Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18751

FOR FURTHER INFORMATION CONTACT:

Daniel A. Meer, Chief, Rulemaking

Section, Air and Toxics Division, U.S.

Environmental Protection Agency,

Region IX, 75 Hawthorne Street, San

Francisco, CA 94105, Telephone: (415)

744–1185.

SUPPLEMENTARY INFORMATION

Background

On June 2, 1994 in 59 FR 28503 EPA

proposed to approve the following rules

into the California SIP: SCAQMD’s Rule

1106.1, Pleasure Craft Coating

Operations, and Rule 109,

Recordkeeping for Volatile Organic

Compound Emissions. Rule 1106.1 was

adopted by SCAQMD on May 1, 1992,

and Rule 109 was adopted on March 6,

1992. Both rules were submitted by the

California Air Resources Board (CARB)

to EPA on September 14, 1992. These

rules were submitted in response to

EPA’s 1988 SIP-Call and the CAA

section 182(a)(2)(A) requirement that

nonattainment areas fix their reasonably

available control technology (RACT)

rules for ozone in accordance with EPA

guidance that interpreted the

requirements of the pre-amendment Act.

A detailed discussion of the background

for each of the above rules and

nonattainment areas is provided in the

NPR(s) cited above.

EPA has evaluated the above rules for

consistency with the requirements of

the CAA and EPA regulations and EPA

interpretation of these requirements as

expressed in the various EPA policy

guidance documents referenced in the

NPR(s) cited above. EPA has found that

the rules meet the applicable EPA

requirements. A detailed discussion of

the rule provisions and evaluations has

been provided in [59 FR 28503 and in

technical support documents (TSDs)

available at EPA’s Region IX office

(TSDs dated February 16, 1993, Pleasure

Craft Coating Operations and February

24, 1993, Recordkeeping for Volatile

Organic Compound Emissions).

Response to Public Comments

A 30-day public comment period was

provided in 59 FR 28503. EPA received

no comments.

EPA Action

EPA is finalizing action to approve

the above rules for inclusion into the

California SIP. EPA is approving the

submittal under section 110(k)(3) as

meeting the requirements of section

110(a) and Part D of the CAA. This

approval action will incorporate these

rules into the federally approved SIP.

The intended effect of approving these

rules is to regulate emissions of VOCs in

accordance with the requirements of the

CAA.

Nothing in this action should be

construed as permitting or allowing or

establishing a precedent for any future

request for revision to any state

implementation plan. Each request for

revision to the state implementation

plan shall be considered separately in

light of specific technical, economic,

and environmental factors and in

relation to relevant statutory and

regulatory requirements.

The Office of Management and Budget

(OMB) has exempted this action from

review under Executive Order 12866.

List of Subjects in 40 CFR Part 52

Environmental protection, Air

pollution control, Hydrocarbons,

Incorporation by reference,

Intergovernmental relations, Ozone,

Reporting and recordkeeping

requirements, Volatile organic

compounds.

Note: Incorporation by reference of the

State Implementation Plan for the State of

California was approved by the Director of

the Federal Register on July 1, 1982.

Dated: March 28, 1995.

Felicia Marcus,

Regional Administrator.

Part 52, chapter I, title 40 of the Code

of Federal Regulations is amended as

follows:

PART 52—[AMENDED]

1. The authority citation for part 52

continues to read as follows:

Authority: 42 U.S.C. 7401–7671q.

Subpart F—California

2. Section 52.220 is amended by

adding paragraph (c)(189)(i)(A)(6) to

read as follows:

§ 52.220 Identification of plan.

* * * * *

(c) * * *

(189) * * *

(i) * * *

(A) * * *

(6) Rule 109 adopted on March 6,

1992, and Rule 1106.1 adopted on May

1, 1992.

* * * * *

[FR Doc. 95–9042 Filed 4–12–95; 8:45 am]

BILLING CODE 6560–50–P

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.

SUMMARY: The EPA is today issuing this

final rule in response to a remand by a

U.S. Court of Appeals. The rule

reinstates emission limitations for

nitrogen oxides (NOX) from coal-fired

utility units under section 407 of the

Clean Air Act (‘‘the Act’’). The emission

limitations for NOX, along with

emission limitations for sulfur dioxide

from utility plants, will reduce acidic

deposition and its serious adverse

effects on natural resources, ecosystems,

materials, visibility, and public health.

On March 22, 1994, EPA promulgated

a rule establishing NOX emission

limitations. The rule established

emission limits generally achievable

using ‘‘low NOX burner technology’’ and

established a procedure for obtaining an

alternative emission limitation (AEL) if

a unit could not achieve the prescribed

limit using such technology. On

November 29, 1994, the U.S. Court of

Appeals for the District of Columbia

Circuit ruled that the definition of ‘‘low

NOX burner technology’’ in the March

22, 1994 rule exceeded EPA’s statutory

authority. The Court vacated the rule

and remanded it to the Agency for

further proceedings. On March 28, 1995,

EPA and environmental and utilityindustry parties signed an agreement

addressing the March 22, 1994

regulations, including issues raised by

the Court’s remand.

Based on the Court’s decision and a

review of the record, the Agency is now

revising the March 22, 1994 regulations.

