Phase I NOX emission limitations, AELs, and plans for averaging
NOX emissions of two or more units are also revised. In general,
the revisions reduce compliance requirements, extend the compliance
date, and increase compliance flexibility. The rule revisions are
issued as a direct final rule because they are consistent with the
Court's decision and no adverse comment is expected. The revisions are
also consistent with the March 28, 1995 agreement.
[[Page 18752]]
EFFECTIVE DATE: This direct final rule will be effective on May 23,
1995 unless significant, adverse comments are received by May 15, 1995.
If significant, adverse comments are timely received on any portion of
the direct final rule, that portion of the direct final rule will be
withdrawn through a notice in the Federal Register.
The incorporation by reference of certain publications listed in
the rule is approved by the Director of the Federal Register as of May
23, 1995.
ADDRESSES: Docket No. A-92-15, containing information considered during
development of the promulgated standards and requirements, is available
for public inspection and copying between 8:30 a.m. and 3:30 p.m.,
Monday through Friday, at EPA's Air Docket Section (6102), Waterside
Mall, Room M1500, 1st Floor, 401 M Street, SW., Washington, DC 20460. A
reasonable fee may be charged for copying. Additional data and
information pertaining to the rule may be found in Docket No. A-90-39.
FOR FURTHER INFORMATION CONTACT: Peter Tsirigotis, Acid Rain Division
(6204J), U.S. Environmental Protection Agency, 401 M Street SW.,
Washington, DC 20460 (for technical matters) at (202) 233-9620; or
Dwight C. Alpern (same address) (for legal matters) at (202) 233-9151.
SUPPLEMENTARY INFORMATION: The information in this preamble is
organized as follows:
I. Background
A. Purpose of the Acid Rain NOX Program
B. Statutory Framework
C. EPA's Rulemaking
II. The Court's Decision
III. EPA's Response to the Court's Decision
A. Changes to the March 22, 1994 Rule
1. Definitions
2. Date for Compliance with NOX Emission Limitations
3. Alternative Emission Limitations
4. NOX Averaging Plans
5. Phase I NOX Compliance Extensions
6. Miscellaneous
B. Reissuance of the Emission Limits
C. Permit Status
IV. Administrative Requirements
A. Executive Order 12866
B. Unfunded Mandates Act
C. Paperwork Reduction Act
D. Regulatory Flexibility Act
E. Miscellaneous
I. Background
A. Purpose of the Acid Rain NOX Program
The purpose of the Acid Rain NOX emission reduction program is
to reduce the adverse effects of acidic deposition on natural
resources, ecosystems, visibility, materials, and public health by
substantially reducing annual emissions of NOX from coal-fired
electric utilities. 42 U.S.C. 7651(a)(1). NOX, along with sulfur
dioxide, is a principal precursor of acidic deposition.
Although sulfate deposition is considered to be the major
contributor to long-term aquatic acidification, nitric acidic
deposition plays a dominant role in the ``acid pulses'' associated with
the fish kills observed during the springtime meltdown of the snowpack
in sensitive watersheds. Furthermore, the atmospheric deposition of
NOX is a substantial source of nutrients that damage estuaries,
such as the Chesapeake Bay, by causing algae blooms and anoxic
conditions. Nitrogen dioxide and particulate nitrate also contribute to
pollutant haze. Moreover, acidic deposition and ozone (formed by the
photochemical reaction of NOX and volatile organic compounds)
contribute to the premature weathering and corrosion of building
materials such as architectural paints and stones.
Electric utilities are a major contributor to NOX emissions
nationwide; in 1980, they accounted for 30 percent of total NOX
emissions and, by 1990, their contribution rose to 38 percent of total
NOX emissions. Approximately 80 percent of electric utility
NOX emissions come from coal-fired plants of the type addressed by
section 407 of the Act.
B. Statutory Framework
Section 407(b)(1) of the Act requires the Administrator to
establish NOX emission limitations for two types of coal-fired
utility boilers (``Group 1'' boilers): (1) Tangentially fired boilers;
and (2) dry bottom wall-fired boilers other than units applying cell
burner technology (``wall-fired boilers''). The Act specifies the
maximum emission limits (often referred to as ``presumptive'' emission
limits or limits) for these Group 1 boilers: 0.45 lb/mmBtu for
tangentially fired boilers; and 0.50 lb/mmBtu for wall-fired boilers.
If the Administrator finds that the presumptive limits cannot be
achieved using ``low NOX burner technology,'' the Administrator
may set less stringent limitations. 42 U.S.C. 7651f(b)(1). A Phase I
coal-fired utility unit with a Group 1 boiler must comply with the
promulgated annual NOX emission limitation on the later of January
1, 1995 or the date the unit is required to meet SO2 emission
reduction requirements under section 404(d) of the Act (id.).
Section 407(d) provides a mechanism by which a utility unit may
receive an AEL less stringent than the applicable limitation
established under section 407(b)(1) for Group 1 boilers. In order to
receive an AEL, the owner or operator of the unit must demonstrate that
it cannot meet the applicable limitation using properly installed ``low
NOX burner technology'' designed to meet the limitation. 42 U.S.C.
7651f(d). If the owner or operator makes the necessary showings, then
an AEL will be established that does not require ``any additional
control technology beyond low NOX burners.'' 42 U.S.C. 7651f(d).
Section 407(d) also provides that EPA may grant the owner or
operator of a Phase I coal-fired utility unit subject to section
407(b)(1) a 15-month extension from the January 1, 1995 compliance
deadline. Such an extension may be granted if the technology necessary
to meet the promulgated NOX emission limitation is not in adequate
supply to enable its installation and operation at the unit, consistent
with system reliability, by January 1, 1995. Section 407(d) specifies
the process the Administrator must use in authorizing the Phase I
extension.
A more detailed discussion of the statutory framework is set forth
at 59 FR 13538-13539 (March 22, 1994).
C. EPA's Rulemaking
As discussed above, the term ``low NOX burner technology''
plays an important role in section 407 of the Act. There has been
substantial controversy as to whether Congress intended ``low NOX
burner technology'' to be equivalent to ``low NOX burners'' and
whether ``low NOX burner technology'' includes all forms of
combustion air staging or only staging at the burner. On November 25,
1992, EPA published a proposed rule establishing NOX emission
limitations for coal-fired utility units under section 407(b)(1) of the
Act and other requirements and procedures for all coal-fired units
subject to Phase I and Phase II of the Acid Rain Program (57 FR 55632-
55683). In recognition of the controversy surrounding the definition of
low NOX burner technology, the proposed rule contained two
regulatory options and an alternative approach for defining that term.
Option 1 defined low NOX burner technology as low NOX burners
incorporating overfire air for wall-fired boilers and as low NOX
burners incorporating separated overfire air (e.g., LNCFS 2 and LNCFS
3) for tangentially fired boilers (57 FR 55642). Option 2 defined low
NOX burner technology as low NOX burners incorporating
separated overfire air for tangentially fired boilers, but excluded
overfire air from the definition for wall-fired boilers (id.). In
addition to the two options set forth, EPA solicited comment on a third
[[Page 18753]]
approach. This approach was endorsed by the Utility Air Regulatory
Group (UARG) (a group made up of utilities that subsequently challenged
the March 22, 1994 final rule) and the U.S. Department of Energy (DOE).
Under the third approach, low NOX burner technology was defined as
excluding both overfire air for wall-fired boilers and separated
overfire air for tangentially fired boilers (57 FR 55644-55645).
On March 22, 1994, EPA published the final NOX rule (59 FR
13538-13580). In that rule, EPA adopted the Option 1 definition of low
NOX burner technology after considering the chemical process of
low NOX combustion, the history and application of low NOX
combustion technology, Congress' intent in section 407 of the Act, and
the actual application of NOX control technology.
