[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 (NO<INF>X) from coal-fired utility 
units under section 407 of the Clean Air Act (``the Act''). The 
emission limitations for NO<INF>X, 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 NO<INF>X 
emission limitations. The rule established emission limits generally 
achievable using ``low NO<INF>X 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 NO<INF>X 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-
NO<INF>X-burner-technology definition is revised to comply with the 
Court's decision. Other provisions concerning the compliance date for 
Phase I NO<INF>X emission limitations, AELs, and plans for averaging 
NO<INF>X 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 NO<INF>X 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 NO<INF>X Emission Limitations
      3. Alternative Emission Limitations
      4. NO<INF>X Averaging Plans
      5. Phase I NO<INF>X 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 NO<INF>X Program

    The purpose of the Acid Rain NO<INF>X 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 NO<INF>X from coal-fired 
electric utilities. 42 U.S.C. 7651(a)(1). NO<INF>X, 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 
NO<INF>X 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 NO<INF>X 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 NO<INF>X emissions 
nationwide; in 1980, they accounted for 30 percent of total NO<INF>X 
emissions and, by 1990, their contribution rose to 38 percent of total 
NO<INF>X emissions. Approximately 80 percent of electric utility 
NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X emission limitation on the later of January 
1, 1995 or the date the unit is required to meet SO<INF>2 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 
NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X burner technology'' 
plays an important role in section 407 of the Act. There has been 
substantial controversy as to whether Congress intended ``low NO<INF>X 
burner technology'' to be equivalent to ``low NO<INF>X burners'' and 
whether ``low NO<INF>X 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 NO<INF>X 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 NO<INF>X burner technology, the proposed rule contained two 
regulatory options and an alternative approach for defining that term. 
Option 1 defined low NO<INF>X burner technology as low NO<INF>X burners 
incorporating overfire air for wall-fired boilers and as low NO<INF>X 
burners incorporating separated overfire air (e.g., LNCFS 2 and LNCFS 
3) for tangentially fired boilers (57 FR 55642). Option 2 defined low 
NO<INF>X burner technology as low NO<INF>X 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 NO<INF>X 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 NO<INF>X rule (59 FR 
13538-13580). In that rule, EPA adopted the Option 1 definition of low 
NO<INF>X burner technology after considering the chemical process of 
low NO<INF>X combustion, the history and application of low NO<INF>X 
combustion technology, Congress' intent in section 407 of the Act, and 
the actual application of NO<INF>X 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 NO<INF>X 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 NO<INF>X burner technology' to 
encompass only low NO<INF>X 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 NO<INF>X 
combustion technologies' because it expressly provided that utilities 
not be required to install or use any equipment beyond low NO<INF>X 
burners in their efforts to comply with NO<INF>X 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 NO<INF>X burners and low NO<INF>X burner technology. Because 
the Court determined that, in defining low NO<INF>X 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 NO<INF>X burners and low NO<INF>X burner technology,'' in 
Sec. 76.2. The Court determined that low NO<INF>X burner technology 
encompasses ``only low NO<INF>X 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 
NO<INF>X burner technology includes ``any combination of coal and air 
nozzles ports * * * not restricted to location within the boiler, 
including * * * NO<INF>X 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 waterwall<SUP>1 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 NO<INF>X burner technology 
includes only low NO<INF>X 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 NO<INF>X combustion controls 
have been used: (1) Advanced burner retrofits for reducing NO<INF>X 
formation (``burner retrofits'');<SUP>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 NO<INF>X 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 NO<INF>X 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-NO<INF>X-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 NO<INF>X burners).
    For tangentially fired boilers, all commercially available systems 
for reducing NO<INF>X 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 NO<INF>X 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'');<SUP>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 NO<INF>X 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 NO<INF>X 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-NO<INF>X-burner-
technology definition, as applied to tangentially fired boilers, 
includes the applications of LNCFS 1 (and other low NO<INF>X burner 
designs)<SUP>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 NO<INF>X 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 NO<INF>X burner technology'' be limited to low NO<INF>X 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 NO<INF>X 
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 NO<INF>X 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-NO<INF>X-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.<SUP>5 In particular, the new low-NO<INF>X-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 NO<INF>X 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 NO<INF>X 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 NO<INF>X 
emission limitations. Under the March 22, 1994 rule, such a Phase I 
unit must begin compliance with NO<INF>X emission limitations on the 
later of January 1, 1995 or the date the unit becomes subject to 
SO<INF>2 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).<SUP>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 NO<INF>X 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 
NO<INF>X 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 NO<INF>X 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 
NO<INF>X 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 NO<INF>X 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 NO<INF>X emission limitations after January 1, 1995. 
Section 407 required the Agency to issue final NO<INF>X 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-NO<INF>X-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 
NO<INF>X control equipment, including low NO<INF>X burners. Of the 175 
Phase I units with Group 1 boilers on Table A of section 404, all 
submitted NO<INF>X compliance plans by May 6, 1994 and only 31 
requested a compliance date extension.<SUP>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 
SO<INF>2 under Sec. 72.42 (which automatically granted them a 2-year 
NO<INF>X extension), and 6 units applied for a 15 month Phase I 
NO<INF>X 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 SO<INF>2 and NO<INF>X emissions reductions. 
Units must comply with SO<INF>2 emission limitations by emitting no 
more SO<INF>2 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X burner technology under the new 
definition in Sec. 72.2.<SUP>8

    \8\Since low NO<INF>X 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 NO<INF>X emission control system) that improve 
NO<INF>X 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 NO<INF>X control 
system from being operated in accordance with the bid and design 
specifications on which the design of the NO<INF>X 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-NO<INF>X-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-NO<INF>X-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 NO<INF>X emissions as low NO<INF>X 
burner technology as applied to tangentially fired boilers. See Docket 
Item IV-A-10, Background Document for RIA of NO<INF>X 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 NO<INF>X emission control technology 
other than low NO<INF>X 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 NO<INF>X 
burner technology, to reduce NO<INF>X 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.<SUP>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-NO<INF>X-burner-technology definition.

    \9\In order to avoid repeating in other sections the NO<INF>X 
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 
NO<INF>X 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 
NO<INF>X emission control system'' or ``NO<INF>X 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).
---------------------------------------------------------------------------

    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 NO<INF>X 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 ``NO<INF>X emission control system.'' See 59 FR 13574 
(Sec. 76.14(a)(2)(i)) and 13575 (Sec. 76.15(b)(3) and (d)(2)).<SUP>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 NO<INF>X 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 NO<INF>X 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 
NO<INF>X burners. Nothing in the Court's decision mandates any further 
changes in the AEL provisions.
4. NO<INF>X 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 NO<INF>X 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 
NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 
NO<INF>X 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 NO<INF>X 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 NO<INF>X 
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 NO<INF>X 
emission control systems and what types of NO<INF>X 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 NO<INF>X emissions with units with lower 
NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 
NO<INF>X 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.<SUP>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 NO<INF>X emission limitations in 
Phase I but is allowed to participate in a NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X Compliance Extensions
    Section 76.12 is revised in order to reflect the new low-NO<INF>X-
burner-technology definition. The March 22, 1994 rule provides for a 
Phase I NO<INF>X 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 NO<INF>X 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 NO<INF>X 
compliance extension for units where low NO<INF>X 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 NO<INF>X 
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 NO<INF>X 
emission limits and, due to claimed operational problems associated 
with the planned NO<INF>X emission control systems, one unit may need 
an additional extension to redesign and install low NO<INF>X burner 
technology. Because of its extension under section 404(d), the unit has 
not yet installed the NO<INF>X control system that was designed to 
comply with the low-NO<INF>X-burner technology definition in the March 
22, 1994 rule. With the change adopted today in the definition, the 
unit has flexibility to redesign the NO<INF>X 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 NO<INF>X burner technology 
without causing system reliability problems.
    Because the need for an additional extension appears to result from 
the change in the low-NO<INF>X-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 NO<INF>X 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]]
NO<INF>X 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 NO<INF>X 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-NO<INF>X-
burner-technology definition, the cost reports are not required for: 
wall-fired boilers using only overfire air and not low NO<INF>X 
burners; and tangentially fired boilers using only separated overfire 
air and not low NO<INF>X burner technology. Because such boilers are 
not using low NO<INF>X burner technology, cost data on their NO<INF>X 
emissions controls are not relevant to setting of Group 2, Phase II 
NO<INF>X 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 NO<INF>X 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 NO<INF>X 
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 NO<INF>X burner technology. In the March 22, 1994 
rule, the Administrator found that the record evidence showed that the 
presumptive limits were achievable using low NO<INF>X 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-
NO<INF>X-burner-technology definition, the Administrator has reviewed 
the record concerning the performance of low NO<INF>X 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-NO<INF>X-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 NO<INF>X 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 NO<INF>X control systems. The analysis of data 
from wall-fired and tangentially fired boilers, fitted with low 
NO<INF>X burner technology as defined by DOE, indicated that NO<INF>X 
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 NO<INF>X control technology performance 
estimates were consistent with average NO<INF>X reductions projected by 
the utilities. The utilities projected average NO<INF>X 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).<SUP>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 
NO<INF>X 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 NO<INF>X 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 NO<INF>X 
burner technology, show that (the presumptive) limits are aggressive 
but generally achievable by most Group 1 units with the use of (low 
NO<INF>X 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 NO<INF>X 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 NO<INF>X reductions of 40 to 50 percent using 
low NO<INF>X 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)<SUP>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 NO<INF>X control system does not fall within the new low-
NO<INF>X-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 NO<INF>X compliance plans. (See 59 FR 13567 (Sec. 76.9 (a) 
through (c))). For units lacking Acid Rain permits, the NO<INF>X 
compliance plans were submitted along with applications for such 
permits. For units that already had Acid Rain permits covering SO<INF>2 
emission limitations, the NO<INF>X compliance plans were submitted as 
permit revisions. Most of the plans required NO<INF>X compliance 
commencing on January 1, 1995. Twenty-five units had previously been 
granted 2-year extensions for NO<INF>X 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 NO<INF>X 
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, NO<INF>X 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 NO<INF>X compliance plans already submitted to the Agency, units 
sought to comply either with the presumptive limits or through NO<INF>X 
emissions averaging plans. The units that requested NO<INF>X compliance 
extensions sought to comply either with the presumptive limits or 
through NO<INF>X emissions averaging plans after the extensions expire.
    If, as anticipated, the revised rule becomes final and thereby 
reinstates the NO<INF>X emission reduction program, the Agency sees no 
need for utilities to resubmit and for EPA to reissue, through notice 
and comment procedures, the NO<INF>X 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 
NO<INF>X emission limitations and do not state any definition for low 
NO<INF>X burner technology. The revised rule changes the low-NO<INF>X-
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 NO<INF>X 
compliance plans.
    The only changes that the revised rule makes in the submitted 
NO<INF>X compliance plans are in the general compliance date and in the 
effect of group compliance on individual-unit limits in NO<INF>X 
averaging plans. The general deadline for compliance by a Group 1, 
Phase I unit with NO<INF>X emission limitations is now the later of 
January 1, 1996 (rather than 1995) or the date on which a unit is 
subject to SO<INF>2 emission reduction requirements under section 
404(d) of the Act. The revised rule also mandates, for all NO<INF>X 
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 NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 
NO<INF>X 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 NO<INF>X compliance plans as amended and the approved 
Phase I NO<INF>X compliance extensions under Secs. 72.42 and 76.12 that 
are referenced in the plans.
    With regard to NO<INF>X 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 NO<INF>X 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 NO<INF>X 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 NO<INF>X requirements 
will be passed along to ratepayers. When NO<INF>X 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 NO<INF>X emission reductions because 
atmospheric emissions of NO<INF>X 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<INF>X emission limitations for Group 1 boilers.
76.6  NO<INF>X emission limitations for Group 2 boilers. [Reserved]
76.7  Revised NO<INF>X emission limitations for Group 1, Phase II 
boilers. [Reserved]
76.8  Early election for Group 1, Phase II boilers.
76.9  Permit application and compliance plans.
76.10  Alternative emission limitations.
76.11  Emissions averaging.
76.12  Phase I NO<INF>X compliance extensions.
76.13  Compliance and excess emissions.
76.14  Monitoring, recordkeeping, and reporting.
76.15  Test methods and procedures.
76.16  [Reserved].

Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units with 
Group 1 or Cell Burner Boilers

Appendix B to Part 76--Procedures And Methods For Estimating Costs Of 
Nitrogen Oxides Controls Applied To Group 1, Phase I Boilers

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


Sec. 76.1  Applicability.

    (a) Except as provided in paragraphs (b) through (d) of this 
section, the provisions apply to each coal-fired utility unit that is 
subject to an Acid Rain emissions limitation or reduction requirement 
for SO<INF>2 under Phase I or Phase II pursuant to sections 404, 405, 
or 409 of the Act.
    (b) The emission limitations for NO<INF>X under this part apply to 
each affected coal-fired utility unit subject to section 404(d) or 
409(b) of the Act on the date the unit is required to meet the Acid 
Rain emissions reduction requirement for SO<INF>2.
    (c) The provisions of this part apply to each coal-fired 
substitution unit or compensating unit, designated and approved as a 
Phase I unit pursuant to Secs. 72.41 or 72.43 of this chapter as 
follows:
    (1) A coal-fired substitution unit that is designated in a 
substitution plan that is approved and active as of January 1, 1995 
shall be treated as a Phase I coal-fired utility unit for purposes of 
this part. In the event the designation of such unit as a substitution 
unit is terminated after December 31, 1995, pursuant to Sec. 72.41 of 
this chapter and the unit is no longer required to meet Phase I 
SO<INF>2 emissions limitations, the provisions of this part (including 
those applicable in Phase I) will continue to apply.
    (2) A coal-fired substitution unit that is designated in a 
substitution plan that is not approved or not active as of January 1, 
1995, or a coal-fired compensating unit, shall be treated as a Phase II 
coal-fired utility unit for purposes of this part.
    (d) The provisions of this part for Phase I units apply to each 
coal-fired transfer unit governed by a Phase I extension plan, approved 
pursuant to 

[[Page 18762]]
Sec. 72.42 of this chapter, on January 1, 1997. Notwithstanding the 
preceding sentence, a coal-fired transfer unit shall be subject to the 
Acid Rain emissions limitations for nitrogen oxides beginning on 
January 1, 1996 if, for that year, a transfer unit is allocated fewer 
Phase I extension reserve allowances than the maximum amount that the 
designated representative could have requested in accordance with 
Sec. 72.42(c)(5) of this chapter (as adjusted under Sec. 72.42(d) of 
this chapter) unless the transfer unit is the last unit allocated Phase 
I extension reserve allowances under the plan.