The low-NOX-burner-technology

definition is revised to comply with the

Court’s decision. Other provisions

concerning the compliance date for

Phase I NOX emission limitations, AELs,

and plans for averaging NOX emissions

of two or more units are also revised. In

general, the revisions reduce

compliance requirements, extend the

compliance date, and increase

compliance flexibility. The rule

revisions are issued as a direct final rule

because they are consistent with the

Court’s decision and no adverse

comment is expected. The revisions are

also consistent with the March 28, 1995

agreement.
18752 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

EFFECTIVE DATE: This direct final rule

will be effective on May 23, 1995 unless

significant, adverse comments are

received by May 15, 1995. If significant,

adverse comments are timely received

on any portion of the direct final rule,

that portion of the direct final rule will

be withdrawn through a notice in the

Federal Register.

The incorporation by reference of

certain publications listed in the rule is

approved by the Director of the Federal

Register as of May 23, 1995.

ADDRESSES: Docket No. A–92–15,

containing information considered

during development of the promulgated

standards and requirements, is available

for public inspection and copying

between 8:30 a.m. and 3:30 p.m.,

Monday through Friday, at EPA’s Air

Docket Section (6102), Waterside Mall,

Room M1500, 1st Floor, 401 M Street,

SW., Washington, DC 20460. A

reasonable fee may be charged for

copying. Additional data and

information pertaining to the rule may

be found in Docket No. A–90–39.

FOR FURTHER INFORMATION CONTACT:

Peter Tsirigotis, Acid Rain Division

(6204J), U.S. Environmental Protection

Agency, 401 M Street SW., Washington,

DC 20460 (for technical matters) at (202)

233–9620; or Dwight C. Alpern (same

address) (for legal matters) at (202) 233–

9151.

SUPPLEMENTARY INFORMATION: The

information in this preamble is

organized as follows:

I. Background

A. Purpose of the Acid Rain NOX Program

B. Statutory Framework

C. EPA’s Rulemaking

II. The Court’s Decision

III. EPA’s Response to the Court’s Decision

A. Changes to the March 22, 1994 Rule

1. Definitions

2. Date for Compliance with NOX

Emission Limitations

3. Alternative Emission Limitations

4. NOX Averaging Plans

5. Phase I NOX Compliance Extensions

6. Miscellaneous

B. Reissuance of the Emission Limits

C. Permit Status

IV. Administrative Requirements

A. Executive Order 12866

B. Unfunded Mandates Act

C. Paperwork Reduction Act

D. Regulatory Flexibility Act

E. Miscellaneous

I. Background

A. Purpose of the Acid Rain NOX

Program

The purpose of the Acid Rain NOX

emission reduction program is to reduce

the adverse effects of acidic deposition

on natural resources, ecosystems,

visibility, materials, and public health

by substantially reducing annual

emissions of NOX from coal-fired

electric utilities. 42 U.S.C. 7651(a)(1).

NOX, along with sulfur dioxide, is a

principal precursor of acidic deposition.

Although sulfate deposition is

considered to be the major contributor

to long-term aquatic acidification, nitric

acidic deposition plays a dominant role

in the ‘‘acid pulses’’ associated with the

fish kills observed during the springtime

meltdown of the snowpack in sensitive

watersheds. Furthermore, the

atmospheric deposition of NOX is a

substantial source of nutrients that

damage estuaries, such as the

Chesapeake Bay, by causing algae

blooms and anoxic conditions. Nitrogen

dioxide and particulate nitrate also

contribute to pollutant haze. Moreover,

acidic deposition and ozone (formed by

the photochemical reaction of NOX and

volatile organic compounds) contribute

to the premature weathering and

corrosion of building materials such as

architectural paints and stones.

Electric utilities are a major

contributor to NOX emissions

nationwide; in 1980, they accounted for

30 percent of total NOX emissions and,

by 1990, their contribution rose to 38

percent of total NOX emissions.

Approximately 80 percent of electric

utility NOX emissions come from coalfired plants of the type addressed by

section 407 of the Act.

B. Statutory Framework

Section 407(b)(1) of the Act requires

the Administrator to establish NOX

emission limitations for two types of

coal-fired utility boilers (‘‘Group 1’’

boilers): (1) Tangentially fired boilers;

and (2) dry bottom wall-fired boilers

other than units applying cell burner

technology (‘‘wall-fired boilers’’). The

Act specifies the maximum emission

limits (often referred to as

‘‘presumptive’’ emission limits or

limits) for these Group 1 boilers: 0.45 lb/

mmBtu for tangentially fired boilers;

and 0.50 lb/mmBtu for wall-fired

boilers. If the Administrator finds that

the presumptive limits cannot be

achieved using ‘‘low NOX burner

technology,’’ the Administrator may set

less stringent limitations. 42 U.S.C.

7651f(b)(1). A Phase I coal-fired utility

unit with a Group 1 boiler must comply

with the promulgated annual NOX

emission limitation on the later of

January 1, 1995 or the date the unit is

required to meet SO2 emission

reduction requirements under section

404(d) of the Act (id.).

Section 407(d) provides a mechanism

by which a utility unit may receive an

AEL less stringent than the applicable

limitation established under section

407(b)(1) for Group 1 boilers. In order to

receive an AEL, the owner or operator

of the unit must demonstrate that it

cannot meet the applicable limitation

using properly installed ‘‘low NOX

burner technology’’ designed to meet

the limitation. 42 U.S.C. 7651f(d). If the

owner or operator makes the necessary

showings, then an AEL will be

established that does not require ‘‘any

additional control technology beyond

low NOX burners.’’ 42 U.S.C. 7651f(d).