II. The Court's Decision
Following issuance of the March 22, 1994 rule, numerous utilities
and the National Coal Association petitioned for judicial review of the
rule. The two main issues raised on appeal were: whether EPA's
definition of low NOX burner technology was lawful; and whether
EPA was obligated to extend the January 1, 1995 compliance date
prescribed in section 407 of the Act because EPA did not issue the
rules by the May 15, 1992 issuance date required by section 407.
On November 29, 1994, the U.S. Court of Appeals for the District of
Columbia Circuit issued a decision on the petitioners' first issue. The
Court held that ``[t]he statutory text, structure, and history of
section 407 * * * support the `unmistakable conclusion' that Congress
unambiguously intended the term `low NOX burner technology' to
encompass only low NOX burners, not overfire air'' (Alabama Power
Co. v. U.S. EPA, No. 94-1170 (D.C. Cir, 1994) slip op. at 12). The
Court explained that under the AEL provision, ``Congress did not intend
to require utilities to consider the `full range of low NOX
combustion technologies' because it expressly provided that utilities
not be required to install or use any equipment beyond low NOX
burners in their efforts to comply with NOX emission limits'' (id.
at 11). After concluding that EPA had exceeded its statutory authority,
the Court vacated the March 22, 1994 rule and determined that the
petitioners' second issue on the compliance deadline was moot.
III. EPA's Response to the Court's Decision
A. Changes to the March 22, 1994 Rule
1. Definitions
Low NOX burners and low NOX burner technology. Because
the Court determined that, in defining low NOX burner technology
in the March 22, 1994 rule, the Agency exceeded its authority under
section 407 of the Act, the revised rule changes the definition of the
terms, ``low NOX burners and low NOX burner technology,'' in
Sec. 76.2. The Court determined that low NOX burner technology
encompasses ``only low NOX burners'' (Alabama Power, slip op. at
12). The Agency is removing from the March 22, 1994 definition the
language that is inconsistent with the Court's determination. In
particular, the revised rule eliminates the language stating that low
NOX burner technology includes ``any combination of coal and air
nozzles ports * * * not restricted to location within the boiler,
including * * * NOX ports, overfire air ports, or staged
combustion ports'' (59 FR 13565). Other related language (e.g., ``at
points downstream of the initial flame'' (id.)) in the March 22, 1994
definition is also removed.
The removed language is replaced by new language explaining that
the new definition includes the staging of combustion air using air
nozzles or registers located inside any boiler waterwall1 hole
that includes a burner. Additional new language explains that the
definition excludes the staging of combustion air using air nozzles or
ports located outside any boiler waterwall hole that includes a burner.
The new language implements, for both wall- and tangentially-fired
boilers, the Court's holding that low NOX burner technology
includes only low NOX burners.
\1\Waterwalls are panels of water tubes running along the length
of a boiler. These tubes carry water or steam. Water in these tubes
is converted into steam through the heat transfer between combustion
gas and this water.
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For wall-fired boilers, two types of NOX combustion controls
have been used: (1) Advanced burner retrofits for reducing NOX
formation (``burner retrofits'');2 and (2) combustion air staging
(i.e., ``overfire air'' for wall-fired boilers) (57 FR 55640). Burner
retrofits must be custom-designed for each boiler and the ease of
retrofitting varies from boiler to boiler:
\2\Typical designs of burner retrofits include upgraded air
registers that allow for better control of combustion air and a
redesigned burner tip. Burner retrofits achieve controlled fuel and
air mixing in the flame. This arrangement results in rapid
devolatilization and combustion of nitrogen-containing volatile
matter under conditions of limited availability of oxygen, with the
result that the formation of fuel NOX is suppressed. The
arrangement also results in combustion of air and coal char with a
cooler flame than the flame of conventional burners, which
suppresses thermal NOX formation (59 FR 13541).
In some cases (of burner retrofits), burner openings must be
enlarged via remolding the refractory material at the burner exit or
by enlarging the hole (not cutting holes in the boiler tubes). If
enlargement of the hole requires that tubes be cut and bent slightly
to accommodate the burner, however, this procedure does not affect
the boiler water circulation since the tubes have been previously
bent. The circulation design takes bends into account during initial
boiler design. By contrast, cutting holes as required for the
addition of (overfire air) affects the boiler circulation. (Docket
Item VIII-A-2, Reply Brief of Petitioners, August 29, 1994, Exhibit
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1.)
Unlike burner retrofits, overfire air for wall-fired boilers
involves diverting some combustion air from waterwall openings that
include a burner and injecting the air above the top burner level. This
generally requires the cutting of entirely new holes in the waterwall
above the highest burners (id.; 57 FR 55640).
The new low-NOX-burner-technology definition, as applied to
wall-fired boilers, encompasses all burner retrofits that are
essentially within an existing waterwall hole. Such retrofits may
involve minor modifications (e.g., of pressure parts or refractory
material) to the existing waterwall hole as necessary to accommodate
the retrofit essentially within the hole. The new definition excludes
all overfire air as applied to wall-fired boilers. This definition
meets the Court's requirement that only burners be considered; nothing
in the Court's decision excludes retrofit burners requiring minor
waterwall modifications. See, e.g., slip op. at 5 footnote 3
(discussing low NOX burners).
For tangentially fired boilers, all commercially available systems
for reducing NOX formation involve a staged combination of coal
and air (57 FR 55641). Three types of control systems for tangentially
fired boilers were discussed in detail in the preamble to proposed part
76: (1) The replacement of the original coal and air nozzle array in
each corner of the boiler with a new low NOX configuration of coal
and air nozzles and the installation of air nozzles at the upper end of
each waterwall hole that contains the new coal and air nozzle array
(``LNCFS 1'');3
[[Page 18754]]
(2) the installation of air nozzles in a new air nozzle assembly above
the waterwall hole that contains the original coal and air nozzle array
in each corner (``LNCFS 2''); and (3) the replacement of the original
coal and air nozzle array with a new low NOX configuration in each
corner and the installation of both air nozzles at the upper end of
each waterwall hole containing the new array and a new air nozzle
assembly above each waterwall hole (``LNCFS 3'') (id.).
\3\Several other low NOX burner designs also use combustion
air staging in the waterwall hole where the coal and air nozzle
array is located. Some of these are : Foster Wheeler's T-fired/Split
Flame (TF/SF) burner; and International Combustion Ltd.'s FAN burner
(Docket Item IV-D-111, Comments of the Utility Air Regulatory Group
on EPA's Proposed Rules on Nitrogen Oxides Reduction Program,
February 8, 1993, at 28, 30 and 115). Both of these designs
incorporate air nozzles at the upper end of the waterwall hole that
contains the new coal and air nozzle array in each corner of the
boiler. Neither, however, incorporates any staging that utilizes
injection of air through separate holes (e.g., separated overfire
air ports) in the waterwall and that therefore is external to the
waterwall hole containing the burner (id. at 27).
As is the case with wall-fired retrofit burners, LNCFS 1 is custom-
designed for each boiler and may require modifications to the existing
waterwall hole (59 FR 13546-13547). Retrofit burners and LNCFS 1
respectively involve the injection of air through registers or nozzles
located in a waterwall hole that includes the burner: In the case of
wall-fired boilers, the air registers are in the burner retrofit itself
while in the case of tangentially fired boilers, the air nozzles are in
the hole with the coal and air nozzle array.
In contrast with LNCFS 1, LNCFS 2 and LNCFS 3 involve injecting
combustion air above the coal and air nozzle array in each corner
through a new air nozzle assembly requiring an entirely new waterwall
hole above the array (57 FR 55641). The new low-NOX-burner-
technology definition, as applied to tangentially fired boilers,
includes the applications of LNCFS 1 (and other low NOX burner
designs)4 that are essentially within the existing waterwall hole.
The included applications may involve minor modifications (e.g., of
pressure parts or refractory material) to the existing waterwall hole
as necessary to accommodate the NOX emission controls essentially
within the existing hole. The new definition excludes all applications
of separated overfire air, e.g., LNCFS 2 and LNCFS 3. This is
consistent with the Court's holding in that, as discussed above, LNCFS
1 for tangentially fired boilers is analogous to retrofit burners for
wall-fired boilers and thus falls within the Court's prescription that
``low NOX burner technology'' be limited to low NOX burners
only.