Sec. 76.2  Definitions.

    All terms used in this part shall have the meaning set forth in the 
Act, in Sec. 72.2 of this chapter, and in this section as follows:
    Alternative contemporaneous annual emission limitation means the 
maximum allowable NO<INF>X emission rate (on a lb/mmBtu, annual average 
basis) assigned to an individual unit in a NO<INF>X emissions averaging 
plan pursuant to Sec. 76.10.
    Alternative technology means a control technology for reducing 
NO<INF>X emissions that is outside the scope of the definition of low 
NO<INF>X burner technology. Alternative technology does not include 
overfire air as applied to wall-fired boilers or separated overfire air 
as applied to tangentially fired boilers.
    Approved clean coal technology demonstration project means a 
project using funds appropriated under the Department of Energy's 
``Clean Coal Technology Demonstration Program,'' up to a total amount 
of $2,500,000,000 for commercial demonstration of clean coal 
technology, or similar projects funded through appropriations for the 
Environmental Protection Agency. The Federal contribution for a 
qualifying project shall be at least 20 percent of the total cost of 
the demonstration project.
    Cell burner boiler means a wall-fired boiler that utilizes two or 
three circular burners combined into a single vertically oriented 
assembly that results in a compact, intense flame. Any low NO<INF>X 
retrofit of a cell burner boiler that reuses the existing cell burner, 
close-coupled wall opening configuration would not change the 
designation of the unit as a cell burner boiler.
    Coal-fired utility unit means a utility unit in which the 
combustion of coal (or any coal-derived fuel) on a Btu basis exceeds 
50.0 percent of its annual heat input, for Phase I units in calendar 
year 1990 and, for Phase II units in the calendar year 1995. For the 
purposes of this part, this definition shall apply notwithstanding the 
definition at Sec. 72.2 of this chapter.
    Cyclone boiler means a boiler with one or more water-cooled 
horizontal cylindrical chambers in which coal combustion takes place. 
The horizontal cylindrical chamber(s) is (are) attached to the bottom 
of the furnace. One or more cylindrical chambers are arranged either on 
one furnace wall or on two opposed furnace walls. Gaseous combustion 
products exiting from the chamber(s) turn 90 degrees to go up through 
the boiler while coal ash exits the bottom of the boiler as a molten 
slag.
    Demonstration period means a period of time not less than 15 
months, approved under Sec. 76.10, for demonstrating that the affected 
unit cannot meet the applicable emission limitation under Secs. 76.5, 
76.6, or 76.7 and establishing the minimum NO<INF>X emission rate that 
the unit can achieve during long-term load dispatch operation.
    Dry bottom means the boiler has a furnace bottom temperature below 
the ash melting point and the bottom ash is removed as a solid.
    Economizer means the lowest temperature heat exchange section of a 
utility boiler where boiler feed water is heated by the flue gas.
    Flue gas means the combustion products arising from the combustion 
of fossil fuel in a utility boiler.
    Group 1 boiler means a tangentially fired boiler or a dry bottom 
wall-fired boiler (other than a unit applying cell burner technology).
    Group 2 boiler means a wet bottom wall-fired boiler, a cyclone 
boiler, a boiler applying cell burner technology, a vertically fired 
boiler, an arch-fired boiler, or any other type of utility boiler (such 
as a fluidized bed or stoker boiler) that is not a Group 1 boiler.
    Low NO<INF>X burners and low NO<INF>X burner technology means 
commercially available combustion modification NO<INF>X controls that 
minimize NO<INF>X formation by introducing coal and its associated 
combustion air into a boiler such that initial combustion occurs in a 
manner that promotes rapid coal devolatilization in a fuel-rich (i.e., 
oxygen deficient) environment and introduces additional air to achieve 
a final fuel-lean (i.e., oxygen rich) environment to complete the 
combustion process. This definition shall include the staging of any 
portion of the combustion air using air nozzles or registers located 
inside any waterwall hole that includes a burner. This definition shall 
exclude the staging of any portion of the combustion air using air 
nozzles or ports located outside any waterwall hole that includes a 
burner (commonly referred to as NO<INF>X ports or separated overfire 
air ports).
    Operating period means a period of time of not less than three 
consecutive months and that occurs not more than one month prior to 
applying for an alternative emission limitation demonstration period 
under Sec. 76.10, during which the owner or operator of an affected 
unit that cannot meet the applicable emission limitation:
    (1) Operates the installed NO<INF>X emission controls in accordance 
with primary vendor specifications and procedures, with the unit 
operating under normal conditions; and
    (2) records and reports quality-assured continuous emission 
monitoring (CEM) and unit operating data according to the methods and 
procedures in part 75 of this chapter.
    Primary vendor means the vendor of the NO<INF>X emission control 
system who has primary responsibility for providing the equipment, 
service, and technical expertise necessary for detailed design, 
installation, and operation of the controls, including process data, 
mechanical drawings, operating manuals, or any combination thereof.
    Reburning means reducing the coal and combustion air to the main 
burners and injecting a reburn fuel (such as gas or oil) to create a 
fuel-rich secondary combustion zone above the main burner zone and 
final combustion air to create a fuel-lean burnout zone. The formation 
of NO<INF>X is inhibited in the main burner zone due to the reduced 
combustion intensity, and NO<INF>X is destroyed in the fuel-rich 
secondary combustion zone by conversion to molecular nitrogen.
    Selective catalytic reduction means a noncombustion control 
technology that destroys NO<INF>X by injecting a reducing agent (e.g., 
ammonia) into the flue gas that, in the presence of a catalyst (e.g., 
vanadium, titanium, or zeolite), converts NO<INF>X into molecular 
nitrogen and water.
    Selective noncatalytic reduction means a noncombustion control 
technology that destroys NO<INF>X by injecting a reducing agent (e.g., 
ammonia, urea, or cyanuric acid) into the flue gas, downstream of the 
combustion zone that converts NO<INF>X to molecular nitrogen, water, 
and when urea or cyanuric acid are used, to carbon dioxide (CO<INF>2).
    Stoker boiler means a boiler that burns solid fuel in a bed, on a 
stationary or moving grate, that is located at the bottom of the 
furnace.
    Tangentially fired boiler means a boiler that has coal and air 
nozzles mounted in each corner of the furnace where the vertical 
furnace walls meet. Both pulverized coal and air are 

[[Page 18763]]
directed from the furnace corners along a line tangential to a circle 
lying in a horizontal plane of the furnace.
    Turbo-fired boiler means a pulverized coal, wall-fired boiler with 
burners arranged on walls so that the individual flames extend down 
toward the furnace bottom and then turn back up through the center of 
the furnace.
    Wall-fired boiler means a boiler that has pulverized coal burners 
arranged on the walls of the furnace. The burners have discrete, 
individual flames that extend perpendicularly into the furnace area.
    Wet bottom means the boiler has a furnace bottom temperature above 
the ash melting point and the bottom ash is removed as a liquid.


Sec. 76.3  General Acid Rain Program provisions.

    The following provisions of part 72 of this chapter shall apply to 
this part:
    (a) Sec. 72.2  (Definitions);
    (b) Sec. 72.3  (Measurements, abbreviations, and acronyms);
    (c) Sec. 72.4  (Federal authority);
    (d) Sec. 72.5  (State authority);
    (e) Sec. 72.6  (Applicability);
    (f) Sec. 72.7  (New unit exemption);
    (g) Sec. 72.8  (Retired units exemption);
    (h) Sec. 72.9  (Standard requirements);
    (i) Sec. 72.10  (Availability of information); and
    (j) Sec. 72.11  (Computation of time).
    In addition, the procedures for appeals of decisions of the 
Administrator under this part are contained in part 78 of this chapter.


Sec. 76.4  Incorporation by reference.

    (a) The materials listed in this section are incorporated by 
reference in the sections noted. These incorporations by reference 
(IBR's) were approved by the Director of the Federal Register in 
accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are 
incorporated as they existed on the date of approval, and notice of any 
change in these materials will be published in the Federal Register. 
The materials are available for purchase at the corresponding address 
noted below and are available for inspection at the Office of the 
Federal Register, 800 North Capitol St., NW., 7th Floor, Suite 700, 
Washington, DC, at the Public Information Reference Unit, U.S. EPA, 401 
M Street, SW., Washington, DC, and at the Library (MD-35), U.S. EPA, 
Research Triangle Park, North Carolina.
    (b) The following materials are available for purchase from at 
least one of the following addresses: American Society for Testing and 
Materials (ASTM), 1916 Race Street, Philadelphia, Pennsylvania 19103; 
or the University Microfilms International, 300 North Zeeb Road, Ann 
Arbor, Michigan 48106.
    (1) ASTM D 3176-89, Standard Practice for Ultimate Analysis of Coal 
and Coke, IBR approved May 23, 1995 for Sec. 76.15.
    (2) ASTM D 3172-89, Standard Practice for Proximate Analysis of 
Coal and Coke, IBR approved May 23, 1995 for Sec. 76.15.
    (c) The following material is available for purchase from the 
American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 
2350, Fairfield, NJ 07007-2350.
    (1) ASME Performance Test Code 4.2 (1991), Test Code for Coal 
Pulverizers, IBR approved May 23, 1995 for Sec. 76.15.
    (2) [Reserved]
    (d) The following material is available for purchase from the 
American National Standards Institute, 11 West 42nd Street, New York, 
NY 10036 or from the International Organization for Standardization 
(ISO), Case Postale 56, CH-1211 Geneve 20, Switzerland.
    (1) ISO 9931 (December, 1991) ``Coal--Sampling of Pulverized Coal 
Conveyed by Gases in Direct Fired Coal Systems,'' IBR approved May 23, 
1995 for Sec. 76.15.
    (2) [Reserved]


Sec. 76.5  NO<INF>X emission limitations for Group 1 boilers.

    (a) Beginning January 1, 1996, or for a unit subject to section 
404(d) of the Act, the date on which the unit is required to meet Acid 
Rain emission reduction requirements for SO<INF>2, the owner or 
operator of a Phase I coal-fired utility unit with a tangentially fired 
boiler or a dry bottom wall-fired boiler (other than units applying 
cell burner technology) shall not discharge, or allow to be discharged, 
emissions of NO<INF>X to the atmosphere in excess of the following 
limits, except as provided in paragraphs (c) or (e) of this section or 
in Secs. 76.10, 76.11, or 76.12:
    (1) 0.45 lb/mmBtu of heat input on an annual average basis for 
tangentially fired boilers.
    (2) 0.50 lb/mmBtu of heat input on an annual average basis for dry 
bottom wall-fired boilers (other than units applying cell burner 
technology).
    (b) The owner or operator shall determine the annual average 
NO<INF>X emission rate, in lb/mmBtu, using the methods and procedures 
specified in part 75 of this chapter.
    (c) Unless the unit meets the early election requirement of 
Sec. 76.8, the owner or operator of a coal-fired substitution unit with 
a tangentially fired boiler or a dry bottom wall-fired boiler (other 
than units applying cell burner technology) that satisfies the 
requirements of Sec. 76.1(c)(2), shall comply with the NO<INF>X 
emission limitations that apply to Group 1, Phase II boilers.
    (d) The owner or operator of a Phase I unit with a cell burner 
boiler that converts to a conventional wall-fired boiler on or before 
January 1, 1995 or, for a unit subject to section 404(d) of the Act, 
the date the unit is required to meet Acid Rain emissions reduction 
requirements for SO<INF>2 shall comply, by such respective date or 
January 1, 1996, whichever is later, with the NO<INF>X emissions 
limitation applicable to dry bottom wall-fired boilers under paragraph 
(a) of this section, except as provided in paragraphs (c) or (e) of 
this section or in Secs. 76.10, 76.11, or 76.12.
    (e) The owner or operator of a Phase I unit with a Group 1 boiler 
that converts to a fluidized bed or other type of utility boiler not 
included in Group 1 boilers on or before January 1, 1995 or, for a unit 
subject to section 404(d) of the Act, the date the unit is required to 
meet Acid Rain emissions reduction requirements for SO<INF>2 is exempt 
from the NO<INF>X emissions limitations specified in paragraph (a) of 
this section, but shall comply with the NO<INF>X emission limitations 
for Group 2 boilers under Sec. 76.6.
    (f) Except as provided in Sec. 76.8 and in paragraph (c) of this 
section, each unit subject to the requirements of this section is not 
subject to the requirements of Sec. 76.7.
    (g) Beginning January 1, 2000, the owner or operator of a Group 1, 
Phase II coal-fired utility unit with a tangentially fired boiler or a 
wall-fired boiler shall be subject to the emission limitations in 
paragraph (a) of this section.


Sec. 76.6  NO<INF>X emission limitations for Group 2 boilers.  
[Reserved]


Sec. 76.7  Revised NO<INF>X emission limitations for Group 1, Phase II 
boilers.  [Reserved]


Sec. 76.8  Early election for Group 1, Phase II boilers.