Section 407(d) also provides that EPA

may grant the owner or operator of a

Phase I coal-fired utility unit subject to

section 407(b)(1) a 15-month extension

from the January 1, 1995 compliance

deadline. Such an extension may be

granted if the technology necessary to

meet the promulgated NOX emission

limitation is not in adequate supply to

enable its installation and operation at

the unit, consistent with system

reliability, by January 1, 1995. Section

407(d) specifies the process the

Administrator must use in authorizing

the Phase I extension.

A more detailed discussion of the

statutory framework is set forth at 59 FR

13538–13539 (March 22, 1994).

C. EPA’s Rulemaking

As discussed above, the term ‘‘low

NOX burner technology’’ plays an

important role in section 407 of the Act.

There has been substantial controversy

as to whether Congress intended ‘‘low

NOX burner technology’’ to be

equivalent to ‘‘low NOX burners’’ and

whether ‘‘low NOX burner technology’’

includes all forms of combustion air

staging or only staging at the burner. On

November 25, 1992, EPA published a

proposed rule establishing NOX

emission limitations for coal-fired

utility units under section 407(b)(1) of

the Act and other requirements and

procedures for all coal-fired units

subject to Phase I and Phase II of the

Acid Rain Program (57 FR 55632–

55683). In recognition of the controversy

surrounding the definition of low NOX

burner technology, the proposed rule

contained two regulatory options and an

alternative approach for defining that

term. Option 1 defined low NOX burner

technology as low NOX burners

incorporating overfire air for wall-fired

boilers and as low NOX burners

incorporating separated overfire air (e.g.,

LNCFS 2 and LNCFS 3) for tangentially

fired boilers (57 FR 55642). Option 2

defined low NOX burner technology as

low NOX burners incorporating

separated overfire air for tangentially

fired boilers, but excluded overfire air

from the definition for wall-fired boilers

(id.). In addition to the two options set

forth, EPA solicited comment on a third
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18753

1Waterwalls 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.

2Typical 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 nitrogencontaining volatile matter under conditions of

limited availability of oxygen, with the result that

the formation of fuel NOX is suppressed. The

arrangement also results in combustion of air and

coal char with a cooler flame than the flame of

conventional burners, which suppresses thermal

NOX formation (59 FR 13541).

3Several other low NOX burner designs also use

combustion air staging in the waterwall hole where

Continued

approach. This approach was endorsed

by the Utility Air Regulatory Group

(UARG) (a group made up of utilities

that subsequently challenged the March

22, 1994 final rule) and the U.S.

Department of Energy (DOE). Under the

third approach, low NOX burner

technology was defined as excluding

both overfire air for wall-fired boilers

and separated overfire air for

tangentially fired boilers (57 FR 55644–

55645).

On March 22, 1994, EPA published

the final NOX rule (59 FR 13538–13580).

In that rule, EPA adopted the Option 1

definition of low NOX burner

technology after considering the

chemical process of low NOX

combustion, the history and application

of low NOX combustion technology,

Congress’ intent in section 407 of the

Act, and the actual application of NOX

control technology.

II. The Court’s Decision

Following issuance of the March 22,

1994 rule, numerous utilities and the

National Coal Association petitioned for

judicial review of the rule. The two

main issues raised on appeal were:

whether EPA’s definition of low NOX

burner technology was lawful; and

whether EPA was obligated to extend

the January 1, 1995 compliance date

prescribed in section 407 of the Act

because EPA did not issue the rules by

the May 15, 1992 issuance date required

by section 407.

On November 29, 1994, the U.S. Court

of Appeals for the District of Columbia

Circuit issued a decision on the

petitioners’ first issue. The Court held

that ‘‘[t]he statutory text, structure, and

history of section 407 * * * support the

‘unmistakable conclusion’ that Congress

unambiguously intended the term ‘low

NOX burner technology’ to encompass

only low NOX burners, not overfire air’’

(Alabama Power Co. v. U.S. EPA, No.

94–1170 (D.C. Cir, 1994) slip op. at 12).

The Court explained that under the AEL

provision, ‘‘Congress did not intend to

require utilities to consider the ‘full

range of low NOX combustion

technologies’ because it expressly

provided that utilities not be required to

install or use any equipment beyond

low NOX burners in their efforts to

comply with NOX emission limits’’ (id.

at 11). After concluding that EPA had

exceeded its statutory authority, the

Court vacated the March 22, 1994 rule

and determined that the petitioners’

second issue on the compliance

deadline was moot.

III. EPA’s Response to the Court’s

Decision

A. Changes to the March 22, 1994 Rule

1. Definitions

Low NOX burners and low NOX burner

technology. Because the Court

determined that, in defining low NOX

burner technology in the March 22,

1994 rule, the Agency exceeded its

authority under section 407 of the Act,

the revised rule changes the definition

of the terms, ‘‘low NOX burners and low

NOX burner technology,’’ in § 76.2. The

Court determined that low NOX burner

technology encompasses ‘‘only low NOX

burners’’ (Alabama Power, slip op. at

12). The Agency is removing from the

March 22, 1994 definition the language

that is inconsistent with the Court’s

determination. In particular, the revised

rule eliminates the language stating that

low NOX burner technology includes

‘‘any combination of coal and air

nozzles ports * * * not restricted to

location within the boiler, including

* * * NOX ports, overfire air ports, or

staged combustion ports’’ (59 FR 13565).