\4\See footnote 3 above.
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The Agency notes that its new definition is in essence the same as
the definition set forth in the preamble of the November 25, 1992
proposed rule as an alternative to Options 1 and 2 (57 FR 55644-55645).
The alternative approach, like the new definition adopted today,
excluded overfire air for wall-fired boilers and excluded LNCFS 2 and
LNCFS 3 for tangentially fired boilers. The utilities described the
alternative approach as involving ``the direct replacement of the
original equipment manufacturer's coal burners (with low NOX
burners) without major new waterwall penetrations or parts'' (Docket
Item IV-D-111 at 74). The utilities also noted that their definition
under the alternative approach--like the definition in the revised
rule--includes ``burners[-]only technologies that have recently begun
to be offered commercially'' for tangentially fired boilers, i.e., the
low NOX burner designs described in footnote 3 above (id. at 73).
In comments on the November 25, 1992 proposal, the utilities and DOE
supported the alternative approach as being consistent with section 407
of the Act (Docket Items IV-D-2 at 1-2 and IV-D-111 at 73-84).
Other defined terms. In light of the new low-NOX-burner-
technology definition adopted today, two other definitions in Sec. 76.2
of the March 22, 1994 rule are now superfluous and are eliminated in
the revised rule.5 In particular, the new low-NOX-burner-
technology definition itself describes what forms of air staging are
included or not included in the definition, and, as discussed below,
references in other sections of part 76 to ``combustion air staging''
have been removed. Consequently, there is no need for the definition of
``combustion air staging''. See 59 FR 13564. Further, the definition of
``low NOX coal and air nozzles'' is unnecessary because that term
is no longer used in part 76. See 59 FR 13565.
\5\As discussed below, the definition of ``alternative
technology'' is also revised.
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2. Date for Compliance with NOX Emission Limitations
The revised rule changes the date in Sec. 76.5(a) on which a Phase
I unit with a Group 1 boiler begins to be subject to the NOX
emission limitations. Under the March 22, 1994 rule, such a Phase I
unit must begin compliance with NOX emission limitations on the
later of January 1, 1995 or the date the unit becomes subject to
SO2 emission reduction requirements under section 404(d) of the
Act. Under the revised rule, the January 1, 1995 date is changed to
January 1, 1996. Analogous changes in the compliance date are made in
Secs. 76.1(d) and 76.5(d).6
\6\The language in Sec. 76.5(d) is also revised to make it
consistent with Sec. 76.5(a) and clarify that a unit under
Sec. 76.5(d) may seek to use a compliance option in Secs. 76.10,
76.11, or 76.12.
The change in the compliance date is necessary because of the delay
in the repromulgation of the NOX emission limitations. The Court
vacated the March 22, 1994 rule on November 29, 1994, only 32 days
prior to the compliance deadline. The Court added that the reissued
NOX emission limitations ``will undoubtedly take effect after the
statutory deadline [for compliance] of January 1, 1995.'' Alabama
Power, slip op. at 13. Moreover, the Court noted ``the agency's
representation at oral argument that it would be inclined to exercise
its enforcement discretion in favor of the utilities in order to
account for delay in the rulemaking process'' (id.).
As correctly predicted by the Court, today's revised rule
reinstating NOX emission limitations takes effect after January 1,
1995, despite the Agency's efforts to expedite the rulemaking process.
Maintaining the January 1, 1995 deadline for compliance with the
NOX emission limitations would mean that the limitations under the
revised rule would have to be applied prior to their effective date.
Not only would this approach raise questions of retroactivity, but
also the Agency is concerned about the lack of any lead time between
promulgation of NOX emission limitations and the beginning date
for compliance. Under these circumstances, the Agency must determine
what Congress would have intended had it addressed the problem of
issuance of the NOX emission limitations after January 1, 1995.
Section 407 required the Agency to issue final NOX regulations
within 18 months of enactment of title IV (i.e., by May 15, 1992) and
required compliance with such regulations to begin on January 1, 1995.
Although these are independent requirements and, the Agency maintains,
no specific lead time between rule promulgation and compliance was
mandated, it is reasonable to conclude that Congress intended that
there be some lead time. Retaining a January 1, 1995 compliance
deadline would result in no lead time at all.
Further, the Agency recognizes that the promulgation of the March
22, 1994 low-NOX-burner-technology definition and the Court's
decision vacating the March 22, 1994 rule may have
[[Page 18755]]
engendered some uncertainty and confusion on the part of utilities
concerning their regulatory obligations. This further supports a change
in the January 1, 1995 compliance deadline. However, the Agency notes
that Phase I units generally proceeded in good faith to take the
necessary steps to comply with the March 22, 1994 rule. These steps
included obtaining a permit to operate and, where necessary, installing
NOX control equipment, including low NOX burners. Of the 175
Phase I units with Group 1 boilers on Table A of section 404, all
submitted NOX compliance plans by May 6, 1994 and only 31
requested a compliance date extension.7 Since complying with the
revised rule will, in general, require the same or less effort than the
industry has already undertaken, the extension until January 1, 1996 is
judged to be reasonable and appropriate.
\7\Twenty-five units applied for a 2-year Phase I extension for
SO2 under Sec. 72.42 (which automatically granted them a 2-year
NOX extension), and 6 units applied for a 15 month Phase I
NOX compliance extension under Sec. 76.12.
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The establishment of January 1, 1996 as the compliance deadline
also reflects the fact that title IV of the Act created an annual
program with regard to both SO2 and NOX emissions reductions.
Units must comply with SO2 emission limitations by emitting no
more SO2 in a year than is authorized by the number of allowances
``held for that unit for that year.'' 42 U.S.C. 7651b(g). Similarly,
emission limitations for NOX are annual: The generic limits
established under section 407(b) are ``annual allowable emission
limitations''; AELs under section 407(d) are emission rates that can be
met ``on an annual basis''; and emissions averaging plans under section
407(e) limit NOX emissions using both ``alternative
contemporaneous annual emission limitations'' and a ``Btu-weighted
average annual emission rate.'' Adopting January 1, 1996 as the
compliance deadline preserves the annual nature of the Acid Rain
Program.
The revised rule also changes language in the March 22, 1994 rule
concerning the date for compliance with any revised emission
limitations for Group 1 boilers that may be adopted under section
407(b)(2) of the Act. The March 22, 1994 rule states that Group 1,
Phase II units must comply with any revised Group 1 emission
limitations starting on January 1, 2000. Because EPA has not determined
whether to revise the Group 1 emission limitations under section
407(b)(2), it is unnecessary to state, in the rule at this time, the
compliance date for such revised limitations. If and when the
limitations are revised, the rule will be amended to add both the
limitations and the compliance date. Sections 76.5(g) and
76.10(f)(1)(iii) are revised to remove that compliance date.
3. Alternative Emission Limitations
In order to ensure that Sec. 76.10 is consistent with the new
definition of the term ``low NOX burner technology,'' all phrases
in the section that elaborated on that term are eliminated. In
particular, in Secs. 76.10(a)(1) and (2) of the March 22, 1994 rule,
the term ``low NOX burner technology'' is followed by phrases such
as: ``including separated overfire air''; ``incorporating both close-
coupled and separated overfire air''; or ``incorporating combustion air
staging above the top burner level'' (59 FR 13567-13568). The revised
rule excludes all of these phrases and is reworded as necessary to
reflect their removal. As a result of these changes, units with Group 1
boilers may apply for AELs if they are unable to meet applicable
emission limitations using low NOX burner technology under the new
definition in Sec. 72.2.8
\8\Since low NOX burner technology does not include air
nozzles or ports located outside of a waterwall hole that includes a
burner, provisions in Sec. 76.10 concerning the technical
feasibility of installing such air nozzles or ports are irrelevant.