    (a) General provisions. (1) The owner or operator of a Phase II 
coal-fired utility unit with a Group 1 boiler may elect to have the 
unit become subject to the applicable emissions limitation for NO<INF>X 
under Sec. 76.5, starting no later than January 1, 1997.
    (2) The owner or operator of a Phase II coal-fired utility unit 
with a Group 1 boiler that elects to become subject to the applicable 
emission limitation under Sec. 76.5 shall not be subject to any revised 
NO<INF>X emissions limitation for Group 1 boilers that the 
Administrator may issue pursuant to section 407(b)(2) of the Act until 
January 1, 2008, 

[[Page 18764]]
provided the designated representative demonstrates that the unit is in 
compliance with the limitation under Sec. 76.5, using the methods and 
procedures specified in part 75 of this chapter, for the period 
beginning January 1 of the year in which the early election takes 
effect (but not later than January 1, 1997) and ending December 31, 
2007.
    (3) The owner or operator of any Phase II unit with a cell burner 
boiler that converts to conventional burner technology may elect to 
become subject to the applicable emissions limitation under Sec. 76.5 
for dry bottom wall-fired boilers, provided the owner or operator 
complies with the provisions in paragraph (a)(2) of this section.
    (4) The owner or operator of a Phase II unit approved for early 
election shall not submit an application for an alternative emissions 
limitation demonstration period under Sec. 76.10 until the earlier of:
    (i) January 1, 2008; or
    (ii) Early election is terminated pursuant to paragraph (e)(3) of 
this section.
    (5) The owner or operator of a Phase II unit approved for early 
election may not incorporate the unit into an averaging plan prior to 
January 1, 2000. On or after January 1, 2000, for purposes of the 
averaging plan, the early election unit will be treated as subject to 
the applicable emissions limitation for NO<INF>X for Phase II units 
with Group 1 boilers under Secs. 76.5(g) and if revised emission 
limitations are issued for Group 1 boilers pursuant to section 
407(b)(2) of the Act, Sec. 76.7.
    (b) Submission requirements. In order to obtain early election 
status, the designated representative of a Phase II unit with a Group 1 
boiler shall submit an early election plan to the Administrator by 
January 1 of the year the early election is to take effect, but not 
later than January 1, 1997. Notwithstanding Sec. 72.40 of this chapter, 
and unless the unit is a substitution unit under Sec. 72.41 of this 
chapter or a compensating unit under Sec. 72.43 of this chapter, a 
complete compliance plan covering the unit shall not include the 
provisions for SO<INF>2 emissions under Sec. 72.40(a)(1) of this 
chapter.
    (c) Contents of an early election plan. A complete early election 
plan shall include the following elements in a format prescribed by the 
Administrator:
    (1) A request for early election;
    (2) The first year for which early election is to take effect, but 
not later than 1997; and
    (3) The special provisions under paragraph (e) of this section.
    (d)(1) Permitting authority's action. To the extent the 
Administrator determines that an early election plan complies with the 
requirements of this section, the Administrator will approve the plan 
and:
    (i) If a Phase I Acid Rain permit governing the source at which the 
unit is located has been issued, will revise the permit in accordance 
with the permit modification procedures in Sec. 72.81 of this chapter 
to include the early election plan; or
    (ii) If a Phase I Acid Rain permit governing the source at which 
the unit is located has not been issued, will issue a Phase I Acid Rain 
permit effective from January 1, 1995 through December 31, 1999, that 
will include the early election plan and a complete compliance plan 
under Sec. 72.40(a) of this chapter and paragraph (b) of this section. 
If the early election plan is not effective until after January 1, 
1995, the permit will not contain any NO<INF>X emissions limitations 
until the effective date of the plan.
    (2) Beginning January 1, 2000, the permitting authority will 
approve any early election plan previously approved by the 
Administrator during Phase I, unless the plan is terminated pursuant to 
paragraph (e)(3) of this section.
    (e) Special provisions--(1) Emissions limitations.--(i) Sulfur 
dioxide. Notwithstanding Sec. 72.9 of this chapter, a unit that is 
governed by an approved early election plan and that is not a 
substitution unit under Sec. 72.41 of this chapter or a compensating 
unit under Sec. 72.43 of this chapter shall not be subject to the 
following standard requirements under Sec. 72.9 of this chapter for 
Phase I:
    (A) The permit requirements under Secs. 72.9(a)(1) (i) and (ii) of 
this chapter;
    (B) The sulfur dioxide requirements under Sec. 72.9(c) of this 
chapter; and
    (C) The excess emissions requirements under Sec. 72.9(e)(1) of this 
chapter.
    (ii) Nitrogen oxides. A unit that is governed by an approved early 
election plan shall be subject to an emissions limitation for NO<INF>X 
as provided under paragraph (a)(2) of this section except as provided 
under paragraph (e)(3)(iii) of this section.
    (2) Liability. The owners and operators of any unit governed by an 
approved early election plan shall be liable for any violation of the 
plan or this section at that unit. The owners and operators shall be 
liable, beginning January 1, 2000, for fulfilling the obligations 
specified in part 77 of this chapter.
    (3) Termination. An approved early election plan shall be in effect 
only until the earlier of January 1, 2008 or January 1 of the calendar 
year for which a termination of the plan takes effect.
    (i) If the designated representative of the unit under an approved 
early election plan fails to demonstrate compliance with the applicable 
emissions limitation under Sec. 76.5 for any year during the period 
beginning January 1 of the first year the early election takes effect 
and ending December 31, 2007, the permitting authority will terminate 
the plan. The termination will take effect beginning January 1 of the 
year after the year for which there is a failure to demonstrate 
compliance, and the designated representative may not submit a new 
early election plan.
    (ii) The designated representative of the unit under an approved 
early election plan may terminate the plan any year prior to 2008 but 
may not submit a new early election plan. In order to terminate the 
plan, the designated representative must submit a notice under 
Sec. 72.40(d) of this chapter by January 1 of the year for which the 
termination is to take effect.
    (iii)(A) If an early election plan is terminated any year prior to 
2000, the unit shall meet, beginning January 1, 2000, the applicable 
emissions limitation for NO<INF>X for Phase II units with Group 1 
boilers under Sec. 76.5(g) and, if revised emission limitations are 
issued pursuant to section 407(b)(2) of the Act, Sec. 76.7.
    (B) If an early election plan is terminated in or after 2000, the 
unit shall meet, beginning on the effective date of the termination, 
the applicable emissions limitation for NO<INF>X for Phase II units 
with Group 1 boilers under Sec. 76.5(g) and, if revised emission 
limitations are issued pursuant to section 407(b)(2) of the Act, 
Sec. 76.7.


Sec. 76.9  Permit application and compliance plans.

    (a) Duty to apply. (1) The designated representative of any source 
with an affected unit subject to this part shall submit, by the 
applicable deadline under paragraph (b) of this section, a complete 
Acid Rain permit application (or, if the unit is covered by an Acid 
Rain permit, a complete permit revision) that includes a complete 
compliance plan for NO<INF>X emissions covering the unit.
    (2) The original and three copies of the permit application and 
compliance plan for NO<INF>X emissions for Phase I shall be submitted 
to the EPA regional office for the region where the applicable source 
is located. The original and three copies of the permit application and 
compliance plan for NO<INF>X emissions for 

[[Page 18765]]
Phase II shall be submitted to the permitting authority.
    (b) Deadlines. (1) For a Phase I unit with a Group 1 boiler, the 
designated representative shall submit a complete permit application 
and compliance plan for NO<INF>X covering the unit during Phase I to 
the applicable permitting authority not later than May 6, 1994.
    (2) For a Phase I or Phase II unit with a Group 2 boiler or a Phase 
II unit with a Group 1 boiler, the designated representative shall 
submit a complete permit application and compliance plan for NO<INF>X 
emissions covering the unit in Phase II to the Administrator not later 
than January 1, 1998, except that early election units shall also 
submit an application not later than January 1, 1997.
    (c) Information requirements for NO<INF>X compliance plans. (1) In 
accordance with Sec. 72.40(a)(2) of this chapter, a complete compliance 
plan for NO<INF>X shall, for each affected unit included in the permit 
application and subject to this part, either certify that the unit will 
comply with the applicable emissions limitation under Sec. 76.5, 76.6, 
or 76.7 or specify one or more other Acid Rain compliance options for 
NO<INF>X in accordance with the requirements of this part. A complete 
compliance plan for NO<INF>X for a source shall include the following 
elements in a format prescribed by the Administrator:
    (i) Identification of the source;
    (ii) Identification of each affected unit that is at the source and 
is subject to this part;
    (iii) Identification of the boiler type of each unit;
    (iv) Identification of the compliance option proposed for each unit 
(i.e., meeting the applicable emissions limitation under Secs. 76.5, 
76.6, 76.7, 76.8 (early election), 76.10 (alternative emission 
limitation), 76.11 (NO<INF>X emissions averaging), or 76.12 (Phase I 
NO<INF>X compliance extension)) and any additional information required 
for the appropriate option in accordance with this part;
    (v) Reference to the standard requirements in Sec. 72.9 of this 
chapter (consistent with Sec. 76.8(e)(1)(i)); and
    (vi) The requirements of Secs. 72.21 (a) and (b) of this chapter.
    (d) Duty to reapply. The designated representative of any source 
with an affected unit subject to this part shall submit a complete Acid 
Rain permit application, including a complete compliance plan for 
NO<INF>X emissions covering the unit, in accordance with the deadlines 
in Sec. 72.30(c) of this chapter.


Sec. 76.10  Alternative emission limitations.

    (a) General provisions. (1) The designated representative of an 
affected unit that is not an early election unit pursuant to Sec. 76.8 
and cannot meet the applicable emission limitation in Secs. 76.5, 76.6, 
or 76.7 using, for Group 1 boilers, either low NO<INF>X burner 
technology or an alternative technology in accordance with paragraph 
(e)(11) of this section, or, for tangentially fired boilers, separated 
overfire air, or, for Group 2 boilers, the technology on which the 
applicable emission limitation is based may petition the permitting 
authority for an alternative emission limitation less stringent than 
the applicable emission limitation.
    (2) In order for the unit to qualify for an alternative emission 
limitation, the designated representative shall demonstrate that the 
affected unit cannot meet the applicable emission limitation in 
Secs. 76.5, 76.6, or 76.7 based on a showing, to the satisfaction of 
the Administrator, that:
    (i) (A) For a tangentially fired boiler, the owner or operator has 
either properly installed low NO<INF>X burner technology or properly 
installed separated overfire air; or
    (B) For a dry bottom wall-fired boiler (other than a unit applying 
cell burner technology), the owner or operator has properly installed 
low NO<INF>X burner technology; or
    (C) For a Group 1 boiler, the owner or operator has properly 
installed an alternative technology (including but not limited to 
reburning, selective noncatalytic reduction, or selective catalytic 
reduction) that achieves NO<INF>X emission reductions demonstrated in 
accordance with paragraph (e)(11) of this section; or
    (D) For a Group 2 boiler, the owner or operator has properly 
installed the appropriate NO<INF>X emission control technology on which 
the applicable emission limitation in Sec. 76.6 is based; and
    (ii) The installed NO<INF>X emission control system has been 
designed to meet the applicable emission limitation in Secs. 76.5, 
76.6, or 76.7; and
    (iii) For a demonstration period of at least 15 months or other 
period of time, as provided in paragraph (f)(1) of this section:
    (A) The NO<INF>X emission control system has been properly 
installed and properly operated according to specifications and 
procedures designed to minimize the emissions of NO<INF>X to the 
atmosphere;
    (B) Unit operating data as specified in this section show that the 
unit and NO<INF>X emission control system were operated in accordance 
with the bid and design specifications on which the design of the 
NO<INF>X emission control system was based; and
    (C) Unit operating data as specified in this section, continuous 
emission monitoring data obtained pursuant to part 75 of this chapter, 
and the test data specific to the NO<INF>X emission control system show 
that the unit could not meet the applicable emission limitation in 
Secs. 76.5, 76.6, or 76.7.
    (b) Petitioning process. The petitioning process for an alternative 
emission limitation shall consist of the following steps:
    (1) Operation during a period of at least 3 months, following the 
installation of the NO<INF>X emission control system, that shows that 
the specific unit and the NO<INF>X emission control system was unable 
to meet the applicable emissions limitation under Secs. 76.5, 76.6, or 
76.7 and was operated in accordance with the operating conditions upon 
which the design of the NO<INF>X emission control system was based and 
with vendor specifications and procedures;
    (2) Submission of a petition for an alternative emission limitation 
demonstration period as specified in paragraph (d) of this section;
    (3) Operation during a demonstration period of at least 15 months, 
or other period of time as provided in paragraph (f)(1) of this 
section, that demonstrates the inability of the specific unit to meet 
the applicable emissions limitation under Secs. 76.5, 76.6, or 76.7 and 
the minimum NO<INF>X emissions rate that the specific unit can achieve 
during long-term load dispatch operation; and
    (4) Submission of a petition for a final alternative emission 
limitation as specified in paragraph (e) of this section.
    (c) Deadlines.--(1) Petition for an alternative emission limitation 
demonstration period. The designated representative of the unit shall 
submit a petition for an alternative emission limitation demonstration 
period to the permitting authority after the unit has been operated for 
at least 3 months after installation of the NO<INF>X emission control 
system required under paragraph (a)(2) of this section and by the 
following deadline:
    (i) For units that seek to have an alternative emission limitation 
demonstration period apply during all or part of calendar year 1996, or 
any previous calendar year by the later of:
    (A) 120 days after startup of the NO<INF>X emission control system, 
or
    (B) May 1, 1996.
    (ii) For units that seek an alternative emission limitation 
demonstration period beginning in a calendar year after 1996, not later 
than: 

[[Page 18766]]