Other related language (e.g., ‘‘at points

downstream of the initial flame’’ (id.)) in

the March 22, 1994 definition is also

removed.

The removed language is replaced by

new language explaining that the new

definition includes the staging of

combustion air using air nozzles or

registers located inside any boiler

waterwall 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 NOX burner

technology includes only low NOX

burners.

For wall-fired boilers, two types of

NOX combustion controls have been

used: (1) Advanced burner retrofits for

reducing NOX formation (‘‘burner

retrofits’’); 2 and (2) combustion air

staging (i.e., ‘‘overfire air’’ for wall-fired

boilers) (57 FR 55640). Burner retrofits

must be custom-designed for each boiler

and the ease of retrofitting varies from

boiler to boiler:

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 1.)

Unlike burner retrofits, overfire air for

wall-fired boilers involves diverting

some combustion air from waterwall

openings that include a burner and

injecting the air above the top burner

level. This generally requires the cutting

of entirely new holes in the waterwall

above the highest burners (id.; 57 FR

55640).

The new low-NOX-burner-technology

definition, as applied to wall-fired

boilers, encompasses all burner retrofits

that are essentially within an existing

waterwall hole. Such retrofits may

involve minor modifications (e.g., of

pressure parts or refractory material) to

the existing waterwall hole as necessary

to accommodate the retrofit essentially

within the hole. The new definition

excludes all overfire air as applied to

wall-fired boilers. This definition meets

the Court’s requirement that only

burners be considered; nothing in the

Court’s decision excludes retrofit

burners requiring minor waterwall

modifications. See, e.g., slip op. at 5

footnote 3 (discussing low NOX

burners).

For tangentially fired boilers, all

commercially available systems for

reducing NOX formation involve a

staged combination of coal and air (57

FR 55641). Three types of control

systems for tangentially fired boilers

were discussed in detail in the preamble

to proposed part 76: (1) The

replacement of the original coal and air

nozzle array in each corner of the boiler

with a new low NOX configuration of

coal and air nozzles and the installation

of air nozzles at the upper end of each

waterwall hole that contains the new

coal and air nozzle array (‘‘LNCFS 1’’); 3
18754 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

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).

4See footnote 3 above.

5As discussed below, the definition of

‘‘alternative technology’’ is also revised.

6The language in § 76.5(d) is also revised to make

it consistent with § 76.5(a) and clarify that a unit

under § 76.5(d) may seek to use a compliance

option in §§ 76.10, 76.11, or 76.12.

(2) the installation of air nozzles in a

new air nozzle assembly above the

waterwall hole that contains the original

coal and air nozzle array in each corner

(‘‘LNCFS 2’’); and (3) the replacement of

the original coal and air nozzle array

with a new low NOX configuration in

each corner and the installation of both

air nozzles at the upper end of each

waterwall hole containing the new array

and a new air nozzle assembly above

each waterwall hole (‘‘LNCFS 3’’) (id.).

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-NOXburner-technology definition, as applied

to tangentially fired boilers, includes the

applications of LNCFS 1 (and other low

NOX burner designs) 4 that are

essentially within the existing waterwall

hole. The included applications may

involve minor modifications (e.g., of

pressure parts or refractory material) to

the existing waterwall hole as necessary

to accommodate the NOX emission

controls essentially within the existing

hole. The new definition excludes all

applications of separated overfire air,

e.g., LNCFS 2 and LNCFS 3. This is

consistent with the Court’s holding in

that, as discussed above, LNCFS 1 for

tangentially fired boilers is analogous to

retrofit burners for wall-fired boilers and

thus falls within the Court’s

prescription that ‘‘low NOX burner

technology’’ be limited to low NOX

burners only.

The Agency notes that its new

definition is in essence the same as the

definition set forth in the preamble of

the November 25, 1992 proposed rule as

an alternative to Options 1 and 2 (57 FR

55644–55645). The alternative

approach, like the new definition

adopted today, excluded overfire air for

wall-fired boilers and excluded LNCFS

2 and LNCFS 3 for tangentially fired

boilers. The utilities described the

alternative approach as involving ‘‘the

direct replacement of the original

equipment manufacturer’s coal burners

(with low NOX burners) without major

new waterwall penetrations or parts’’

(Docket Item IV–D–111 at 74). The

utilities also noted that their definition

under the alternative approach—like the

definition in the revised rule—includes

‘‘burners[-]only technologies that have

recently begun to be offered

commercially’’ for tangentially fired

boilers, i.e., the low NOX burner designs

described in footnote 3 above (id. at 73).

In comments on the November 25, 1992

proposal, the utilities and DOE

supported the alternative approach as

being consistent with section 407 of the

Act (Docket Items IV–D–2 at 1–2 and

IV–D–111 at 73–84).

Other defined terms. In light of the

new low-NOX-burner-technology

definition adopted today, two other

definitions in § 76.2 of the March 22,

1994 rule are now superfluous and are

eliminated in the revised rule.5 In

particular, the new low-NOX-burnertechnology definition itself describes

what forms of air staging are included

or not included in the definition, and,

as discussed below, references in other

sections of part 76 to ‘‘combustion air

staging’’ have been removed.

Consequently, there is no need for the

definition of ‘‘combustion air staging’’.