Consequently, the March 22, 1994 provisions in Secs. 76.10(a)(3) and
(d)(4) are entirely eliminated. See 59 FR 13568-13569. The revised
rule also reflects the removal of any reference to these eliminated
provisions and the renumbering that results from their elimination.
See 59 FR 13568-69 and 13574. In addition, the requirement in
Sec. 76.10(g)(1)(ii)(C) that the designated representative revise
the AEL demonstration period plan is changed to apply only when the
owner or operator identifies operating modifications (whether for
the boiler or the NOX emission control system) that improve
NOX reductions. Consistent with Sec. 76.10(a)(2)(iii)(B), this
does not require revision of the plan to include operating
modifications that would prevent the boiler or NOX control
system from being operated in accordance with the bid and design
specifications on which the design of the NOX control system is
based. Plan revision is no longer required for all possible
equipment modifications or upgrades since they could be outside the
new low-NOX-burner technology definition. See 59 FR 13570-
13571.
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The revised rule also adds that units with tangentially fired
boilers may seek AELs where they cannot meet the applicable emission
limitations using separated overfire air. In order to comply with the
March 22, 1994 low-NOX-burner-technology definition, which was
then in effect and included close-coupled and separated overfire air,
some units installed only separated overfire air. The record
information to date indicates that separated overfire air alone is at
least as effective in reducing NOX emissions as low NOX
burner technology as applied to tangentially fired boilers. See Docket
Item IV-A-10, Background Document for RIA of NOX Regulations,
appendix A at 21. The Agency therefore maintains that such units should
not be disqualified from seeking an AEL because of their efforts to
comply with the March 22, 1994 rule. Sections 76.10(a)(1) and (2)(i)(A)
are revised to allow such units to seek AELs.
For similar reasons, the definition of ``alternative technology''
set forth in Sec. 76.2 is revised. Under the revised rule,
``alternative technology'' is NOX emission control technology
other than low NOX burner technology but does not include overfire
air for wall-fired boilers and separated overfire air for tangentially
fired boilers. Under Secs. 76.10(a) and (e)(11), a unit using
alternative technology, in addition to or in lieu of low NOX
burner technology, to reduce NOX emissions must show an annual
average emissions reduction of greater than 65 percent in order to
qualify for an AEL. The revision of the alternative-technology
definition excludes units with tangentially fired boilers applying
separated overfire air from the 65-percent reduction requirement.9
This avoids putting at a disadvantage, for purposes of obtaining AELs,
units that may have installed separated overfire air because of the
March 22, 1994 low-NOX-burner-technology definition.
\9\In order to avoid repeating in other sections the NOX
control technology requirements set forth in Sec. 76.10(a)(2) for
qualifying for an AEL (e.g., that a Group 1 boiler install low
NOX burner technology, alternative technology, or, for a
tangentially fired boiler, separated overfire air), the references
in Secs. 76.10(d)(8) and (e)(2)-(4) and 76.15(c) to specific
technologies are replaced by a general reference to the ``installed
NOX emission control system'' or ``NOX emission control
system.'' Such a system must, of course, meet the requirements in
Sec. 76.10(a)(2). In addition, Sec. 76.10(e)(2) is also revised to
make it consistent with Sec. 76.10(d)(8).
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Moreover, certain dates in Sec. 76.10(c)(1), concerning the
submission of petitions for an AEL demonstration period, and in
Sec. 76.10(f)(1), concerning approved AEL demonstration periods, are
changed. See 59 FR 13568 and 13570. These revisions reflect the change
in the compliance deadline from January 1, 1995 to January 1, 1996.
Finally, certain provisions, concerning information included in
petitions for AEL demonstration periods and for final AELs, in
Secs. 76.14 and 76.15 of the March 22, 1994 rule refer to combustion
air or air flow through ``overfire air ports'' or ``combustion air
staging ports.'' Since low NOX burner technology now excludes air
nozzles or ports located outside a waterwall hole that includes a
burner, these references are no longer appropriate. The provisions have
been modified to apply
[[Page 18756]]
only to tangentially fired boilers (which may use close-coupled
overfire air) and to refer to the ``distribution of combustion air''
within the ``NOX emission control system.'' See 59 FR 13574
(Sec. 76.14(a)(2)(i)) and 13575 (Sec. 76.15(b)(3) and (d)(2)).10
\10\Sections 76.15(a), (b), and (d) are also revised to state,
consistent with Secs. 76.10(d)(13) and 76.14(a)(2)(v), that the
owner or operator ``may'' use for tests and procedures set forth in
Sec. 76.15. Further, the language in Sec. 76.15(b)(6) is clarified,
and Sec. 76.15(d)(3) is revised to refer more generally to
optimization of the combustion process and to cite burner balancing
as an example.
As a result of these changes, the revised rule complies with the
Court's decision. The rule provides that, in applying for an AEL, the
designated representative for an affected Group 1 unit must demonstrate
that the unit cannot meet the presumptive emission limit using properly
installed and operated low NOX burner technology as redefined (or
alternative technology or, for tangentially fired boilers, separated
overfire air) that is designed to meet the presumptive limit. The
designated representative is not required to attempt to meet the
presumptive limit using low NOX burners plus overfire air for
wall-fired boilers or separated overfire air for tangentially fired
boilers. Rather, in keeping with the Court's decision, the designated
representative may base the petition for an AEL on the use of only low
NOX burners. Nothing in the Court's decision mandates any further
changes in the AEL provisions.
4. NOX Averaging Plans
Section 76.11 is revised to change the provisions concerning
compliance on an individual basis and on a group basis with the
emission limitations in NOX averaging plans and to clarify
language in the formulas implementing the requirements of such plans.
Under Sec. 76.11(d) of the March 22, 1994 rule, units governed by a
NOX averaging plan must comply with both individual-unit limits
``and'', where applicable, a group emission requirement. 59 FR 13572
(Sec. 76.11(d)(1)(i)(B)). An averaging plan must state individual-unit
limits for all units in the plan, i.e., an alternative contemporaneous
annual emission limitation and, in most cases, an annual heat input
limit. The formula for setting the individual-unit limits is Equation 1
in Sec. 76.11(a)(6). Each unit's actual annual average emission rate
must not exceed that unit's alternative contemporaneous annual emission
limitation. Further, if the alternative contemporaneous annual emission
limitation is less stringent than the applicable emission limitation,
the unit's actual annual heat input must not exceed the unit's annual
heat input limit. If the alternative contemporaneous annual emission
limitation is more stringent, the unit's heat input must not be less
than the heat input limit.
The March 22, 1994 rule also provides that if one or more of the
units under the plan fail to meet the individual-unit limits, there
must be a showing that the entire group of units under the plan
complies with a group emission requirement. The group emission
requirement is met where the actual Btu-weighted annual average
emission rate for the units in the plan does not exceed the Btu-
weighted annual average emission rate for these units if they had
operated in compliance with the applicable emission limitation in
Secs. 76.5, 76.6, or 76.7. The formula for determining group compliance
is Equation 2 in Sec. 76.11(d)(1)(ii)(A).
Section 76.11(d)(2) of the March 22, 1994 rule addresses liability
where units under the NOX averaging plan fail to meet any of the
requirements of the plan, including the individual-unit limits and the
group emission requirement. Under Sec. 76.11(d)(2)(i), the owners and
operators of each unit under the plan are liable for any violations of
the plan (or of Sec. 76.11) by any unit under the plan. Such liability
expressly includes the excess emissions penalty under 40 CFR part 77
and section 411 of the Act and penalties under section 113 of the Act.
The only exception to the liability provision in Sec. 76.11(d)(2)(i) is
that if the group showing of compliance under Sec. 76.11(d)(1)(ii) is
made, then no unit under the plan is subject to the excess emissions
penalty. Regardless of whether the group showing of compliance (which
is for purposes of excess emissions) is made, the March 22, 1994 rule
does not exempt any unit under the plan from liability under section
113 for violation of the individual-unit limits.