    (A) 120 days after January 1 of that calendar year, or
    (B) 120 days after startup of the NO<INF>X emission control system 
if the unit is not operating at the beginning of that calendar year.
    (2) Petition for a final alternative emission limitation. Not later 
than 90 days after the end of an approved alternative emission 
limitation demonstration period for the unit, the designated 
representative of the unit may submit a petition for an alternative 
emission limitation to the permitting authority.
    (3) Renewal of an alternative emission limitation. In order to 
request continuation of an alternative emission limitation, the 
designated representative must submit a petition to renew the 
alternative emission limitation on the date that the application for 
renewal of the source's Acid Rain permit containing the alternative 
emission limitation is due.
    (d) Contents of petition for an alternative emission limitation 
demonstration period. The designated representative of an affected unit 
that has met the minimum criteria under paragraph (a) of this section 
and that has been operated for a period of at least 3 months following 
the installation of the required NO<INF>X emission control system may 
submit to the permitting authority a petition for an alternative 
emission limitation demonstration period. In the petition, the 
designated representative shall provide the following information in a 
format prescribed by the Administrator:
    (1) Identification of the unit;
    (2) The type of NO<INF>X control technology installed (e.g., low 
NO<INF>X burner technology, selective noncatalytic reduction, selective 
catalytic reduction, reburning);
    (3) If an alternative technology is installed, the time period (not 
less than 6 consecutive months) prior to installation of the technology 
to be used for the demonstration required in paragraph (e)(11) of this 
section.
    (4) Documentation as set forth in Sec. 76.14(a)(1) showing that the 
installed NO<INF>X emission control system has been designed to meet 
the applicable emission limitation in Secs. 76.5, 76.6, or 76.7 and 
that the system has been properly installed according to procedures and 
specifications designed to minimize the emissions of NO<INF>X to the 
atmosphere;
    (5) The date the unit commenced operation following the 
installation of the NO<INF>X emission control system or the date the 
specific unit became subject to the emission limitations of Secs. 76.5, 
76.6, or 76.7, whichever is later;
    (6) The dates of the operating period (which must be at least 3 
months long);
    (7) Certification by the designated representative that the 
owner(s) or operator operated the unit and the NO<INF>X emission 
control system during the operating period in accordance with: 
Specifications and procedures designed to achieve the maximum NO<INF>X 
reduction possible with the installed NO<INF>X emission control system 
or the applicable emission limitation in Secs. 76.5, 76.6, or 76.7; the 
operating conditions upon which the design of the NO<INF>X emission 
control system was based; and vendor specifications and procedures;
    (8) A brief statement describing the reason or reasons why the unit 
cannot achieve the applicable emission limitation in Secs. 76.5, 76.6, 
or 76.7;
    (9) A demonstration period plan, as set forth in Sec. 76.14(a)(2);
    (10) Unit operating data and quality-assured continuous emission 
monitoring data (including the specific data items listed in 
Sec. 76.14(a)(3) collected in accordance with part 75 of this chapter 
during the operating period) and demonstrating the inability of the 
specific unit to meet the applicable emission limitation in Secs. 76.5, 
76.6, or 76.7 on an annual average basis while operating as certified 
under paragraph (d)(7) of this section;
    (11) An interim alternative emission limitation, in lb/mmBtu, that 
the unit can achieve during a demonstration period of at least 15 
months. The interim alternative emission limitation shall be derived 
from the data specified in paragraph (d)(10) of this section using 
methods and procedures satisfactory to the Administrator;
    (12) The proposed dates of the demonstration period (which must be 
at least 15 months long);
    (13) A report which outlines the testing and procedures to be taken 
during the demonstration period in order to determine the maximum 
NO<INF>X emission reduction obtainable with the installed system. The 
report shall include the reasons for the NO<INF>X emission control 
system's failure to meet the applicable emission limitation, and the 
tests and procedures that will be followed to optimize the NO<INF>X 
emission control system's performance. Such tests and procedures may 
include those identified in Sec. 76.15 as appropriate.
    (14) The special provisions at paragraph (g)(1) of this section.
    (e) Contents of petition for a final alternative emission 
limitation. After the approved demonstration period, the designated 
representative of the unit may petition the permitting authority for an 
alternative emission limitation. The petition shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the unit;
    (2) Certification that the owner(s) or operator operated the 
affected unit and the NO<INF>X emission control system during the 
demonstration period in accordance with: specifications and procedures 
designed to achieve the maximum NO<INF>X reduction possible with the 
installed NO<INF>X emission control system or the applicable emissions 
limitation in Secs. 76.5, 76.6, or 76.7; the operating conditions 
(including load dispatch conditions) upon which the design of the 
NO<INF>X emission control system was based; and vendor specifications 
and procedures.
    (3) Certification that the owner(s) or operator have installed in 
the affected unit all NO<INF>X emission control systems, made any 
operational modifications, and completed any planned upgrades and/or 
maintenance to equipment specified in the approved demonstration period 
plan for optimizing NO<INF>X emission reduction performance, consistent 
with the demonstration period plan and the proper operation of the 
installed NO<INF>X emission control system. Such certification shall 
explain any differences between the installed NO<INF>X emission control 
system and the equipment configuration described in the approved 
demonstration period plan.
    (4) A clear description of each step or modification taken during 
the demonstration period to improve or optimize the performance of the 
installed NO<INF>X emission control system.
    (5) Engineering design calculations and drawings that show the 
technical specifications for installation of any additional operational 
or emission control modifications installed during the demonstration 
period.
    (6) Unit operating and quality-assured continuous emission 
monitoring data (including the specific data listed in Sec. 76.14(b)) 
collected in accordance with part 75 of this chapter during the 
demonstration period and demonstrating the inability of the specific 
unit to meet the applicable emission limitation in Secs. 76.5, 76.6, or 
76.7 on an annual average basis while operating in accordance with the 
certification under paragraph (e)(2) of this section.
    (7) A report (based on the parametric test requirements set forth 
in the approved demonstration period plan as identified in paragraph 
(d)(13) of this section), that demonstrates the unit was operated in 
accordance with the operating conditions upon which the 

[[Page 18767]]
design of the NO<INF>X emission control system was based and describes 
the reason or reasons for the failure of the installed NO<INF>X 
emission control system to meet the applicable emission limitation in 
Secs. 76.5, 76.6, or 76.7 on an annual average basis.
    (8) The minimum NO<INF>X emission rate, in lb/mmBtu, that the 
affected unit can achieve on an annual average basis with the installed 
NO<INF>X emission control system. This value, which shall be the 
requested alternative emission limitation, shall be derived from the 
data specified in this section using methods and procedures 
satisfactory to the Administrator and shall be the lowest annual 
emission rate the unit can achieve with the installed NO<INF>X emission 
control system;
    (9) All supporting data and calculations documenting the 
determination of the requested alternative emission limitation and its 
conformance with the methods and procedures satisfactory to the 
Administrator;
    (10) The special provisions in paragraph (g)(2) of this section.
    (11) In addition to the other requirements of this section, the 
owner or operator of an affected unit with a Group 1 boiler that has 
installed an alternative technology in addition to or in lieu of low 
NO<INF>X burner technology and cannot meet the applicable emission 
limitation in Sec. 76.5 shall demonstrate, to the satisfaction of the 
Administrator, that the actual percentage reduction in NO<INF>X 
emissions (lbs/mmBtu), on an annual average basis is greater than 65 
percent of the average annual NO<INF>X emissions prior to the 
installation of the NO<INF>X emission control system. The percentage 
reduction in NO<INF>X emissions shall be determined using continuous 
emissions monitoring data for NO<INF>X taken during the time period 
(under paragraph (d)(3) of this section) prior to the installation of 
the NO<INF>X emission control system and during long-term load dispatch 
operation of the specific boiler.
    (f) Permitting authority's action.--(1) Alternative emission 
limitation demonstration period. (i) The permitting authority may 
approve an alternative emission limitation demonstration period and 
demonstration period plan, provided that the requirements of this 
section are met to the satisfaction of the permitting authority. The 
permitting authority shall disapprove a demonstration period if the 
requirements of paragraph (a) of this section were not met during the 
operating period.
    (ii) If the demonstration period is approved, the permitting 
authority will include, as part of the demonstration period, the 4 
month period prior to submission of the application in the 
demonstration period.
    (iii) The alternative emission limitation demonstration period will 
authorize the unit to emit at a rate not greater than the interim 
alternative emission limitation during the demonstration period on or 
after January 1, 1996 for Phase I units and the applicable date 
established in Secs. 76.5(g) or 76.6 for Phase II units, and until the 
date that the Administrator approves or denies a final alternative 
emission limitation.
    (iv) After an alternative emission limitation demonstration period 
is approved, if the designated representative requests an extension of 
the demonstration period in accordance with paragraph (g)(1)(i)(B) of 
this section, the permitting authority may extend the demonstration 
period by administrative amendment (under Sec. 72.83 of this chapter) 
to the Acid Rain permit.
    (v) The permitting authority shall deny the demonstration period if 
the designated representative cannot demonstrate that the unit met the 
requirements of paragraph (a)(2) of this section. In such cases, the 
permitting authority shall require that the owner or operator operate 
the unit in compliance with the applicable emission limitation in 
Secs. 76.5, 76.6, or 76.7 for the period preceding the submission of 
the application for an alternative emission limitation demonstration 
period, including the operating period, if such periods are after the 
date on which the unit is subject to the standard limit under 
Secs. 76.5, 76.6, or 76.7.
    (2) Alternative emission limitation. (i) If the permitting 
authority determines that the requirements in this section are met, the 
permitting authority will approve an alternative emission limitation 
and issue or revise an Acid Rain permit to apply the approved 
limitation, in accordance with subparts F and G of part 72 of this 
chapter. The permit will authorize the unit to emit at a rate not 
greater than the approved alternative emission limitation, starting the 
date the permitting authority revises an Acid Rain permit to approve an 
alternative emission limitation.
    (ii) If a permitting authority disapproves an alternative emission 
limitation under paragraph (a)(2) of this section, the owner or 
operator shall operate the affected unit in compliance with the 
applicable emission limitation in Secs. 76.5, 76.6, or 76.7 (unless the 
unit is participating in an approved averaging plan under Sec. 76.11) 
beginning on the date the permitting authority revises an Acid Rain 
permit to disapprove an alternative emission limitation.
    (3) Alternative emission limitation renewal. (i) If, upon review of 
a petition to renew an approved alternative emission limitation, the 
permitting authority determines that no changes have been made to the 
control technology, its operation, the operating conditions on which 
the alternative emission limitation was based, or the actual NO<INF>X 
emission rate, the alternative emission limitation will be renewed.
    (ii) If the permitting authority determines that changes have been 
made to the control technology, its operation, the fuel quality, or the 
operating conditions on which the alternative emission limitation was 
based, the designated representative shall submit, in order to renew 
the alternative emission limitation or to obtain a new alternative 
emission limitation, a petition for an alternative emission limitation 
demonstration period that meets the requirements of paragraph (d) of 
this section using a new demonstration period.
    (g) Special provisions.--(1) Alternative emission limitation 
demonstration period. (i) Emission limitations. (A) Each unit with an 
approved alternative emission limitation demonstration period shall 
comply with the interim emission limitation specified in the unit's 
permit beginning on the effective date of the demonstration period 
specified in the permit and, if a timely petition for a final 
alternative emission limitation is submitted, extending until the date 
on which the permitting authority issues or revises an Acid Rain permit 
to approve or disapprove an alternative emission limitation. If a 
timely petition is not submitted, then the unit shall comply with the 
standard emission limit under Secs. 76.5, 76.6, or 76.7 beginning on 
the date the petition was required to be submitted under paragraph 
(c)(2) of this section.
    (B) When the owner or operator identifies, during the demonstration 
period, boiler operating or NO<INF>X emission control system 
modifications or upgrades that would produce further NO<INF>X emission 
reductions, enabling the affected unit to comply with or bring its 
emission rate closer to the applicable emissions limitation under 
Secs. 76.5, 76.6, or 76.7, the designated representative may submit a 
request and the permitting authority may grant, by administrative 
amendment under Sec. 72.83 of this chapter, an extension of the 
demonstration period for such period of time (not to exceed 12 months) 
as may 

[[Page 18768]]
be necessary to implement such modifications or upgrades.
    (C) If the approved interim alternative emission limitation applies 
to a unit for part, but not all, of a calendar year, the unit shall 
determine compliance for the calendar year in accordance with the 
procedures in Sec. 76.13(a).
    (ii) Operating requirements. (A) A unit with an approved 
alternative emission limitation demonstration period shall be operated 
under load dispatch conditions consistent with the operating conditions 
upon which the design of the NO<INF>X emission control system and 
performance guarantee were based, and in accordance with the 
demonstration period plan.
    (B) A unit with an approved alternative emission limitation 
demonstration period shall install all NO<INF>X emission control 
systems, make any operational modifications, and complete any upgrades 
and maintenance to equipment specified in the approved demonstration 
period plan for optimizing NO<INF>X emission reduction performance.
    (C) When the owner or operator identifies boiler or NO<INF>X 
emission control system operating modifications that would produce 
higher NO<INF>X emission reductions, enabling the affected unit to 
comply with, or bring its emission rate closer to, the applicable 
emission limitation under Secs. 76.5, 76.6, or 76.7, the designated 
representative shall submit an administrative amendment under 
Sec. 72.83 of this chapter to revise the unit's Acid Rain permit and 
demonstration period plan to include such modifications.
    (iii) Testing requirements. A unit with an approved alternative 
emission limitation demonstration period shall monitor in accordance 
with part 75 of this chapter and shall conduct all tests required under 
the approved demonstration period plan.
    (2) Final alternative emission limitation.--(i) Emission 
limitations. (A) Each unit with an approved alternative emission 
limitation shall comply with the alternative emission limitation 
specified in the unit's permit beginning on the date specified in the 
permit as issued or revised by the permitting authority to apply the 
final alternative emission limitation.
    (B) If the approved interim or final alternative emission 
limitation applies to a unit for part, but not all, of a calendar year, 
the unit shall determine compliance for the calendar year in accordance 
with the procedures in Sec. 76.13(a).


Sec. 76.11  Emissions averaging.