See 59 FR 13564. Further, the definition

of ‘‘low NOX coal and air nozzles’’ is

unnecessary because that term is no

longer used in part 76. See 59 FR 13565.

2. Date for Compliance with NOX

Emission Limitations

The revised rule changes the date in

§ 76.5(a) on which a Phase I unit with

a Group 1 boiler begins to be subject to

the NOX emission limitations. Under the

March 22, 1994 rule, such a Phase I unit

must begin compliance with NOX

emission limitations on the later of

January 1, 1995 or the date the unit

becomes subject to SO2 emission

reduction requirements under section

404(d) of the Act. Under the revised

rule, the January 1, 1995 date is changed

to January 1, 1996. Analogous changes

in the compliance date are made in

§§ 76.1(d) and 76.5(d).6

The change in the compliance date is

necessary because of the delay in the

repromulgation of the NOX emission

limitations. The Court vacated the

March 22, 1994 rule on November 29,

1994, only 32 days prior to the

compliance deadline. The Court added

that the reissued NOX emission

limitations ‘‘will undoubtedly take

effect after the statutory deadline [for

compliance] of January 1, 1995.’’

Alabama Power, slip op. at 13.

Moreover, the Court noted ‘‘the agency’s

representation at oral argument that it

would be inclined to exercise its

enforcement discretion in favor of the

utilities in order to account for delay in

the rulemaking process’’ (id.).

As correctly predicted by the Court,

today’s revised rule reinstating NOX

emission limitations takes effect after

January 1, 1995, despite the Agency’s

efforts to expedite the rulemaking

process. Maintaining the January 1,

1995 deadline for compliance with the

NOX emission limitations would mean

that the limitations under the revised

rule would have to be applied prior to

their effective date.

Not only would this approach raise

questions of retroactivity, but also the

Agency is concerned about the lack of

any lead time between promulgation of

NOX emission limitations and the

beginning date for compliance. Under

these circumstances, the Agency must

determine what Congress would have

intended had it addressed the problem

of issuance of the NOX emission

limitations after January 1, 1995.

Section 407 required the Agency to

issue final NOX regulations within 18

months of enactment of title IV (i.e., by

May 15, 1992) and required compliance

with such regulations to begin on

January 1, 1995. Although these are

independent requirements and, the

Agency maintains, no specific lead time

between rule promulgation and

compliance was mandated, it is

reasonable to conclude that Congress

intended that there be some lead time.

Retaining a January 1, 1995 compliance

deadline would result in no lead time at

all.

Further, the Agency recognizes that

the promulgation of the March 22, 1994

low-NOX-burner-technology definition

and the Court’s decision vacating the

March 22, 1994 rule may have
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18755

7Twenty-five units applied for a 2-year Phase I

extension for SO2 under § 72.42 (which

automatically granted them a 2-year NOX

extension), and 6 units applied for a 15 month

Phase I NOX compliance extension under § 76.12.

8Since low NOX burner technology does not

include air nozzles or ports located outside of a

waterwall hole that includes a burner, provisions in

§ 76.10 concerning the technical feasibility of

installing such air nozzles or ports are irrelevant.

Consequently, the March 22, 1994 provisions in

§§ 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 § 76.10(g)(1)(ii)(C)

that the designated representative revise the AEL

demonstration period plan is changed to apply only

when the owner or operator identifies operating

modifications (whether for the boiler or the NOX

emission control system) that improve NOX

reductions. Consistent with § 76.10(a)(2)(iii)(B), this

does not require revision of the plan to include

operating modifications that would prevent the

boiler or NOX control system from being operated

in accordance with the bid and design

specifications on which the design of the NOX

control system is based. Plan revision is no longer

required for all possible equipment modifications or

upgrades since they could be outside the new lowNOX-burner technology definition. See 59 FR

13570–13571.

9 In order to avoid repeating in other sections the

NOX control technology requirements set forth in

§ 76.10(a)(2) for qualifying for an AEL (e.g., that a

Group 1 boiler install low NOX burner technology,

alternative technology, or, for a tangentially fired

boiler, separated overfire air), the references in

§§ 76.10(d)(8) and (e)(2)–(4) and 76.15(c) to specific

technologies are replaced by a general reference to

the ‘‘installed NOX emission control system’’ or

‘‘NOX emission control system.’’ Such a system

must, of course, meet the requirements in

§ 76.10(a)(2). In addition, § 76.10(e)(2) is also

revised to make it consistent with § 76.10(d)(8).

engendered some uncertainty and

confusion on the part of utilities

concerning their regulatory obligations.

This further supports a change in the

January 1, 1995 compliance deadline.

However, the Agency notes that Phase I

units generally proceeded in good faith

to take the necessary steps to comply

with the March 22, 1994 rule. These

steps included obtaining a permit to

operate and, where necessary, installing

NOX control equipment, including low

NOX burners. Of the 175 Phase I units

with Group 1 boilers on Table A of

section 404, all submitted NOX

compliance plans by May 6, 1994 and

only 31 requested a compliance date

extension.7 Since complying with the

revised rule will, in general, require the

same or less effort than the industry has

already undertaken, the extension until

January 1, 1996 is judged to be

reasonable and appropriate.

The establishment of January 1, 1996

as the compliance deadline also reflects

the fact that title IV of the Act created

an annual program with regard to both

SO2 and NOX emissions reductions.