In contrast with the March 22, 1994 rule, the revised rule provides
that if one or more units fail to meet the individual-unit limits but
there is a showing of group compliance for the year, then all units in
the plan will be deemed to be in compliance for the year with the
individual-unit limits. With regard to their NOX emissions for the
year, all units therefore will be in compliance with the averaging plan
and have no potential liability for violation of the plan or part 76.
Further, none of the units will have excess emissions for the year
under part 77.
The Agency has received public comment to the effect that this
revised approach, which was proposed in the original November 25, 1992
proposed NOX rule, is more consistent with the purposes of section
407 than the approach adopted in the March 22, 1994 rule. Neither
section 407(e) nor the legislative history specifically address this
matter. However, section 407(e) states that individual units'
alternative contemporaneous annual emission limitations must ``ensure
that the units' actual annual NOX emission rate'' averaged over
the units in question does not exceed the ``Btu-weighted annual average
emission rate for the same units'' if they had met the applicable
emission limitations under section 407(b). 15 U.S.C 7651f(e). That goal
is satisfied where units fail to meet the individual-unit limits in the
NOX averaging plan but can show group compliance with the plan.
Further, even though the March 22, 1994 rule relieves units in such
circumstances from liability for excess emissions, the units are still
potentially liable for civil penalties, which may be enforceable
through Agency action or citizen suits under sections 113 and 304 of
the Act. This potential liability is sufficiently significant that a
utility with a NOX averaging plan may, in effect, be forced to
comply unit-by-unit with the individual-unit limits even if the group
emission requirement could be met without meeting all the individual-
unit limits. The individual-unit limits can restrict the utility's
flexibility, for example, in dispatching the units in the plan. In
order to minimize the likelihood of violating individual-unit limits,
some designated representatives have submitted Phase I NOX
averaging plans that set alternative contemporaneous emission
limitations equal to the presumptive limits in Sec. 76.5 and that
specify no heat input limits. However, under such plans, the
individual-unit limits can still restrict the utility's flexibility to
choose which units in the plan will be retrofitted with NOX
emission control systems and what types of NOX emission control
systems will be used. The Agency is concerned that the net result of
such lack of flexibility is that designated representatives will be
encouraged to seek AELs for more units, rather than attempting to
average units with higher NOX emissions with units with lower
NOX emissions. Not only is the case-by-case process of setting
AELs administratively burdensome for utilities and the Agency, but also
the Agency is concerned that total NOX emissions are likely to be
higher the greater the number of units with AELs.
The Agency concludes that removing the requirement to meet
individual-unit limits when there is group compliance
[[Page 18757]]
under a NOX averaging plan is a reasonable interpretation of
section 407(e) and better implements that provision. Consequently,
Sec. 76.11(d)(1)(ii) is revised to state that when the units in a
NOX averaging plan show compliance with the group emission
requirement in Sec. 76.11(d)(1)(ii)(A) for a given year, the units will
be deemed to comply for that year with their individual emission
limitations and heat input limits. Since units meeting group compliance
are thereby in compliance with both the individual-unit and group
emission requirements of the plan, there is no need to state separately
that group compliance relieves the units of any penalties for excess
emissions. Section 76.11(d)(2)(ii) is therefore eliminated.11
\11\Consistent with these changes, Sec. 76.11(d)(1)(i)(B) is
revised to state that units must meet either the individual-unit
limits ``or'' the group emission requirement.
---------------------------------------------------------------------------
Sections 76.11(a) (6) and (7) and (d)(1)(ii) (A) and (B) are also
revised to clarify the formulas (Equations 1 and 2) that govern the
selection of individual-unit limits and the showing of group
compliance. The language in these sections explaining what ``applicable
emission limitation'' to use in Equations 1 and 2 is confusing. The
revised rule clarifies that the limitation to be used in Equations 1
and 2 is the applicable emission limitation for each respective unit in
Secs. 76.5, 76.6, or 76.7. Consistent with that approach, a unit with
an AEL must use the applicable emission limitation in Secs. 76.5, 76.6,
or 76.7 rather than the AEL. The only exception is that an early
election unit, which elects to meet NOX emission limitations in
Phase I but is allowed to participate in a NOX averaging plan only
in Phase II, must use the most stringent applicable limitation in
Secs. 76.5 or 76.7 (i.e., 0.45 lb/mmBtu or 0.50 lb/mmBtu depending on
whether the unit's boiler is wall-fired or tangentially fired) or, if
the limitation is revised and made more stringent for Phase II under
section 407(b)(2), the revised limitation applicable to the boiler
type.
In order to simplify the language in Secs. 76.11(a)(7) and
(d)(1)(ii)(B) in the March 22, 1994 rule, the references to Phase II
units are removed. To capture the concept in the March 22, 1994
provisions that Phase II units cannot participate in averaging plans
before January 1, 2000, Sec. 76.11(a)(1) is revised to state that a
unit in an averaging plan in Phase I must be a Phase I unit with a
Group 1 boiler.
EPA notes that it has received public comments concerning the use
of a single NOX averaging plan for units of two or more operating
companies (also referred to as utility systems) that are subsidiaries
of a single holding company. In such a case, the operating companies
would designate the same designated representative (probably someone at
the holding company level) for their units in order to meet the common
designated representative requirement for a NOX averaging plan.
Each operating company could still designate its own alternate
designated representative. Concern was raised that the designated
representative at the holding company level may not be readily
accessible and that operating companies may need the flexibility of
having two persons at the operating company level with authority to act
for the designated representative. The Agency is currently reviewing
this matter and, in light of the public comments, will propose, in a
future rulemaking, revisions to 40 CFR part 72 that would allow
designation of a second alternate designated representative for units
under certain limited circumstances. Such circumstances could be where:
The unit's utility system is a subsidiary of a holding company with two
or more utility-system subsidiaries in two or more states; and, in
order to use a NOX averaging plan involving units of two or more
such subsidiaries, all the utility-system subsidiaries of that holding
company have the same designated representative. EPA intends to
consider this revision, and other revisions to streamline part 72, in a
rulemaking to be completed in 1995.
5. Phase I NOX Compliance Extensions
Section 76.12 is revised in order to reflect the new low-NOX-
burner-technology definition. The March 22, 1994 rule provides for a
Phase I NOX compliance extension where a tangentially fired boiler
was designed and guaranteed, but failed, to meet the presumptive
emission limit and there is a contract to install close-coupled or
separated overfire air on or before January 1, 1996. The March 22, 1994
rule includes similar language, with regard to wall-fired boilers,
providing a Phase I NOX compliance extension where there is a
contract to install additional equipment, including overfire air. 59 FR
13572 (Sec. 76.12(a)(1) (ii) and (iii)). The direct final rule
eliminates these provisions and a related provision in
Sec. 76.12(b)(3). No extensions were requested under these provisions.
The March 22, 1994 rule also provides for a Phase I NOX
compliance extension for units where low NOX burner technology
designed to meet the presumptive emission limits is not in adequate
supply for installation and operation by January 1, 1995, consistent
with system reliability. Requests for the extensions were due by
October 1, 1994. These provisions are not changed in the revised rule.
Extension requests for 6 units under this provision were submitted, and
the requests either have already been granted or will be acted on
consistent with the revised rule after its effective date.
The Agency is aware that, in very limited circumstances, an
additional extension of the compliance date for Phase I NOX
emission limitations may be warranted. These circumstances are as
follows: A source has 3 or more units that have extensions under
section 404(d) until January 1, 1997 to comply with Phase I NOX
emission limits and, due to claimed operational problems associated
with the planned NOX emission control systems, one unit may need
an additional extension to redesign and install low NOX burner
technology. Because of its extension under section 404(d), the unit has
not yet installed the NOX control system that was designed to
comply with the low-NOX-burner technology definition in the March
22, 1994 rule. With the change adopted today in the definition, the
unit has flexibility to redesign the NOX control system to meet
the new definition and avoid the claimed operational problems. However,
unless an additional compliance extension is granted, there will be
insufficient time to install redesigned low NOX burner technology
without causing system reliability problems.