    (a) General provisions. In lieu of complying with the applicable 
emission limitation in Secs. 76.5, 76.6, or 76.7, any affected units 
subject to such emission limitation, under control of the same owner or 
operator, and having the same designated representative may average 
their NO<INF>X emissions under an averaging plan approved under this 
section.
    (1) Each affected unit included in an averaging plan for Phase I 
shall be a Phase I unit with a Group 1 boiler subject to an emission 
limitation in Sec. 76.5 during all years for which the unit is included 
in the plan.
    (i) If a unit with an approved NO<INF>X compliance extension is 
included in an averaging plan for 1996, the unit shall be treated, for 
the purposes of applying Equation 1 in paragraph (a)(6) of this section 
and Equation 2 in paragraph (d)(1)(ii)(A) of this section, as subject 
to the applicable emissions limitation under Sec. 76.5 for the entire 
year 1996.
    (ii) A Phase II unit approved for early election under Sec. 76.8 
shall not be included in an averaging plan for Phase I.
    (2) Each affected unit included in an averaging plan for Phase II 
shall be a boiler subject to an emission limitation in Secs. 76.5, 
76.6, or 76.7 for all years for which the unit is included in the plan.
    (3) Each unit included in an averaging plan shall have an 
alternative contemporaneous annual emission limitation (lb/mmBtu) and 
can only be included in one averaging plan.
    (4) Each unit included in an averaging plan shall have a minimum 
allowable annual heat input value (mmBtu), if it has an alternative 
contemporaneous annual emission limitation more stringent than that 
unit's applicable emission limitation under Secs. 76.5, 76.6, or 76.7, 
and a maximum allowable annual heat input value, if it has an 
alternative contemporaneous annual emission limitation less stringent 
than that unit's applicable emission limitation under Secs. 76.5, 76.6, 
or 76.7.
    (5) The Btu-weighted annual average emission rate for the units in 
an averaging plan shall be less than or equal to the Btu-weighted 
annual average emission rate for the same units had they each been 
operated, during the same period of time, in compliance with the 
applicable emission limitations in Secs. 76.5, 76.6, or 76.7.
    (6) In order to demonstrate that the proposed plan is consistent 
with paragraph (a)(5) of this section, the alternative contemporaneous 
annual emission limitations and annual heat input values assigned to 
the units in the proposed averaging plan shall meet the following 
requirement:
[GRAPHIC][TIFF OMITTED]TR13AP95.000

Where:

R<INF>Li = Alternative contemporaneous annual emission limitation for 
unit i, lb/mmBtu, as specified in the averaging plan;
R<INF>li = Applicable emission limitation for unit i, lb/mmBtu, as 
specified in Secs. 76.5, 76.6, or 76.7 except that for early election 
units, which may be included in an averaging plan only on or after 
January 1, 2000, R<INF>li shall equal the most stringent applicable 
emission limitation under Secs. 76.5 or 76.7;
HI<INF>i = Annual heat input for unit i, mmBtu, as specified in the 
averaging plan;
n = Number of units in the averaging plan.

    (7) For units with an alternative emission limitation, R<INF>li 
shall equal the applicable emissions limitation under Secs. 76.5, 76.6, 
or 76.7, not the alternative emissions limitation.
    (8) No unit may be included in more than one averaging plan.
    (b)(1) Submission requirements. The designated representative of a 
unit meeting the requirements of paragraphs (a)(1), (a)(2), and (a)(8) 
of this section may submit an averaging plan (or a revision to an 
approved averaging plan) to the permitting authority(ies) at any time 
up to and including January 1 (or July 1, if the plan is restricted to 
units located within a single permitting authority's jurisdiction) of 
the calendar 

[[Page 18769]]
year for which the averaging plan is to become effective.
    (2) The designated representative shall submit a copy of the same 
averaging plan (or the same revision to an approved averaging plan) to 
each permitting authority with jurisdiction over a unit in the plan.
    (3) When an averaging plan (or a revision to an approved averaging 
plan) is not approved, the owner or operator of each unit in the plan 
shall operate the unit in compliance with the emission limitation that 
would apply in the absence of the averaging plan (or revision to a 
plan).
    (c) Contents of NO<INF>X averaging plan. A complete NO<INF>X 
averaging plan shall include the following elements in a format 
prescribed by the Administrator:
    (1) Identification of each unit in the plan;
    (2) Each unit's applicable emission limitation in Secs. 76.5, 76.6, 
or 76.7;
    (3) The alternative contemporaneous annual emission limitation for 
each unit (in lb/mmBtu). If any of the units identified in the NO<INF>X 
averaging plan utilize a common stack pursuant to 
Sec. 75.17(a)(2)(i)(B) of this chapter, the same alternative 
contemporaneous emission limitation shall be assigned to each such unit 
and different heat input limits may be assigned;
    (4) The annual heat input limit for each unit (in mmBtu);
    (5) The calculation for Equation 1 in paragraph (a)(6) of this 
section;
    (6) The calendar years for which the plan will be in effect; and
    (7) The special provisions in paragraph (d)(1) of this section.
    (d) Special provisions.--(1) Emission limitations. Each affected 
unit in an approved averaging plan is in compliance with the Acid Rain 
emission limitation for NO<INF>X under the plan only if the following 
requirements are met:
    (i) For each unit, the unit's actual annual average emission rate 
for the calendar year, in lb/mmBtu, is less than or equal to its 
alternative contemporaneous annual emission limitation in the averaging 
plan; and
    (A) For each unit with an alternative contemporaneous emission 
limitation less stringent than the applicable emission limitation in 
Secs. 76.5, 76.6, or 76.7, the actual annual heat input for the 
calendar year does not exceed the annual heat input limit in the 
averaging plan;
    (B) For each unit with an alternative contemporaneous annual 
emission limitation more stringent than the applicable emission 
limitation in Secs. 76.5, 76.6, or 76.7, the actual annual heat input 
for the calendar year is not less than the annual heat input limit in 
the averaging plan; or
    (ii) If one or more of the units does not meet the requirements 
under paragraph (d)(1)(i) of this section, the designated 
representative shall demonstrate, in accordance with paragraph 
(d)(1)(ii)(A) of this section (Equation 2) that the actual Btu-weighted 
annual average emission rate for the units in the plan is less than or 
equal to the Btu-weighted annual average rate for the same units had 
they each been operated, during the same period of time, in compliance 
with the applicable emission limitations in Secs. 76.5, 76.6, or 76.7.
    (A) A group showing of compliance shall be made based on the 
following equation:
[GRAPHIC][TIFF OMITTED]TR13AP95.001

Where:

R<INF>ai = Actual annual average emission rate for unit i, lb/mmBtu, as 
determined using the procedures in part 75 of this chapter. For units 
in an averaging plan utilizing a common stack pursuant to 
Sec. 75.17(a)(2)(i)(B) of this chapter, use the same NO<INF>X emission 
rate value for each unit utilizing the common stack, and calculate this 
value in accordance with appendix F to part 75 of this chapter;
R<INF>li = Applicable annual emission limitation for unit i lb/mmBtu, 
as specified in Secs. 76.5, 76.6, or 76.7, except that for early 
election units, which may be included in an averaging plan only on or 
after January 1, 2000, R<INF>li shall equal the most stringent 
applicable emission limitation under Secs. 76.5 or 76.7;
HI<INF>ai = Actual annual heat input for unit i, mmBtu, as determined 
using the procedures in part 75 of this chapter;
n = Number of units in the averaging plan.

    (B) For units with an alternative emission limitation, R<INF>li 
shall equal the applicable emission limitation under Secs. 76.5, 76.6, 
or 76.7, not the alternative emission limitation.
    (C) If there is a successful group showing of compliance under 
paragraph (d)(1)(ii)(A) of this section for a calendar year, then all 
units in the averaging plan shall be deemed to be in compliance for 
that year with their alternative contemporaneous emission limitations 
and annual heat input limits under paragraph (d)(1)(i) of this section.
    (2) Liability. The owners and operators of a unit governed by an 
approved averaging plan shall be liable for any violation of the plan 
or this section at that unit or any other unit in the plan, including 
liability for fulfilling the obligations specified in part 77 of this 
chapter and sections 113 and 411 of the Act.
    (3) Withdrawal or termination. The designated representative may 
submit a notification to terminate an approved averaging plan in 
accordance with Sec. 72.40(d) of this chapter, no later than October 1 
of the calendar year for which the plan is to be withdrawn or 
terminated.


Sec. 76.12  Phase I NO<INF>X compliance extension.

    (a) General provisions. (1) The designated representative of a 
Phase I unit with a Group 1 boiler may apply for and receive a 15-month 
extension of the deadline for meeting the applicable emissions 
limitation under Sec. 76.5 where it is demonstrated, to the 
satisfaction of the Administrator, that:
    (i) The low NO<INF>X burner technology designed to meet the 
applicable emission limitation is not in adequate supply to enable 
installation and operation at the unit, consistent with system 
reliability, by January 1, 1995 and the reliability problems are due 
substantially to NO<INF>X emission control system installation and 
availability; or
    (ii) The unit is participating in an approved clean coal technology 
demonstration project.
    (2) In order to obtain a Phase I NO<INF>X compliance extension, the 
designated representative shall submit a Phase I 

[[Page 18770]]
NO<INF>X compliance extension plan by October 1, 1994.
    (b) Contents of Phase I NO<INF>X compliance extension plan. A 
complete Phase I NO<INF>X compliance extension plan shall include the 
following elements in a format prescribed by the Administrator:
    (1) Identification of the unit.
    (2) For units applying pursuant to paragraph (a)(1)(i) of this 
section:
    (i) A list of the company names, addresses, and telephone numbers 
of vendors who are qualified to provide the services and low NO<INF>X 
burner technology designed to meet the applicable emission limitation 
under Sec. 76.5 and have been contacted to obtain the required services 
and technology. The list shall include the dates of contact, and a copy 
of each request for bids shall be submitted, along with any other 
information necessary to show a good-faith effort to obtain the 
required services and technology necessary to meet the requirements of 
this part on or before January 1, 1995.
    (ii) A copy of those portions of a legally binding contract with a 
qualified vendor that demonstrate that services and low NO<INF>X burner 
technology designed to meet the applicable emission limitation under 
Sec. 76.5, with a completion date not later than December 31, 1995 have 
been contracted for.
    (iii) Scheduling information, including justification and test 
schedules.
    (iv) To demonstrate, if applicable, that the supply of the low 
NO<INF>X burner technology designed to meet the applicable emission 
limitation under Sec. 76.5 is inadequate to enable its installation and 
operation at the unit, consistent with system reliability, in time for 
the unit to comply with the applicable emission limitation on or before 
January 1, 1995, either:
    (A) Certification from the selected vendor(s) (by a certifying 
official) listed in paragraph (b)(2)(i) of this section stating that 
they cannot provide the necessary services and install the low NO<INF>X 
burner technology on or before January 1, 1995 and explaining the 
reasons why the services cannot be provided and why the equipment 
cannot be installed in a timely manner; or
    (B) The following information:
    (i) Standard load forecasts, based on standard forecasting models 
available throughout the utility industry and applied to the period, 
January 1, 1993, through December 31, 1994.
    (ii) Specific reasons why an outage cannot be scheduled to enable 
the unit to install and operate the low NO<INF>X burner technology by 
January 1, 1995, including reasons why no other units can be used to 
replace this unit's generation during such outage.
    (iii) Fuel and energy balance summaries and power and other 
consumption requirements (including those for air, steam, and cooling 
water).
    (3) To demonstrate, if applicable, participation in an approved 
clean coal technology demonstration project, a description of the 
project, including all sources of federal, State, and other outside 
funding, amount and date for approval of federal funding, the duration 
of the project, and the anticipated completion date of the project.
    (4) The special provisions in paragraph (d) of this section.
    (c) (1) Administrator's action. To the extent the Administrator 
determines that a Phase I NO<INF>X compliance extension plan complies 
with the requirements of this section, the Administrator will approve 
the plan and revise the Acid Rain permit governing the unit in the plan 
in order to incorporate the plan by administrative amendment under 
Sec. 72.83 of this chapter, except that the Administrator shall have 90 
days from receipt of the compliance extension plan to take final 
action.
    (2) The Administrator will approve or disapprove a proposed 
NO<INF>X compliance extension plan within 3 months of receipt.
    (d) Special provisions.
    (1) Emission limitations. The unit shall comply with the applicable 
emission limitation under Sec. 76.5 beginning April 1, 1996. Compliance 
shall be determined as specified in part 75 of this chapter using 
measured values of NO<INF>X emissions and heat input only for the 
portion of the year that the emission limit is in effect.
    (2) If a unit with an approved NO<INF>X compliance extension is 
included in an averaging plan under Sec. 76.11 for year 1996, the unit 
shall be treated, for purposes of applying Equation 1 in 
Sec. 76.11(a)(6) and Equation 2 in Sec. 76.11(d)(1)(ii)(A), as subject 
to the applicable emission limitation under Sec. 76.5 for the entire 
year 1996.
    (e) Extension until December 31, 1997. (1) The designated 
representative of a Phase I unit that is subject to section 404(d) of 
the Act, has a tangentially fired boiler, and is unable to install low 
NO<INF>X burner technology by January 1, 1997 may submit a petition for 
and receive an extension for meeting the applicable emission limitation 
under Sec. 76.5 where it is demonstrated, to the satisfaction of the 
Administrator, that:
    (i) The unit is located at a source with two or more other units, 
all of which are Phase I units that are subject to section 404(d) of 
the Act and have tangentially fired boilers;
    (ii) The NO<INF>X control system at the unit was scheduled to be 
installed by January 1, 1997 and, because of operational problems 
associated with the NO<INF>X control system, will be redesigned; and
    (iii) Installation of the redesigned low NO<INF>X burner technology 
at the unit cannot be completed by January 1, 1997 without causing 
system reliability problems.
    (2) A complete petition shall include the following elements and 
shall be submitted by April 28, 1995.
    (i) Identification of the unit and the other units at the source;
    (ii) A statement describing how the requirements of paragraphs 
(e)(1)(ii) and (e)(1)(iii) of this section are met;
    (iii) The earliest date, not later than December 31, 1997, by which 
installation of the redesigned low NO<INF>X burner technology can be 
completed consistent with system reliability; and
    (iv) The provisions in paragraph (e)(4) of this section.
    (3) To the extent the Administrator determines that a Phase I unit 
meets the requirements of paragraphs (e)(1) and (e)(2) of this section, 
the Administrator will approve the petition within 90 days from receipt 
of the complete petition. The Acid Rain permit governing the unit will 
be revised in order to incorporate the approved extension, which shall 
terminate no later than December 31, 1997, by administrative amendment 
under Sec. 72.83 of this chapter except that the Administrator will 
have 90 days to take final action.
    (4) The unit shall comply with the applicable emission limitation 
under Sec. 76.5 beginning on the day immediately following the day on 
which the extension approved under paragraph (e)(3) of this section 
terminates. Compliance shall be determined as specified in part 75 of 
this chapter using measured values of NO<INF>X emissions and heat input 
only for the portion of the year that the emission limit is in effect. 
If a unit with an approved extension is included in an averaging plan 
under Sec. 76.11 for year 1997, the unit shall be treated, for the 
purpose of applying Equation 1 in Sec. 76.11(a)(6) and Equation 2 in 
Sec. 76.11(d)(1)(ii)(A), as subject to the applicable emission 
limitation under Sec. 76.5 for the entire year 1997.