Units must comply with SO2 emission

limitations by emitting no more SO2 in

a year than is authorized by the number

of allowances ‘‘held for that unit for that

year.’’ 42 U.S.C. 7651b(g). Similarly,

emission limitations for NOX are

annual: The generic limits established

under section 407(b) are ‘‘annual

allowable emission limitations’’; AELs

under section 407(d) are emission rates

that can be met ‘‘on an annual basis’’;

and emissions averaging plans under

section 407(e) limit NOX emissions

using both ‘‘alternative

contemporaneous annual emission

limitations’’ and a ‘‘Btu-weighted

average annual emission rate.’’

Adopting January 1, 1996 as the

compliance deadline preserves the

annual nature of the Acid Rain Program.

The revised rule also changes

language in the March 22, 1994 rule

concerning the date for compliance with

any revised emission limitations for

Group 1 boilers that may be adopted

under section 407(b)(2) of the Act. The

March 22, 1994 rule states that Group 1,

Phase II units must comply with any

revised Group 1 emission limitations

starting on January 1, 2000. Because

EPA has not determined whether to

revise the Group 1 emission limitations

under section 407(b)(2), it is

unnecessary to state, in the rule at this

time, the compliance date for such

revised limitations. If and when the

limitations are revised, the rule will be

amended to add both the limitations

and the compliance date. Sections

76.5(g) and 76.10(f)(1)(iii) are revised to

remove that compliance date.

3. Alternative Emission Limitations

In order to ensure that § 76.10 is

consistent with the new definition of

the term ‘‘low NOX burner technology,’’

all phrases in the section that elaborated

on that term are eliminated. In

particular, in §§ 76.10(a)(1) and (2) of

the March 22, 1994 rule, the term ‘‘low

NOX burner technology’’ is followed by

phrases such as: ‘‘including separated

overfire air’’; ‘‘incorporating both closecoupled and separated overfire air’’; or

‘‘incorporating combustion air staging

above the top burner level’’ (59 FR

13567–13568). The revised rule

excludes all of these phrases and is

reworded as necessary to reflect their

removal. As a result of these changes,

units with Group 1 boilers may apply

for AELs if they are unable to meet

applicable emission limitations using

low NOX burner technology under the

new definition in § 72.2.8

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 lowNOX-burner-technology definition,

which was then in effect and included

close-coupled and separated overfire air,

some units installed only separated

overfire air. The record information to

date indicates that separated overfire air

alone is at least as effective in reducing

NOX emissions as low NOX burner

technology as applied to tangentially

fired boilers. See Docket Item IV–A–10,

Background Document for RIA of NOX

Regulations, appendix A at 21. The

Agency therefore maintains that such

units should not be disqualified from

seeking an AEL because of their efforts

to comply with the March 22, 1994 rule.

Sections 76.10(a)(1) and (2)(i)(A) are

revised to allow such units to seek

AELs.

For similar reasons, the definition of

‘‘alternative technology’’ set forth in

§ 76.2 is revised. Under the revised rule,

‘‘alternative technology’’ is NOX

emission control technology other than

low NOX burner technology but does

not include overfire air for wall-fired

boilers and separated overfire air for

tangentially fired boilers. Under

§§ 76.10(a) and (e)(11), a unit using

alternative technology, in addition to or

in lieu of low NOX burner technology,

to reduce NOX emissions must show an

annual average emissions reduction of

greater than 65 percent in order to

qualify for an AEL. The revision of the

alternative-technology definition

excludes units with tangentially fired

boilers applying separated overfire air

from the 65-percent reduction

requirement.9 This avoids putting at a

disadvantage, for purposes of obtaining

AELs, units that may have installed

separated overfire air because of the

March 22, 1994 low-NOX-burnertechnology definition.

Moreover, certain dates in

§ 76.10(c)(1), concerning the submission

of petitions for an AEL demonstration

period, and in § 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 §§ 76.14 and

76.15 of the March 22, 1994 rule refer

to combustion air or air flow through

‘‘overfire air ports’’ or ‘‘combustion air

staging ports.’’ Since low NOX burner

technology now excludes air nozzles or

ports located outside a waterwall hole

that includes a burner, these references

are no longer appropriate. The

provisions have been modified to apply
18756 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

10Sections 76.15(a), (b), and (d) are also revised

to state, consistent with §§ 76.10(d)(13) and

76.14(a)(2)(v), that the owner or operator ‘‘may’’ use

for tests and procedures set forth in § 76.15.

Further, the language in § 76.15(b)(6) is clarified,

and § 76.15(d)(3) is revised to refer more generally

to optimization of the combustion process and to

cite burner balancing as an example.

only to tangentially fired boilers (which

may use close-coupled overfire air) and

to refer to the ‘‘distribution of

combustion air’’ within the ‘‘NOX

emission control system.’’ See 59 FR

13574 (§ 76.14(a)(2)(i)) and 13575

(§ 76.15(b)(3) and (d)(2)).10

As a result of these changes, the

revised rule complies with the Court’s

decision. The rule provides that, in

applying for an AEL, the designated

representative for an affected Group 1

unit must demonstrate that the unit

cannot meet the presumptive emission

limit using properly installed and

operated low NOX burner technology as

redefined (or alternative technology or,

for tangentially fired boilers, separated

overfire air) that is designed to meet the

presumptive limit. The designated

representative is not required to attempt

to meet the presumptive limit using low

NOX burners plus overfire air for wallfired boilers or separated overfire air for

tangentially fired boilers. Rather, in

keeping with the Court’s decision, the

designated representative may base the

petition for an AEL on the use of only

low NOX burners. Nothing in the Court’s

decision mandates any further changes

in the AEL provisions.