Because the need for an additional extension appears to result from
the change in the low-NOX-burner-technology definition, the Agency
maintains that an additional extension may be appropriate in these
limited circumstances. In order to provide the designated
representative of the unit an opportunity to demonstrate the need for
such extension, the revised rule (in Sec. 76.12(e)) requires the
submission of a petition for the extension within 15 days of the
publication of the revised rule and establishes procedures for acting
on the petition. The procedures and the provisions in the revised rule
concerning treatment of the unit upon approval of the petition are
essentially the same as the procedures and provisions applicable to
Phase I NOX compliance extensions. See 59 FR 13572-13573
(Sec. 76.12(c) and (d)).
6. Miscellaneous
The revised rule excludes Sec. 76.9(e) of the March 22, 1994 rule,
which provides that each ton of excess emissions of
[[Page 18758]]
NOX will be a separate violation. In response to the utilities'
challenge of Sec. 76.9(e), EPA moved before the Court for a voluntary
remand of the provision. The Court granted the motion and therefore EPA
is now deleting the provision.
The revised rule also changes provisions concerning the types of
units for which reports of cost data on low NOX burner technology
installations must be prepared and the date by which the reports must
be submitted under Sec. 76.14(c). Consistent with the new low-NOX-
burner-technology definition, the cost reports are not required for:
wall-fired boilers using only overfire air and not low NOX
burners; and tangentially fired boilers using only separated overfire
air and not low NOX burner technology. Because such boilers are
not using low NOX burner technology, cost data on their NOX
emissions controls are not relevant to setting of Group 2, Phase II
NOX emission limitations under section 407(b)(2) of the Act. An
analogous change is made in section 1 of appendix B to part 76.
Also excluded from cost reporting are units that begin installing a
new NOX emission control system after 120 days from publication of
the instant direct final rule in the Federal Register. In light of the
statutory requirement that Group 2, Phase II emission limitations be
established by January 1, 1997, the Agency maintains that cost
information on those units would be received too late to be useful in
the rulemaking on such emission limitations.
Finally, the date for submission of cost reports is revised in
Sec. 76.14(c)(3) to take account of the vacating of the March 22, 1994
rule by the Court. As in the March 22, 1994 rule, the cost reports must
be submitted within 120 days after completion of the low NOX
burner technology retrofit project. However, in order to provide time
for resumption and completion of cost data collection that may have
been stopped when the rule was vacated, the revised rule ensures that
all projects will have at least 40 days, from the publication of the
revised rule in the Federal Register, to submit the cost reports. Cost
reports on projects completed more than 80 days before publication of
the direct final rule must be submitted by the 40th day after such
publication.
B. Reissuance of the Emission Limits
Section 407(b)(1) requires the Administrator to adopt by regulation
the presumptive emission limits unless she finds that they cannot be
achieved using low NOX burner technology. In the March 22, 1994
rule, the Administrator found that the record evidence showed that the
presumptive limits were achievable using low NOX burners plus
overfire air for wall-fired boilers and separated overfire air for
tangentially fired boilers (59 FR 13546). In light of the revised low-
NOX-burner-technology definition, the Administrator has reviewed
the record concerning the performance of low NOX burners and
concludes that the presumptive limits are still achievable. The revised
rule therefore reissues the presumptive limits of 0.50 lb/mmBtu for
wall-fired boilers and 0.45 lb/mmBtu for tangentially fired boilers.
The record includes analyses conducted by DOE in which the
presumptive limits were examined in light of the low-NOX-burner-
technology definition supported by DOE, i.e., the third approach in the
November 25, 1992 proposal. The revised rule adopts in essence the same
definition as DOE supported. As discussed below, DOE concluded, and the
utilities agreed, that most units could achieve the presumptive limits
using low NOX burners without overfire air for wall-fired boilers
and without separated overfire air for tangentially fired boilers. See,
e.g., Docket Item IV-D-162, Fourth Supplementary Comments of UARG,
February 2, 1994 at 16-23.
After reviewing a number of sources of information on control
technology efficiency, DOE estimated control technology performance
based primarily on data from ongoing demonstration projects and other
recent installations of NOX control systems. The analysis of data
from wall-fired and tangentially fired boilers, fitted with low
NOX burner technology as defined by DOE, indicated that NOX
reductions of 45 to 50 percent would be achieved at wall-fired boilers
and of 35 to 37 percent would be achieved at tangentially fired boilers
(57 FR 55646-55647). DOE's NOX control technology performance
estimates were consistent with average NOX reductions projected by
the utilities. The utilities projected average NOX reductions of
47 percent with use of burner retrofits for wall-fired boilers and 35
to 37 percent with the use of LNCFS 1 for tangentially fired boilers
(Docket Item IV-D-111 at 59-61).12 Further, the utilities
supported DOE's performance estimates in their brief to the Court in
Alabama Power (Docket Item VIII-A-1, Brief of Petitioners, July 1,
1994, at 18-19).
\12\Since the completion of DOE's analysis, other types of low
NOX burner technology have been developed for tangentially
fired boilers. See footnote 3 above. Although EPA currently lacks
data on the long-term performance of these NOX controls, the
outlook for their performance is promising.
---------------------------------------------------------------------------
DOE's analysis also showed that, assuming 45 percent control
efficiency for wall-fired boilers and 35 percent for tangentially fired
boilers, less than 10 percent of the Group 1 units would fail to meet
the presumptive limits (57 FR 55648). Further, the utilities similarly
concluded that ``review of the uncontrolled emissions at wall-fired and
tangentially fired boilers, and of the capabilities of low NOX
burner technology, show that (the presumptive) limits are aggressive
but generally achievable by most Group 1 units with the use of (low
NOX burners) alone'' (Docket Item IV-D-111 at 138). The utilities
reiterated this conclusion before the Court in Alabama Power. The
utilities stated that ``all of the tangentially fired boiler groupings
analyzed by EPA's contractor would comply with the final presumptive
emission limitation using low NOX burners alone for tangentially
fired boilers (i.e., LNCFS 1), without the use of separated overfire
air'' (Docket Item VIII-A-1, Brief of Petitioners at 40).
In the March 22, 1994 preamble, EPA did not adopt DOE's analysis
and instead presented its own analysis of control technology
performance data available after promulgation of the November 25, 1992
proposal. The EPA found that the majority of wall-fired boilers would
be expected to achieve NOX reductions of 40 to 50 percent using
low NOX burners only and no overfire air (59 FR 13546). The EPA
also found that tangentially fired boilers using LNCFS 1 would achieve
reduction of 20 to 25 percent. While EPA's finding on wall-fired
boilers is consistent with DOE's finding, the two analyses differ
concerning tangentially fired boilers. However, upon reconsideration,
the Agency finds that the 20 to 25 percent estimate of reductions
achievable using LNCFS 1 erroneously excluded the reductions using a
form of LNCFS 1 referred to in the March 22, 1994 preamble as ``LNCFS
1+.'' 59 FR 13546-13547. Because ``LNCFS 1+'' (i.e., Lansing Smith Unit
2)13 employs the
[[Page 18759]]
same hardware (i.e., air nozzles in the hole with the burner) as LNCFS
1 applications, there is no basis of distinguishing ``LNCFS 1+''. The
differences between EPA's and DOE's data are eliminated by treating
``LNCFS 1+'' as included in LNCFS 1 and considering the performance
results of ``LNCFS 1+'' as included in results for LNCFS 1.