Sec. 76.13  Compliance and excess emissions.

    Excess emissions of nitrogen oxides under Sec. 77.6 of this chapter 
shall be calculated as follows: 

[[Page 18771]]

    (a) For a unit that is not in an approved averaging plan:
    (1) Calculate EE<INF>i for each portion of the calendar year that 
the unit is subject to a different NO<INF>X emission limitation:
[GRAPHIC][TIFF OMITTED]TR13AP95.002

Where:

EE<INF>i = Excess emissions for NO<INF>X for the portion of the 
calendar year (in tons);
R<INF>ai = Actual average emission rate for the unit (in lb/mmBtu), 
determined according to part 75 of this chapter for the portion of the 
calendar year for which the applicable emission limitation R<INF>l is 
in effect;
R<INF>li = Applicable emission limitation for the unit, (in lb/mmBtu), 
as specified in Secs. 76.5, 76.6, or 76.7 or as determined under 
Sec. 76.10;
[GRAPHIC][TIFF OMITTED]TR13AP95.003

HI<SUP>i = Actual heat input for the unit, (in mmBtu), determined 
according to part 75 of this chapter for the portion of the calendar 
year for which the applicable emission limitation, R<INF>l, is in 
effect.

    (2) If EE<INF>i is a negative number for any portion of the 
calendar year, the EE value for that portion of the calendar year shall 
be equal to zero (e.g., if EE<INF>i = -100, then EE<INF>i = 0).
    (3) Sum all EE<INF>i values for the calendar year:
Where:

EE = Excess emissions for NO<INF>X for the year (in tons);
n = The number of time periods during which a unit is subject to 
different emission limitations; and

    (b) For units participating in an approved averaging plan, when all 
the requirements under Sec. 76.11(d)(1) are not met,
[GRAPHIC][TIFF OMITTED]TR13AP95.004

Where:

EE = Excess emissions for NO<INF>X for the year (in tons);
R<INF>ai = Actual annual average emission rate for NO<INF>X for unit i, 
(in lb/mmBtu), determined according to part 75 of this chapter;
R<INF>li = Applicable emission limitation for unit i, (in lb/mmBtu), as 
specified in Secs. 76.5, 76.6, or 76.7;
HI<INF>i = Actual annual heat input for unit i, mmBtu, determined 
according to part 75 of this chapter;
n = Number of units in the averaging plan.


Sec. 76.14  Monitoring, recordkeeping, and reporting.

    (a) A petition for an alternative emission limitation demonstration 
period under Sec. 76.10(d) shall include the following information:
    (1) In accordance with Sec. 76.10(d)(4), the following information:
    (i) Documentation that the owner or operator solicited bids for a 
NO<INF>X emission control system designed for application to the 
specific boiler and designed to achieve the applicable emission 
limitation in Secs. 76.5, 76.6, or 76.7 on an annual average basis. 
This documentation must include a copy of all bid specifications.
    (ii) A copy of the performance guarantee submitted by the vendor of 
the installed NO<INF>X emission control system to the owner or operator 
showing that such system was designed to meet the applicable emission 
limitation in Secs. 76.5, 76.6, or 76.7 on an annual average basis.
    (iii) Documentation describing the operational and combustion 
conditions that are the basis of the performance guarantee.
    (iv) Certification by the primary vendor of the NO<INF>X emission 
control system that such equipment and associated auxiliary equipment 
was properly installed according to the modifications and procedures 
specified by the vendor.
    (v) Certification by the designated representative that the 
owner(s) or operator installed technology that meets the requirements 
of Sec. 76.10(a)(2).
    (2) In accordance with Sec. 76.10(d)(9), the following information:
    (i) The operating conditions of the NO<INF>X emission control 
system including load range, O<INF>2 range, coal volatile matter range, 
and, for tangentially fired boilers, distribution of combustion air 
within the NO<INF>X emission control system;
    (ii) Certification by the designated representative that the 
owner(s) or operator have achieved and are following the operating 
conditions, boiler modifications, and upgrades that formed the basis 
for the system design and performance guarantee;
    (iii) Any planned equipment modifications and upgrades for the 
purpose of achieving the maximum NO<INF>X reduction performance of the 
NO<INF>X emission control system that were not included in the design 
specifications and performance guarantee, but that were achieved prior 
to submission of this application and are being followed;
    (iv) A list of any modifications or replacements of equipment that 
are to be done prior to the completion of the demonstration period for 
the purpose of reducing emissions of NO<INF>X; and
    (v) The parametric testing that will be conducted to determine the 
reason or reasons for the failure of the unit to achieve the applicable 
emission limitation and to verify the proper operation of the installed 
NO<INF>X emission control system during the demonstration period. The 
tests shall include tests in Sec. 76.15, which may be modified as 
follows:
    (A) The owner or operator of the unit may add tests to those listed 
in Sec. 76.15, if such additions provide data relevant to the failure 
of the installed NO<INF>X emission control system to meet the 
applicable emissions limitation in Secs. 76.5, 76.6, or 76.7; or
    (B) The owner or operator of the unit may remove tests listed in 
Sec. 76.15 that are shown, to the satisfaction of the permitting 
authority, not to be relevant to NO<INF>X emissions from the affected 
unit; and
    (C) In the event the performance guarantee or the NO<INF>X emission 
control system specifications require additional tests not listed in 
Sec. 76.15, or specify operating conditions not verified by tests 
listed in Sec. 76.15, the owner or operator of the unit shall include 
such additional tests.
    (3) In accordance with Sec. 76.10(d)(10), the following information 
for the operating period:
    (i) The average NO<INF>X emission rate (in lb/mmBtu) of the 
specific unit;
    (ii) The highest hourly NO<INF>X emission rate (in lb/mmBtu) of the 
specific unit;
    (iii) Hourly NO<INF>X emission rate (in lb/mmBtu), calculated in 
accordance with part 75 of this chapter;
    (iv) Total heat input (in mmBtu) for the unit for each hour of 
operation, 

[[Page 18772]]
calculated in accordance with the requirements of part 75 of this 
chapter; and
    (v) Total integrated hourly gross unit load (in MWge).
    (b) A petition for an alternative emission limitation shall include 
the following information in accordance with Sec. 76.10(e)(6).
    (1) Total heat input (in mmBtu) for the unit for each hour of 
operation, calculated in accordance with the requirements of part 75 of 
this chapter;
    (2) Hourly NO<INF>X emission rate (in lb/mmBtu), calculated in 
accordance with the requirements of part 75 of this chapter; and
    (3) Total integrated hourly gross unit load (MWge).
    (c) Reporting of the costs of low NO<INF>X burner technology 
applied to Group 1, Phase I boilers. (1) Except as provided in 
paragraph (c)(2) of this section, the designated representative of a 
Phase I unit with a Group 1 boiler that has installed or is installing 
any form of low NO<INF>X burner technology shall submit to the 
Administrator a report containing the capital cost, operating cost, and 
baseline and post-retrofit emission data specified in appendix B to 
this part. If any of the required equipment, cost, and schedule 
information are not available (e.g., the retrofit project is still 
underway), the designated representative shall include in the report 
detailed cost estimates and other projected or estimated data in lieu 
of the information that is not available.
    (2) The report under paragraph (c)(1) of this section is not 
required with regard to the following types of Group 1, Phase I units:
    (i) Units employing no new NO<INF>X emission control system after 
November 15, 1990;
    (ii) Units employing modifications to boiler operating parameters 
(e.g., burners out of service or fuel switching) without low NO<INF>X 
burners or other emission reduction equipment for reducing NO<INF>X 
emissions;
    (iii) Units with wall-fired boilers employing only overfire air and 
units with tangentially fired boilers employing only separated overfire 
air; or
    (iv) Units beginning installation of a new NO<INF>X emission 
control system after August 11, 1995.
    (3) The report under paragraph (c)(1) of this section shall be 
submitted to the Administrator by:
    (i) 120 days after completion of the low NO<INF>X burner technology 
retrofit project; or
    (ii) May 23, 1995, if the project was completed on or before 
January 23, 1995.


Sec. 76.15  Test methods and procedures.

    (a) The owner or operator may use the following tests as a basis 
for the report required by Sec. 76.10(e)(7):
    (1) Conduct an ultimate analysis of coal using ASTM D 3176-89 
(incorporated by reference as specified in Sec. 76.4);
    (2) Conduct a proximate analysis of coal using ASTM D 3172-89 
(incorporated by reference as specified in Sec. 76.4); and
    (3) Measure the coal mass flow rate to each individual burner using 
ASME Power Test Code 4.2 (1991), ``Test Code for Coal Pulverizers'' or 
ISO 9931 (1991), ``Coal--Sampling of Pulverized Coal Conveyed by Gases 
in Direct Fired Coal Systems'' (incorporated by reference as specified 
in Sec. 76.4).
    (b) The owner or operator may measure and record the actual 
NO<INF>X emission rate in accordance with the requirements of this part 
while varying the following parameters where possible to determine 
their effects on the emissions of NO<INF>X from the affected boiler:
    (1) Excess air levels;
    (2) Settings of burners or coal and air nozzles, including tilt and 
yaw, or swirl;
    (3) For tangentially fired boilers, distribution of combustion air 
within the NO<INF>X emission control system;
    (4) Coal mass flow rates to each individual burner;
    (5) Coal-to-primary air ratio (based on pound per hour) for each 
burner, the average coal-to-primary air ratio for all burners, and the 
deviations of individual burners' coal-to-primary air ratios from the 
average value; and
    (6) If the boiler uses varying types of coal, the type of coal. 
Provide the results of proximate and ultimate analyses of each type of 
as-fired coal.
    (c) In performing the tests specified in paragraph (a) of this 
section, the owner or operator shall begin the tests using the 
equipment settings for which the NO<INF>X emission control system was 
designed to meet the NO<INF>X emission rate guaranteed by the primary 
NO<INF>X emission control system vendor. These results constitute the 
``baseline controlled'' condition.
    (d) After establishing the baseline controlled condition under 
paragraph (c) of this section, the owner or operator may:
    (1) Change excess air levels <plus-minus> 5 percent from the 
baseline controlled condition to determine the effects on emissions of 
NO<INF>X, by providing a minimum of three readings (e.g., with a 
baseline reading of 20 percent excess air, excess air levels will be 
changed to 19 percent and 21 percent);
    (2) For tangentially fired boilers, change the distribution of 
combustion air within the NO<INF>X emission control system to determine 
the effects on NO<INF>X emissions by providing a minimum of three 
readings, one with the minimum, one with the baseline, and one with the 
maximum amounts of staged combustion air; and
    (3) Show that the combustion process within the boiler is optimized 
(e.g., that the burners are balanced).


Sec. 76.16  [Reserved]
Appendix A to Part 76--Phase I Affected Coal-Fired Utility Units With 
Group 1 or Cell Burner Boilers

                                   Table 1.--Phase I Tangentially Fired Units                                   
----------------------------------------------------------------------------------------------------------------
             State                          Plant                 Unit                    Operator              
----------------------------------------------------------------------------------------------------------------
ALABAMA.......................  EC GASTON...................  5             ALABAMA POWER CO.                   
GEORGIA.......................  BOWEN.......................  1BLR          GEORGIA POWER CO.                   
GEORGIA.......................  BOWEN.......................  2BLR          GEORGIA POWER CO.                   
GEORGIA.......................  BOWEN.......................  3BLR          GEORGIA POWER CO.                   
GEORGIA.......................  BOWEN.......................  4BLR          GEORGIA POWER CO.                   
GEORGIA.......................  JACK MCDONOUGH..............  MB1           GEORGIA POWER CO.                   
GEORGIA.......................  JACK MCDONOUGH..............  MB2           GEORGIA POWER CO.                   
GEORGIA.......................  WANSLEY.....................  1             GEORGIA POWER CO.                   
GEORGIA.......................  WANSLEY.....................  2             GEORGIA POWER CO.                   
GEORGIA.......................  YATES.......................  Y1BR          GEORGIA POWER CO.                   
GEORGIA.......................  YATES.......................  Y2BR          GEORGIA POWER CO.                   
GEORGIA.......................  YATES.......................  Y3BR          GEORGIA POWER CO.                   
GEORGIA.......................  YATES.......................  Y4BR          GEORGIA POWER CO.                   
GEORGIA.......................  YATES.......................  Y5BR          GEORGIA POWER CO.                   