4. NOX Averaging Plans

Section 76.11 is revised to change the

provisions concerning compliance on an

individual basis and on a group basis

with the emission limitations in NOX

averaging plans and to clarify language

in the formulas implementing the

requirements of such plans.

Under § 76.11(d) of the March 22,

1994 rule, units governed by a NOX

averaging plan must comply with both

individual-unit limits ‘‘and’’, where

applicable, a group emission

requirement. 59 FR 13572

(§ 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 § 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

§§ 76.5, 76.6, or 76.7. The formula for

determining group compliance is

Equation 2 in § 76.11(d)(1)(ii)(A).

Section 76.11(d)(2) of the March 22,

1994 rule addresses liability where units

under the NOX averaging plan fail to

meet any of the requirements of the

plan, including the individual-unit

limits and the group emission

requirement. Under § 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 § 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 § 76.11(d)(2)(i)

is that if the group showing of

compliance under § 76.11(d)(1)(ii) is

made, then no unit under the plan is

subject to the excess emissions penalty.

Regardless of whether the group

showing of compliance (which is for

purposes of excess emissions) is made,

the March 22, 1994 rule does not

exempt any unit under the plan from

liability under section 113 for violation

of the individual-unit limits.

In contrast with the March 22, 1994

rule, the revised rule provides that if

one or more units fail to meet the

individual-unit limits but there is a

showing of group compliance for the

year, then all units in the plan will be

deemed to be in compliance for the year

with the individual-unit limits. With

regard to their NOX emissions for the

year, all units therefore will be in

compliance with the averaging plan and

have no potential liability for violation

of the plan or part 76. Further, none of

the units will have excess emissions for

the year under part 77.

The Agency has received public

comment to the effect that this revised

approach, which was proposed in the

original November 25, 1992 proposed

NOX rule, is more consistent with the

purposes of section 407 than the

approach adopted in the March 22, 1994

rule. Neither section 407(e) nor the

legislative history specifically address

this matter. However, section 407(e)

states that individual units’ alternative

contemporaneous annual emission

limitations must ‘‘ensure that the units’

actual annual NOX emission rate’’

averaged over the units in question does

not exceed the ‘‘Btu-weighted annual

average emission rate for the same

units’’ if they had met the applicable

emission limitations under section

407(b). 15 U.S.C 7651f(e). That goal is

satisfied where units fail to meet the

individual-unit limits in the NOX

averaging plan but can show group

compliance with the plan.

Further, even though the March 22,

1994 rule relieves units in such

circumstances from liability for excess

emissions, the units are still potentially

liable for civil penalties, which may be

enforceable through Agency action or

citizen suits under sections 113 and 304

of the Act. This potential liability is

sufficiently significant that a utility with

a NOX averaging plan may, in effect, be

forced to comply unit-by-unit with the

individual-unit limits even if the group

emission requirement could be met

without meeting all the individual-unit

limits. The individual-unit limits can

restrict the utility’s flexibility, for

example, in dispatching the units in the

plan. In order to minimize the

likelihood of violating individual-unit

limits, some designated representatives

have submitted Phase I NOX averaging

plans that set alternative

contemporaneous emission limitations

equal to the presumptive limits in § 76.5

and that specify no heat input limits.

However, under such plans, the

individual-unit limits can still restrict

the utility’s flexibility to choose which

units in the plan will be retrofitted with

NOX emission control systems and what

types of NOX emission control systems

will be used. The Agency is concerned

that the net result of such lack of

flexibility is that designated

representatives will be encouraged to

seek AELs for more units, rather than

attempting to average units with higher

NOX emissions with units with lower

NOX emissions. Not only is the case-bycase process of setting AELs

administratively burdensome for

utilities and the Agency, but also the

Agency is concerned that total NOX

emissions are likely to be higher the

greater the number of units with AELs.

The Agency concludes that removing

the requirement to meet individual-unit

limits when there is group compliance
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18757

11Consistent with these changes,

§ 76.11(d)(1)(i)(B) is revised to state that units must

meet either the individual-unit limits ‘‘or’’ the

group emission requirement.

under a NOX averaging plan is a

reasonable interpretation of section

407(e) and better implements that

provision. Consequently,

§ 76.11(d)(1)(ii) is revised to state that

when the units in a NOX averaging plan

show compliance with the group

emission requirement in

§ 76.11(d)(1)(ii)(A) for a given year, the

units will be deemed to comply for that

year with their individual emission

limitations and heat input limits. Since

units meeting group compliance are

thereby in compliance with both the

individual-unit and group emission

requirements of the plan, there is no

need to state separately that group

compliance relieves the units of any

penalties for excess emissions. Section

76.11(d)(2)(ii) is therefore eliminated.11

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 individualunit 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 §§ 76.5, 76.6, or 76.7. Consistent

with that approach, a unit with an AEL

must use the applicable emission

limitation in §§ 76.5, 76.6, or 76.7 rather

than the AEL. The only exception is that

an early election unit, which elects to

meet NOX emission limitations in Phase

I but is allowed to participate in a NOX

averaging plan only in Phase II, must

use the most stringent applicable

limitation in §§ 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

§§ 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, § 76.11(a)(1) is revised

to state that a unit in an averaging plan

in Phase I must be a Phase I unit with

a Group 1 boiler.