\13\DOE's analysis included Fiddler's Ferry Unit 1 as a unit
with LNCFS 1. Since installation of LNCFS 1 in that unit involved
major modifications of the existing waterwall holes (i.e., cutting
out a waterwall section having a height of 3 feet above each
existing waterwall hole and a width equal to the width of the hole),
the unit's NOX control system does not fall within the new low-
NOX-burner technology definition, which includes minor
modifications of the existing hole. See Docket Item II-E-11, Record
of Telephone Conversations, October 12, 1992. However, eliminating
the emission reduction results of that unit does not change the
conclusion that LNCFS 1 (e.g., at Lansing Smith Unit 2) can achieve
35 to 37 percent reductions.
Upon reconsideration, EPA concurs with the aforementioned DOE and
utilities' analyses. EPA, therefore, retains in the revised rule the
presumptive limits for Group 1 boilers.
C. Permit Status
Pursuant to the March 22, 1994 rule, the designated representatives
of Phase I units with wall-fired or tangentially-fired boilers
submitted NOX compliance plans. (See 59 FR 13567 (Sec. 76.9 (a)
through (c))). For units lacking Acid Rain permits, the NOX
compliance plans were submitted along with applications for such
permits. For units that already had Acid Rain permits covering SO2
emission limitations, the NOX compliance plans were submitted as
permit revisions. Most of the plans required NOX compliance
commencing on January 1, 1995. Twenty-five units had previously been
granted 2-year extensions for NOX compliance under Sec. 72.42, and
designated representatives for 6 more units requested 15-month
extensions under Sec. 76.12 of the March 22, 1994 rule.
The Agency followed the applicable permit issuance and revision
procedures under part 72 of the Acid Rain permits rule. These
procedures required notice of a proposed permit or proposed permit
revision and opportunity for public comment prior to issuance of a
final permit or final revised permit. Most of the submitted NOX
compliance plans were already approved and included in final permits or
final revised permits before the November 29, 1994 Alabama Power
decision vacating the March 22, 1994 rule. Because of the vacating of
the rule, the Agency has deferred action on those plans and extension
requests that were not yet approved when the Court issued its decision.
Under the March 22, 1994 rule, NOX compliance plans had to
identify which one of several possible compliance options was proposed
for each Phase I unit with a Group 1 boiler. Id. (Sec. 76.9(c)(4)). In
the NOX compliance plans already submitted to the Agency, units
sought to comply either with the presumptive limits or through NOX
emissions averaging plans. The units that requested NOX compliance
extensions sought to comply either with the presumptive limits or
through NOX emissions averaging plans after the extensions expire.
If, as anticipated, the revised rule becomes final and thereby
reinstates the NOX emission reduction program, the Agency sees no
need for utilities to resubmit and for EPA to reissue, through notice
and comment procedures, the NOX compliance plans that have already
been approved and issued in final form in permits or permit revisions.
The final permits and permit revisions set forth the applicable
NOX emission limitations and do not state any definition for low
NOX burner technology. The revised rule changes the low-NOX-
burner-technology definition but does not change the presumptive limits
or the formulas for setting individual-unit limits or showing group
compliance in averaging plans. The revised rule preserves without
change the provisions governing the Phase I extensions that were
requested and either were approved or that would have been approved
under the March 22, 1994 rule. The revised rule also does not change
the application requirements in Sec. 76.9 or the permit issuance or
permit revision procedures in parts 72 and 76 applicable to NOX
compliance plans.
The only changes that the revised rule makes in the submitted
NOX compliance plans are in the general compliance date and in the
effect of group compliance on individual-unit limits in NOX
averaging plans. The general deadline for compliance by a Group 1,
Phase I unit with NOX emission limitations is now the later of
January 1, 1996 (rather than 1995) or the date on which a unit is
subject to SO2 emission reduction requirements under section
404(d) of the Act. The revised rule also mandates, for all NOX
averaging plans, that where the units in an averaging plan show they
meet the group compliance requirement, the units are deemed to meet
their individual-unit limits. All NOX compliance plans must
conform to the revised rule.
As discussed above, the Agency has issued, elsewhere in this
Federal Register, a notice of proposal requesting comments on the
provisions of the revised rule. Any comments concerning the compliance
deadline and the group compliance provisions should be made in response
to that notice and would not be appropriate in the context of permit
issuance. All other aspects of the submitted NOX compliance plans
have already been subject to notice and comment and are unchanged by
the revised rule.
The Agency concludes that, once the revised rule becomes final as
anticipated, conforming changes in the compliance date and group
compliance provisions in otherwise unchanged NOX compliance plans
are properly considered administrative amendments under Sec. 72.83 of
the Acid Rain permits rule because there is no basis for requiring
notice and comment on the changes. All existing permits that include
NOX compliance plans will be amended under Sec. 72.83 to the
extent necessary to make them consistent with the new compliance date
and group compliance requirements. The administrative amendments will
reinstate the NOX compliance plans as amended and the approved
Phase I NOX compliance extensions under Secs. 72.42 and 76.12 that
are referenced in the plans.
With regard to NOX compliance plans in permits or permit
revisions issued in draft form for public comment but not yet issued in
final form, the Agency will complete the issuance procedure in
accordance with the revised rule once the rule becomes final. Since,
except for the compliance date and group compliance provisions, neither
the substance of such plans nor the issuance procedures were changed by
the revised rule, there is no need to reopen the public comment period
on the plans.
Any plans that have not yet been issued in draft form will also be
processed by the Agency in accordance with the revised rule and part
72. Similarly, any Phase I NOX compliance extensions requested
under Sec. 76.12 and not acted on before November 29, 1994 will be
acted on consistent with the revised rule. It should be noted that, if
significant, adverse comment is timely received on relevant portions of
the instant direct final rule, the NOX compliance plans could be
subject to further change depending on the outcome of the rulemaking
initiated by the notice of proposed rule issued elsewhere in this
Federal Register.
IV. Administrative Requirements
A. Executive Order 12866
Under Executive Order 12866 (58 FR 51735 (October 4, 1993)), the
Agency must determine whether the regulatory action is ``significant''
and therefore subject to Office of Management and Budget (OMB) review
and the requirements of the Executive Order. The Order defines
``significant regulatory action'' as one that is likely to result in a
rule that may:
(1) Have an annual effect on the economy of $100 million or more or
adversely affect in a material way the economy, a sector of the
economy, productivity, competition, jobs, the
[[Page 18760]]
environment, public health or safety, or State, local, or tribal
governments or communities;
(2) Create a serious inconsistency or otherwise interfere with an
action taken or planned by another agency;
(3) Materially alter the budgetary impact of entitlements, grants,
user fees, or loan programs or the rights and obligations of recipients
thereof; or
(4) Raise novel legal or policy issues arising out of legal
mandates, the President's priorities, or the principles set forth in
the Executive Order.
Pursuant to the terms of Executive Order 12866, it has been
determined that this rule is a ``significant regulatory action''
because it will have an annual effect on the economy of approximately
$276 million starting in 2000. As such, this action was submitted to
OMB for review. Any written comments from OMB to EPA and any written
EPA response to those comments are included in the docket. The docket
is available for public inspection at the EPA's Air Docket Section,
which is listed in the ADDRESSES section of this preamble.
EPA does not believe a revised Regulatory Impact Analysis (RIA) is
needed for the direct final rule, which, in large part, reinstates the
March 22, 1994 rule and which imposes no new costs beyond what costs
were estimated in the RIA to the March 22, 1994 rule. The EPA does not
anticipate major increases in prices, costs, or other significant
adverse effects on competition, investment, productivity, or innovation
or on the ability of U.S. enterprises to compete with foreign
enterprises in domestic or foreign markets due to the final rule.
In assessing the impacts of a regulation, it is important to
examine: (1) The costs to the regulated community, (2) the costs that
are passed on to customers of the regulated community, and (3) the
impact of these cost increases on the financial health and
competitiveness of both the regulated community and their customers.
The costs of this rule to electric utilities are generally very small
relative to their annual revenues. (However, the relative amount of the
costs will definitely vary in individual cases.) Moreover, EPA expects
that most or all utility expenses from meeting NOX requirements
will be passed along to ratepayers. When NOX requirements are
fully implemented in the year 2000, consumer electric utility rates are
expected to rise by 0.12 percent on average due to this rulemaking.