[[Page 18773]]
                                                                                                                
GEORGIA.......................  YATES.......................  Y6BR          GEORGIA POWER CO.                   
GEORGIA.......................  YATES.......................  Y7BR          GEORGIA POWER CO.                   
ILLINOIS......................  BALDWIN.....................  3             ILLINOIS POWER CO.                  
ILLINOIS......................  HENNEPIN....................  2             ILLINOIS POWER CO.                  
ILLINOIS......................  JOPPA.......................  1             ELECTRIC ENERGY INC.                
ILLINOIS......................  JOPPA.......................  2             ELECTRIC ENERGY INC.                
ILLINOIS......................  JOPPA.......................  3             ELECTRIC ENERGY INC.                
ILLINOIS......................  JOPPA.......................  4             ELECTRIC ENERGY INC.                
ILLINOIS......................  JOPPA.......................  5             ELECTRIC ENERGY INC.                
ILLINOIS......................  JOPPA.......................  6             ELECTRIC ENERGY INC.                
ILLINOIS......................  MEREDOSIA...................  5             CEN ILLINOIS PUB SER.               
ILLINOIS......................  VERMILION...................  2             ILLINOIS POWER CO.                  
INDIANA.......................  CAYUGA......................  1             PSI ENERGY INC.                     
INDIANA.......................  CAYUGA......................  2             PSI ENERGY INC.                     
INDIANA.......................  EW STOUT....................  50            INDIANAPOLIS PWR & LT.              
INDIANA.......................  EW STOUT....................  60            INDIANAPOLIS PWR & LT.              
INDIANA.......................  EW STOUT....................  70            INDIANAPOLIS PRW & LT.              
INDIANA.......................  HT PRITCHARD................  6             INDIANAPOLIS PWR & LT.              
INDIANA.......................  PETERSBURG..................  1             INDIANAPOLIS PWR & LT.              
INDIANA.......................  PETERSBURG..................  2             INDIANAPOLIS PWR & LT.              
INDIANA.......................  WABASH RIVER................  6             PSI ENERGY INC.                     
IOWA..........................  BURLINGTON..................  1             IOWA SOUTHERN UTL.                  
IOWA..........................  ML KAPP.....................  2             INTERSTATE POWER CO.                
IOWA..........................  RIVERSIDE...................  9             IOWA-ILL GAS & ELEC.                
KENTUCKY......................  ELMER SMITH.................  2             OWENSBORO MUN UTIL.                 
KENTUCKY......................  EW BROWN....................  2             KENTUCKY UTL CO.                    
KENTUCKY......................  EW BROWN....................  3             KENTUCKY UTL CO.                    
KENTUCKY......................  GHENT.......................  1             KENTUCKY UTL CO.                    
MARYLAND......................  MORGANTOWN..................  1             POTOMAC ELEC PWR CO.                
MARYLAND......................  MORGANTOWN..................  2             POTOMAC ELEC PWR CO.                
MICHIGAN......................  JH CAMPBELL.................  1             CONSUMERS POWER CO.                 
MISSOURI......................  LABADIE.....................  1             UNION ELECTRIC CO.                  
MISSOURI......................  LABADIE.....................  2             UNION ELECTRIC CO.                  
MISSOURI......................  LABADIE.....................  3             UNION ELECTRIC CO.                  
MISSOURI......................  LABADIE.....................  4              UNION ELECTRIC CO.                 
MISSOURI......................  MONTROSE....................  1             KANSAS CITY PWR & LT.               
MISSOURI......................  MONTROSE....................  2             KANSAS CITY PWR & LT.               
MISSOURI......................  MONTROSE....................  3             KANSAS CITY PWR & LT.               
NEW YORK......................  DUNKIRK.....................  3             NIAGARA MOHAWK PWR.                 
NEW YORK......................  DUNKIRK.....................  4             NIAGARA MOHAWK PWR.                 
NEW YORK......................  GREENIDGE...................  6             NY STATE ELEC & GAS.                
NEW YORK......................  MILLIKEN....................  1             NY STATE ELEC & GAS.                
NEW YORK......................  MILLIKEN....................  2             NY STATE ELEC & GAS.                
OHIO..........................  ASHTABULA...................  7             CLEVELAND ELEC ILLUM.               
OHIO..........................  AVON LAKE...................  11            CLEVELAND ELEC ILLUM.               
OHIO..........................  CONESVILLE..................  4             COLUMBUS STHERN PWR.                
OHIO..........................  EASTLAKE....................  1             CLEVELAND ELEC ILLUM.               
OHIO..........................  EASTLAKE....................  2             CLEVELAND ELEC ILLUM.               
OHIO..........................  EASTLAKE....................  3             CLEVELAND ELEC ILLUM.               
OHIO..........................  EASTLAKE....................  4             CLEVELAND ELEC ILLUM.               
OHIO..........................  MIAMI FORT..................  6             CINCINNATI GAS & ELEC.              
OHIO..........................  WC BECKJORD.................  5             CINCINNATI GAS & ELEC.              
OHIO..........................  WC BECKJORD.................  6             CINCINNATI GAS & ELEC.              
PENNSYLVANIA..................  BRUNNER ISLAND..............  1             PENNSYLVANIA PWR & LT.              
PENNSYLVANIA..................  BRUNNER ISLAND..............  2             PENNSYLVANIA PWR & LT.              
PENNSYLVANIA..................  BRUNNER ISLAND..............  3             PENNSYLVANIA PWR & LT.              
PENNSYLVANIA..................  CHESWICK....................  1             DUQUESNE LIGHT CO.                  
PENNSYLVANIA..................  CONEMAUGH...................  1             PENNSYLVANIA ELEC CO.               
PENNSYLVANIA..................  CONEMAUGH...................  2             PENNSYLVANIA ELEC CO.               
PENNSYLVANIA..................  PORTLAND....................  1             METROPOLITAN EDISON.                
PENNSYLVANIA..................  PORTLAND....................  2             METROPOLITAN EDISON.                
PENNSYLVANIA..................  SHAWVILLE...................  3             PENNSYLVANIA ELEC CO.               
PENNSYLVANIA..................  SHAWVILLE...................  4             PENNSYLVANIA ELEC CO.               
TENNESSEE.....................  GALLATIN....................  1             TENNESSEE VAL AUTH.                 
TENNESSEE.....................  GALLATIN....................  2             TENNESSEE VAL AUTH.                 
TENNESSEE.....................  GALLATIN....................  3             TENNESSEE VAL AUTH.                 
TENNESSEE.....................  GALLATIN....................  4             TENNESSEE VAL AUTH.                 
TENNESSEE.....................  JOHNSONVILLE................  1             TENNESSEE VAL AUTH.                 
TENNESSEE.....................  JOHNSONVILLE................  2             TENNESSEE VAL AUTH.                 
TENNESSEE.....................  JOHNSONVILLE................  3             TENNESSEE VAL AUTH.                 
TENNESSEE.....................  JOHNSONVILLE................  4             TENNESSEE VAL AUTH.                 
TENNESSEE.....................  JOHNSONVILLE................  5             TENNESSEE VAL AUTH.                 

[[Page 18774]]
                                                                                                                
TENNESSEE.....................  JOHNSONVILLE................  6             TENNESSEE VAL AUTH.                 
WEST VIRGINIA.................  ALBRIGHT....................  3             MONONGAHELA POWER CO.               
WEST VIRGINIA.................  FORT MARTIN.................  1             MONONGAHELA POWER CO.               
WEST VIRGINIA.................  MOUNT STORM.................  1             VIRGINIA ELEC & PWR.                
WEST VIRGINIA.................  MOUNT STORM.................  2             VIRGINIA ELEC & PWR.                
WEST VIRGINIA.................  MOUNT STORM.................  3             VIRGINIA ELEC & PWR.                
WISCONSIN.....................  GENOA.......................  1             DAIRYLAND POWER COOP.               
WISCONSIN.....................  SOUTH OAK CREEK.............  7             WISCONSIN ELEC POWER.               
WISCONSIN.....................  SOUTH OAK CREEK.............  8             WISCONSIN ELEC POWER.               
----------------------------------------------------------------------------------------------------------------



                                    Table 2.--Phase I Dry Bottom-Fired Units                                    
----------------------------------------------------------------------------------------------------------------
                State                             Plant                 Unit                 Operator           
----------------------------------------------------------------------------------------------------------------
ALABAMA.............................  COLBERT.....................  1             TENNESSEE VAL AUTH.           
ALABAMA.............................  COLBERT.....................  2             TENNESSEE VAL AUTH.           
ALABAMA.............................  COLBERT.....................  3             TENNESSEE VAL AUTH.           
ALABAMA.............................  COLBERT.....................  4             TENNESSEE VAL AUTH.           
ALABAMA.............................  COLBERT.....................  5             TENNESSEE VAL AUTH.           
ALABAMA.............................  EC GASTON...................  1             ALABAMA POWER CO.             
ALABAMA.............................  EC GASTON...................  2             ALABAMA POWER CO.             
ALABAMA.............................  EC GASTON...................  3             ALABAMA POWER CO.             
ALABAMA.............................  EC GASTON...................  4             ALABAMA POWER CO.             
                                                                                                                
FLORIDA.............................  CRIST.......................  6             GULF POWER CO.                
FLORIDA.............................  CRIST.......................  7             GULF POWER CO.                
                                                                                                                
GEORGIA.............................  HAMMOND.....................  1             GEORGIA POWER CO.             
GEORGIA.............................  HAMMOND.....................  2             GEORGIA POWER CO.             
GEORGIA.............................  HAMMOND.....................  3             GEORGIA POWER CO.             
GEORGIA.............................  HAMMOND.....................  4             GEORGIA POWER CO.             
                                                                                                                
ILLINOIS............................  GRAND TOWER.................  9             CEN ILLINOIS PUB SER.         
                                                                                                                
INDIANA.............................  CULLEY......................  2             STHERN IND GAS & EL.          
INDIANA.............................  CULLEY......................  3             STHERN IND GAS & EL.          
INDIANA.............................  GIBSON......................  1             PSI ENERGY INC.               
INDIANA.............................  GIBSON......................  2             PSI ENERGY INC.               
INDIANA.............................  GIBSON......................  3             PSI ENERGY INC.               
INDIANA.............................  GIBSON......................  4             PSI ENERGY INC.               
INDIANA.............................  RA GALLAGHER................  1             PSI ENERGY INC.               
INDIANA.............................  RA GALLAGHER................  2             PSI ENERGY INC.               
INDIANA.............................  RA GALLAGHER................  3             PSI ENERGY INC.               
INDIANA.............................  RA GALLAGHER................  4             PSI ENERGY INC.               
INDIANA.............................  FRANK E RATTS...............  1SG1          HOOSIER ENERGY REC.           
INDIANA.............................  FRANK E RATTS...............  2SG1          HOOSIER ENERGY REC.           
INDIANA.............................  WABASH RIVER................  1             PSI ENERGY INC.               
INDIANA.............................  WABASH RIVER................  2             PSI ENERGY INC.               
INDIANA.............................  WABASH RIVER................  3             PSI ENERGY INC.               
INDIANA.............................  WABASH RIVER................  5             PSI ENERGY INC.               
                                                                                                                
IOWA................................  DES MOINES..................  11            IOWA PWR & LT CO.             
IOWA................................  PRAIRIE CREEK...............  4             IOWA ELEC LT & PWR.           
                                                                                                                
KANSAS..............................  QUINDARO....................  2             KS CITY BD PUB UTIL.          
                                                                                                                
KENTUCKY............................  COLEMAN.....................  C1            BIG RIVERS ELEC CORP.         
KENTUCKY............................  COLEMAN.....................  C2            BIG RIVERS ELEC CORP.         
KENTUCKY............................  COLEMAN.....................  C3            BIG RIVERS ELEC CORP.         
KENTUCKY............................  EW BROWN....................  1             KENTUCKY UTL CO.              
KENTUCKY............................  GREEN RIVER.................  5             KENTUCKY UTL CO.              
KENTUCKY............................  HMP&L STATION 2.............  H1            BIG RIVERS ELEC CORP.         
KENTUCKY............................  HMP&L STATION 2.............  H2            BIG RIVERS ELEC CORP.         
KENTUCKY............................  HL SPURLOCK.................  1             EAST KY PWR COOP.             
KENTUCKY............................  JS COOPER...................  1             EAST KY PWR COOP.             
KENTUCKY............................  JS COOPER...................  2             EAST KY PWR COOP.             
                                                                                                                
MARYLAND............................  CHALK POINT.................  1             POTOMAC ELEC PWR CO.          

[[Page 18775]]
                                                                                                                
MARYLAND............................  CHALK POINT.................  2             POTOMAC ELEC PWR CO.          
                                                                                                                
MINNESOTA...........................  HIGH BRIDGE.................  6             NORTHERN STATES PWR.          
                                                                                                                
MISSISSIPPI.........................  JACK WATSON.................  4             MISSISSIPPI PWR CO.           
MISSISSIPPI.........................  JACK WATSON.................  5             MISSISSIPPI PWR CO.           
                                                                                                                
MISSOURI............................  JAMES RIVER.................  5             SPRINGFIELD UTL.              
                                                                                                                
OHIO................................  CONESVILLE..................  3             COLUMBUS STHERN PWR.          
OHIO................................  EDGEWATER...................  13            OHIO EDISON CO.               
OHIO................................  MIAMI FORT\1\...............  5-1           CINCINNATI GAS&ELEC.          
OHIO................................  MIAMI FORT\1\...............  5-2           CINCINNATI GAS&ELEC.          
OHIO................................  PICWAY......................  9             COLUMBUS STHERN PWR.          
OHIO................................  RE BURGER...................  7             OHIO EDISON CO.               
OHIO................................  RE BURGER...................  8             OHIO EDISON CO.               
OHIO................................  WH SAMMIS...................  5             OHIO EDISON CO.               
OHIO................................  WH SAMMIS...................  6             OHIO EDISON CO.               
                                                                                                                
PENNSYLVANIA........................  ARMSTRONG...................  1             WEST PENN POWER CO.           
PENNSYLVANIA........................  ARMSTRONG...................  2             WEST PENN POWER CO.           
PENNSYLVANIA........................  MARTINS CREEK...............  1             PENNSYLVANIA PWR & LT.        
PENNSYLVANIA........................  MARTINS CREEK...............  2             PENNSYLVANIA PWR & LT.        
PENNSYLVANIA........................  SHAWVILLE...................  1             PENNSYLVANIA ELEC CO.         
PENNSYLVANIA........................  SHAWVILLE...................  2             PENNSYLVANIA ELEC CO.         
PENNSYLVANIA........................  SUNBURY.....................  3             PENNSYLVANIA PWR & LT.        
PENNSYLVANIA........................  SUNBURY.....................  4             PENNSYLVANIA PWR & LT.        
                                                                                                                
TENNESSEE...........................  JOHNSONVILLE................  7             TENNESSEE VAL AUTH.           
TENNESSEE...........................  JOHNSONVILLE................  8             TENNESSEE VAL AUTH.           
TENNESSEE...........................  JOHNSONVILLE................  9             TENNESSEE VAL AUTH.           
TENNESSEE...........................  JOHNSONVILLE................  10            TENNESSEE VAL AUTH.           
                                                                                                                
WEST VIRGINIA.......................  HARRISON....................  1             MONONGAHELA POWER CO.         
WEST VIRGINIA.......................  HARRISON....................  2             MONONGAHELA POWER CO.         
WEST VIRGINIA.......................  HARRISON....................  3             MONONGAHELA POWER CO.         
WEST VIRGINIA.......................  MITCHELL....................  1             OHIO POWER CO.                
WEST VIRGINIA.......................  MITCHELL....................  2             OHIO POWER CO.                
                                                                                                                
WISCONSIN...........................  JP PULLIAM..................  8             WISCONSIN PUB SER CO.         
WISCONSIN...........................  NORTH OAK CREEK\2\..........  1             WISCONSIN ELEC PWR.           
WISCONSIN...........................  NORTH OAK CREEK\2\..........  2             WISCONSIN ELEC PWR.           
WISCONSIN...........................  NORTH OAK CREEK\2\..........  3             WISCONSIN ELEC PWR.           
WISCONSIN...........................  NORTH OAK CREEK\2\..........  4             WISCONSIN ELEC PWR.           
WISCONSIN...........................  SOUTH OAK CREEK\2\..........  5             WISCONSIN ELEC PWR.           
WISCONSIN...........................  SOUTH OAK CREEK\2\..........  6             WISCONSIN ELEC PWR.           
----------------------------------------------------------------------------------------------------------------
\1\Vertically fired boiler.                                                                                     
\2\Arch-fired boiler.                                                                                           



                                                                                                                

[[Page 18776]]
                                 Table 3.--Phase I Cell Burner Technology Units                                 
----------------------------------------------------------------------------------------------------------------
              State                            Plant                Unit                  Operator              
----------------------------------------------------------------------------------------------------------------
INDIANA..........................  WARRICK.....................          4  STHERN IND GAS & EL.                
MICHIGAN.........................  JH CAMPBELL.................          2  CONSUMERS POWER CO.                 
OHIO.............................  AVON LAKE...................         12  CLEVELAND ELEC ILLUM.               
OHIO.............................  CARDINAL....................          1  CARDINAL OPERATING.                 
OHIO.............................  CARDINAL....................          2  CARDINAL OPERATING.                 
OHIO.............................  EASTLAKE....................          5  CLEVELAND ELEC ILLUM.               
OHIO.............................  GENRL JM GAVIN..............          1  OHIO POWER CO.                      
OHIO.............................  GENRL JM GAVIN..............          2  OHIO POWER CO.                      
OHIO.............................  MIAMI FORT..................          7  CINCINNATI GAS & EL.                
OHIO.............................  MUSKINGUM RIVER.............          5  OHIO POWER CO.                      
OHIO.............................  WH SAMMIS...................          7  OHIO EDISON CO.                     
PENNSYLVANIA.....................  HATFIELDS FERRY.............          1  WEST PENN POWER CO.                 
PENNSYLVANIA.....................  HATFIELDS FERRY.............          2  WEST PENN POWER CO.                 
PENNSYLVANIA.....................  HATFIELDS FERRY.............          3  WEST PENN POWER CO.                 
TENNESSEE........................  CUMBERLAND..................          1  TENNESSEE VAL AUTH.                 
TENNESSEE........................  CUMBERLAND..................          2  TENNESSEE VAL AUTH.                 
WEST VIRGINIA....................  FORT MARTIN.................          2  MONONGAHELA POWER CO.               
----------------------------------------------------------------------------------------------------------------


Appendix B to Part 76--Procedures and Methods for Estimating Costs of 
Nitrogen Oxides Controls Applied to Group 1, Phase I Boilers

    1. Purpose and Applicability
    This technical appendix specifies the procedures, methods, and 
data that the Administrator will use in establishing ``***the degree 
of reduction achievable through this retrofit application of the 
best system of continuous emission reduction, taking into account 
available technology, costs, and energy and environmental impacts; 
and which is comparable to the costs of nitrogen oxides controls set 
pursuant to subsection (b)(1) (of section 407 of the Act).'' In 
developing the allowable NO<INF>X emissions limitations for Group 2 
boilers pursuant to subsection (b)(2) of section 407 of the Act, the 
Administrator will consider only those systems of continuous 
emission reduction that, when applied on a retrofit basis, are 
comparable in cost to the average cost in constant dollars of low 
NO<INF>X burner technology applied to Group 1, Phase I boilers, as 
determined in section 3 below.
    The Administrator will evaluate the capital cost (in dollars per 
kilowatt electrical ($/kW)), the operating and maintenance costs (in 
$/year), and the cost-effectiveness (in annualized $/ton NO<INF>X 
removed) of installed low NO<INF>X burner technology controls over a 
range of boiler sizes (as measured by the gross electrical capacity 
of the associated generator in megawatt electrical (MW)) and 
utilization rates (in percent gross nameplate capacity on an annual 
basis) to develop estimates of the average capital cost and cost-
effectiveness for Group 1, Phase I boilers. The following units will 
be excluded from these determinations of the average capital cost 
and cost-effectiveness of NO<INF>X controls set pursuant to 
subsection (b)(1) of section 407 of the Act: (1) Units employing an 
alternative technology, or only overfire air as applied to wall-
fired boilers or only separated overfire air as applied to 
tangentially fired boilers, in lieu of low NO<INF>X burner 
technology for reducing NO<INF>X emissions; (2) units employing no 
controls, only controls installed before November 15, 1990, or only 
modifications to boiler operating parameters (e.g., burners out of 
service or fuel switching) for reducing NO<INF>X emissions; and (3) 
units that have not achieved the applicable emission limitation.

2. Average Capital Cost for Low NO<INF>X Burner Technology Applied 
to Group 1, Phase I Boilers

    The Administrator will use the procedures, methods, and data 
specified in this section to estimate the average capital cost (in 
$/kW) of installed low NO<INF>X burner technology applied to Group 
1, Phase I boilers.
    2.1  Using cost data submitted pursuant to the reporting 
requirements in section 4 below, boiler-specific actual or estimated 
actual capital costs will be determined for each unit in the 
population specified in section 1 above for assessing the costs of 
installed low NO<INF>X burner technology. The scope of installed low 
NO<INF>X burner technology costs will include the following capital 
costs for retrofit application: (1) For the burner portion--burners 
or air and coal nozzles, burner throat and waterwall modifications, 
and windbox modifications; and, where applicable, (2) for the 
combustion air staging portion--waterwall modifications or panels, 
windbox modifications, and ductwork, and (3) scope adders or 
supplemental equipment such as replacement or additional fans, 
dampers, or ignitors necessary for the proper operation of the low 
NO<INF>X burner technology. Capital costs associated with boiler 
restoration or refurbishment such as replacement of air heaters, 
asbestos abatement, and recasing will not be included in the cost 
basis for installed low NO<INF>X burner technology. The scope of 
installed low NO<INF>X burner technology retrofit capital costs will 
include materials, construction and installation labor, engineering, 
and overhead costs.
    2.2  Using gross nameplate capacity (in MW) for each unit as 
reported in the National Allowance Data Base (NADB), boiler-specific 
capital costs will be converted to a $/kW basis.
    2.3  Capital cost curves ($/kW versus boiler size in MW) or 
equations for installed low NO<INF>X burner technology retrofit 
costs will be developed for: (1) Dry bottom wall fired boilers 
(excluding units applying cell burner technology) and (2) 
tangentially fired boilers.
    2.4  The capital cost curves or equations defined above will be 
used to develop weighted average cost estimates of installed low 
NO<INF>X burner technology applied to Group 1, Phase I boilers. The 
weighting factor will be the unit gross nameplate generating 
capacity (in MW) as reported in the NADB.

3. Average Cost-Effectiveness for Low NO<INF>X Burner Technology 
Applied to Group 1, Phase I Boilers

    The Administrator will use the procedures, methods, and data 
specified in this section to estimate the average cost-effectiveness 
(in annualized $/ton NO<INF>X removed) of installed low NO<INF>X 
burner technology applied to Group 1, Phase I boilers.
    3.1  Boiler-specific estimates of annual tons NO<INF>X removed 
by the installed low NO<INF>X burner technology will be determined 
for each unit in the population specified in section 1 above.
    3.1.1  The baseline NO<INF>X emission rate (in lb/mmBtu, annual 
average basis) will be estimated prior to retrofitting any low 
NO<INF>X burner technology controls. For units that have installed 
and certified continuous emission monitoring systems for measuring 
the NO<INF>X emission rate pursuant to part 75 of this chapter at 
least 120 days prior to the low NO<INF>X burner technology retrofit, 
an estimate of the average annual uncontrolled NO<INF>X emission 
rate will be developed using continuous emission monitoring data for 
the 120 days immediately before the low NO<INF>X burner technology 
retrofit or another continuous 120-day or longer period as approved 
by the Administrator. (In cases where 120 days of certified and 
quality-assured continuous emission monitoring data are not 
available prior to the low NO<INF>X burner technology retrofit, the 
Administrator may use continuous emission monitoring data over a 
shorter period or short-term test data to estimate the uncontrolled 
NO<INF>X emission rate.) Continuous emission monitoring data or 
other emission rate measurements will be extrapolated to one year of 
unit operation.
    3.1.2  The controlled NO<INF>X emission rate (in lb/mmBtu, 
annual average basis) will be 

[[Page 18777]]
estimated after installation, shakedown, and/or optimization of all low 
NO<INF>X burner technology controls have been completed and while 
the unit is complying with the applicable emission limitation (or 
alternative emission limitation). Continuous emission monitoring 
data submitted pursuant to part 75 of this chapter will be used for 
the 120 days immediately following installation and testing of the 
final low NO<INF>X burner technology, provided the unit is complying 
with the applicable emission limitation (or alternative emission 
limitation), or another continuous 120-day or shorter period as 
approved by the Administrator. Continuous emission monitoring data 
will be extrapolated to one year of unit operation.
    3.1.3  The NO<INF>X emission reduction (in lb/mmBtu, annual 
average basis) achieved by the installed low NO<INF>X burner 
technology will be estimated by subtracting the controlled NO<INF>X 
emission rate defined in section 3.1.2 from the uncontrolled 
NO<INF>X emission rate defined in section 3.1.1.
    3.1.4  Annual estimates of the NO<INF>X emission reduction 
achieved by the installed low NO<INF>X burner technology will be 
converted to annual tons of NO<INF>X removed by multiplying it by 
the annual heat input (in mmBtu). Unit heat input data submitted 
pursuant to part 75 of this chapter for calendar year 1994 or for 
the year immediately following installation and testing of the final 
low NO<INF>X burner technology, will be used when such data are 
available prior to October 30, 1995. Such data will be adjusted to 
an annual basis whenever a nonrecurrent extended outage at the 
affected unit during the period has taken place.
    3.2  The boiler-specific capital costs of installed low NO<INF>X 
burner technology developed in section 2.1 will be annualized by 
multiplying them by a constant dollar capital recovery factor based 
on a 20-year economic life (e.g., 0.115).
    3.3  Using cost data submitted pursuant to the reporting 
requirements in section 4, boiler-specific annual operating and 
maintenance cost increases (or decreases) will be determined for 
each unit in the population specified in section 1 above. The scope 
of the operating and maintenance costs (or savings) attributable to 
the installed low NO<INF>X burner technology may, but not 
necessarily will, include incremental increases (or decreases) in: 
maintenance labor and materials costs, operating labor costs, 
operating fuel costs, and secondary air fan electricity costs.
    3.4  The average annual cost-effectiveness of installed low 
NO<INF>X burner technology applied to Group 1, Phase I boilers will 
be estimated as follows: (1) The annualized capital costs defined in 
section 3.2 and the annual operating and maintenance cost increases 
(or decreases) defined in section 3.3 will be summed for all units 
in the population specified in section 1; and (2) these annualized 
costs will be divided by the sum of the NO<INF>X emission reductions 
(in tons/year) achieved by the units in the population specified in 
section 1.

4. Reporting Requirements

    4.1  The following information is to be submitted by each 
designated representative of a Phase I affected unit subject to the 
reporting requirements of Sec. 76.14(c):
    4.1.1  Schedule and dates for baseline testing, installation, 
and performance testing of low NO<INF>X burner technology.
    4.1.2  Estimates of the annual average baseline NO<INF>X 
emission rate, as specified in section 3.1.1, and the annual average 
controlled NO<INF>X emission rate, as specified in section 3.1.2, 
including the supporting continuous emission monitoring or other 
test data.
    4.1.3  Copies of pre-retrofit and post-retrofit performance test 
reports.
    4.1.4  Detailed estimates of the capital costs based on actual 
contract bids for each component of the installed low NO<INF>X 
burner technology including the items listed in section 2.1. 
Indicate number of bids solicited. Provide a copy of the actual 
agreement for the installed technology.
    4.1.5  Detailed estimates of the capital costs of system 
replacements or upgrades such as coal pipe changes, fan 
replacements/upgrades, or mill replacements/upgrades undertaken as 
part of the low NO<INF>X burner technology retrofit project.
    4.1.6  Detailed breakdown of the actual costs of the completed 
low NO<INF>X burner technology retrofit project where low NO<INF>X 
burner technology costs (section 4.1.4) are disaggregated, if 
feasible, from system replacement or upgrade costs (section 4.1.5).
    4.1.7  Description of the probable causes for significant 
differences between actual and estimated low NO<INF>X burner 
technology retrofit project costs.
    4.1.8  Detailed breakdown of the burner and, if applicable, 
combustion air staging system annual operating and maintenance costs 
for the items listed in section 3.3 before and after the 
installation, shakedown, and/or optimization of the installed low 
NO<INF>X burner technology. Include estimates and a description of 
the probable causes of the incremental annual operating and 
maintenance costs (or savings) attributable to the installed low 
NO<INF>X burner technology.
    4.2  All capital cost estimates are to be broken down into 
materials costs, construction and installation labor costs, and 
engineering and overhead costs. All operating and maintenance costs 
are to be broken down into maintenance materials costs, maintenance 
labor costs, operating labor costs, and fan electricity costs. All 
capital and operating costs are to be reported in dollars with the 
year of expenditure or estimate specified for each component.

[FR Doc. 95-8742 Filed 4-12-95; 8:45 am]
BILLING CODE 6560-50-P