Consequently, the rule is not likely to have an impact on utility
profits or competitiveness.
B. Unfunded Mandates Act
Section 202 of the Unfunded Mandates Reform Act of 1995 (``Unfunded
Mandates Act'') (signed into law on March 22, 1995) requires that the
Agency prepare a budgetary impact statement before promulgating a rule
that includes a Federal mandate that may result in expenditure by
State, local, and tribal governments, in the aggregate, or by the
private sector, of $100 million or more in any one year. The budgetary
impact statement must include: (i) Identification of the Federal law
under which the rule is promulgated; (ii) a qualitative and
quantitative assessment of anticipated costs and benefits of the
Federal mandate and an analysis of the extent to which such costs to
State, local, and tribal governments may be paid with Federal financial
assistance; (iii) if feasible, estimates of the future compliance costs
and any disproportionate budgetary effects of the mandate; (iv) if
feasible, estimates of the effect on the national economy; and (v) a
description of the Agency's prior consultation with elected
representatives of State, local, and tribal governments and a summary
and evaluation of the comments and concerns presented. Section 203
provides that if any small governments may be significantly or uniquely
impacted by the rule, the Agency must establish a plan for obtaining
input from and informing, educating, and advising any such potentially
affected small governments.
Under section 205 of the Unfunded Mandates Act, the Agency must
identify and consider a reasonable number of regulatory alternatives
before promulating a rule for which a budgetary impact statement must
be prepared. The Agency must select from those alternatives the least
costly, most cost-effective, or least burdensome alternative, for
State, local, and tribal governments and the private sector, that
achieves the objectives of the rule, unless the Agency explains why
this alternative is not selected or unless the selection of this
alternative is inconsistent with law.
Because this direct final rule is estimated to result in the
expenditure by State, local, and tribal governments, in aggregate, or
the private sector of over $100 million per year starting in 2000, EPA
has prepared a supplement to the Regulatory Impact Statement in
compliance with the Unfunded Mandates Act. EPA summarizes that
supplement as follows.
The direct final rule is promulgated under section 407 of the Clean
Air Act. The rule is issued in response to a remand by the U.S. Court
of Appeals for the District of Columbia Circuit and, in large part,
reinstates the remanded March 22, 1994 rule. Thus, the analysis in the
RIA developed in preparation of the March 22, 1994 rule was
appropriately considered in response to the requirements of the
Unfunded Mandates Act.
Total expenditures resulting from the direct final rule are
estimated at: $69 million (of which less than $1 million is by State,
local, and tribal governments) per year in 1995-1999; and $276 million
(of which $21 million is by State, local, and tribal governments) per
year starting in 2000. There are no federal funds available to assist
State, local, and tribal governments in meeting these costs. There are
important benefits from NOX emission reductions because
atmospheric emissions of NOX have significant, adverse impacts on
human health and welfare and on the environment.
The rule does not have any disproportionate budgetary effects on
any particular region of the nation, any State, local, or tribal
government, or urban or rural or other type of community. On the
contrary, the rule will result in only a minimal increase in average
electricity rates. Moreover, the rule will not have a material effect
on the national economy.
Prior to issuing the March 22, 1994 rule, EPA provided numerous
opportunities, e.g., through the Acid Rain Advisory Committee
proceedings, the public comment period, and public hearings, for
consultation with interested parties, including State, local, and
tribal governments. In general, State and local environmental agencies
advocated that EPA adopt more stringent environmental controls while
municipally-owned utilities advocated less stringent controls and more
compliance flexibility. EPA evaluated the comments and concerns
expressed, and the direct final rule reflects, to the extent consistent
with section 407 of the Clean Air Act, those comments and concerns.
While small governments are not significantly or uniquely affected by
the rule, these procedures, as well as additional public conferences
and meetings, gave small governments an opportunity to give meaningful
and timely input and obtain information, education, and advice on
compliance.
The Agency considered several regulatory options in developing the
rule. The option selected in the direct final rule is the least costly
and least burdensome alternative currently available for achieving the
objectives of
[[Page 18761]]
section 407. The Agency rejected another alternative that was the most
cost-effective alternative because the U.S. Court of Appeals for the
D.C. Circuit held that the latter alternative was beyond the Agency's
statutory authority.
C. Paperwork Reduction Act
The OMB has approved the information collection requirements
contained in this rule under the provisions of the Paperwork Reduction
Act of 1980, 44 U.S.C. 3501, et seq., and has assigned OMB control
number 2060-0258.
Public reporting burden for this collection of information is
estimated at 27,510 hours for all respondents through May 15, 1995.
This estimate includes time for reviewing instructions, searching
existing data sources, gathering and maintaining the data needed, and
completing and reviewing the collection of information.
The Agency notes that this burden estimate was originally developed
based on the March 22, 1994 rule. Today's direct final rule includes
revisions to cost reporting requirements in the March 22, 1994 rule
that result in a small reduction in overall burden. In order to account
for this small reduction, the Agency will submit an adjustment to the
current Information Collection Report.
Send comments regarding this change in the information collection
requirements or any other aspect of this collection of information,
including suggestions for reducing the burden, to Chief, Information
Policy Branch (PM-223Y), U.S. Environmental Protection Agency, 401 M
Street SW., Washington, DC 20460; and to the Paperwork Reduction
Project, Office of Information and Regulatory Affairs, Office of
Management and Budget, 726 Jackson Place NW., Washington, DC 20503,
marked ``Attention: Desk Officer for EPA.''
D. Regulatory Flexibility Act
The Regulatory Flexibility Act (5 U.S.C. 601, et seq.) requires EPA
to consider potential impacts of proposed regulations on small business
``entities.'' If a preliminary analysis indicates that a proposed
regulation would have a significant economic impact on 20 percent or
more of small entities, then a regulatory flexibility analysis must be
prepared.
Current Regulatory Flexibility Act guidelines indicate that an
economic impact should be considered significant if it meets one of the
following criteria: (1) Compliance increases annual production costs by
more than 5 percent, assuming costs are passed onto consumers; (2)
compliance costs as a percentage of sales for small entities are at
least 10 percent more than compliance costs as a percentage of sales
for large entities; (3) capital costs of compliance represent a
``significant'' portion of capital available to small entities,
considering internal cash flow plus external financial capabilities; or
(4) regulatory requirements are likely to result in closures of small
entities.
Under the Regulatory Flexibility Act, a small business is any
``small business concern'' as identified by the Small Business
Administration under section 3 of the Small Business Act. As of January
1, 1991, the Small Business Administration had established the size
threshold for small electric services companies at 4 million megawatt
hours per year. Because all of the utilities affected by Phase I of the
Acid Rain regulations have generating capacities greater than 4 million
megawatt hours, EPA believes that no small businesses are affected by
today's revised rule. The EPA's initial estimates are that the burden
on small utilities under Phase II is minimal.
Pursuant to the provisions of 5 U.S.C. 605(b), I hereby certify
that this rule, if promulgated, will not have a significant adverse
impact on a substantial number of small entities.
E. Miscellaneous
In accordance with section 117 of the Act, publication of this rule
was preceded by consultation with appropriate advisory committees,
independent experts, and federal departments and agencies.
List of Subjects in 40 CFR Part 76
Acid rain program, Air pollution control, Nitrogen oxide,
Incorporation by reference, Reporting and recordkeeping requirements.
Dated: March 31, 1995.
Carol M. Browner,
Administrator.
Title 40, chapter I, of the Code of Federal Regulations is amended
as follows:
1. Part 76 is revised to read as follows:
PART 76--ACID RAIN NITROGEN OXIDES EMISSION REDUCTION PROGRAM
Sec.
76.1 Applicability.
76.2 Definitions.
76.3 General Acid Rain Program provisions.
76.4 Incorporation by reference.
76.5 NO