EPA notes that it has received public

comments concerning the use of a single

NOX averaging plan for units of two or

more operating companies (also referred

to as utility systems) that are

subsidiaries of a single holding

company. In such a case, the operating

companies would designate the same

designated representative (probably

someone at the holding company level)

for their units in order to meet the

common designated representative

requirement for a NOX averaging plan.

Each operating company could still

designate its own alternate designated

representative. Concern was raised that

the designated representative at the

holding company level may not be

readily accessible and that operating

companies may need the flexibility of

having two persons at the operating

company level with authority to act for

the designated representative. The

Agency is currently reviewing this

matter and, in light of the public

comments, will propose, in a future

rulemaking, revisions to 40 CFR part 72

that would allow designation of a

second alternate designated

representative for units under certain

limited circumstances. Such

circumstances could be where: The

unit’s utility system is a subsidiary of a

holding company with two or more

utility-system subsidiaries in two or

more states; and, in order to use a NOX

averaging plan involving units of two or

more such subsidiaries, all the utilitysystem subsidiaries of that holding

company have the same designated

representative. EPA intends to consider

this revision, and other revisions to

streamline part 72, in a rulemaking to be

completed in 1995.

5. Phase I NOX Compliance Extensions

Section 76.12 is revised in order to

reflect the new low-NOX-burnertechnology definition. The March 22,

1994 rule provides for a Phase I NOX

compliance extension where a

tangentially fired boiler was designed

and guaranteed, but failed, to meet the

presumptive emission limit and there is

a contract to install close-coupled or

separated overfire air on or before

January 1, 1996. The March 22, 1994

rule includes similar language, with

regard to wall-fired boilers, providing a

Phase I NOX compliance extension

where there is a contract to install

additional equipment, including

overfire air. 59 FR 13572 (§ 76.12(a)(1)

(ii) and (iii)). The direct final rule

eliminates these provisions and a

related provision in § 76.12(b)(3). No

extensions were requested under these

provisions.

The March 22, 1994 rule also provides

for a Phase I NOX compliance extension

for units where low NOX burner

technology designed to meet the

presumptive emission limits is not in

adequate supply for installation and

operation by January 1, 1995, consistent

with system reliability. Requests for the

extensions were due by October 1, 1994.

These provisions are not changed in the

revised rule. Extension requests for 6

units under this provision were

submitted, and the requests either have

already been granted or will be acted on

consistent with the revised rule after its

effective date.

The Agency is aware that, in very

limited circumstances, an additional

extension of the compliance date for

Phase I NOX emission limitations may

be warranted. These circumstances are

as follows: A source has 3 or more units

that have extensions under section

404(d) until January 1, 1997 to comply

with Phase I NOX emission limits and,

due to claimed operational problems

associated with the planned NOX

emission control systems, one unit may

need an additional extension to redesign

and install low NOX burner technology.

Because of its extension under section

404(d), the unit has not yet installed the

NOX control system that was designed

to comply with the low-NOX-burner

technology definition in the March 22,

1994 rule. With the change adopted

today in the definition, the unit has

flexibility to redesign the NOX control

system to meet the new definition and

avoid the claimed operational problems.

However, unless an additional

compliance extension is granted, there

will be insufficient time to install

redesigned low NOX burner technology

without causing system reliability

problems.

Because the need for an additional

extension appears to result from the

change in the low-NOX-burnertechnology 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

§ 76.12(e)) requires the submission of a

petition for the extension within 15

days of the publication of the revised

rule and establishes procedures for

acting on the petition. The procedures

and the provisions in the revised rule

concerning treatment of the unit upon

approval of the petition are essentially

the same as the procedures and

provisions applicable to Phase I NOX

compliance extensions. See 59 FR

13572–13573 (§ 76.12(c) and (d)).

6. Miscellaneous

The revised rule excludes § 76.9(e) of

the March 22, 1994 rule, which provides

that each ton of excess emissions of
18758 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

12Since the completion of DOE’s analysis, other

types of low NOX burner technology have been

developed for tangentially fired boilers. See

footnote 3 above. Although EPA currently lacks

data on the long-term performance of these NOX

controls, the outlook for their performance is

promising.

13 DOE’s analysis included Fiddler’s Ferry Unit 1

as a unit with LNCFS 1. Since installation of LNCFS

1 in that unit involved major modifications of the

existing waterwall holes (i.e., cutting out a

waterwall section having a height of 3 feet above

each existing waterwall hole and a width equal to

the width of the hole), the unit’s NOX control

system does not fall within the new low-NOXburner 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.

NOX will be a separate violation. In

response to the utilities’ challenge of

§ 76.9(e), EPA moved before the Court

for a voluntary remand of the provision.

The Court granted the motion and

therefore EPA is now deleting the

provision.

The revised rule also changes

provisions concerning the types of units

for which reports of cost data on low

NOX burner technology installations

must be prepared and the date by which

the reports must be submitted under

§ 76.14(c). Consistent with the new lowNOX-burner-technology definition, the

cost reports are not required for: wallfired boilers using only overfire air and

not low NOX burners; and tangentially

fired boilers using only separated

overfire air and not low NOX burner

technology. Because such boilers are not

using low NOX burner technology, cost

data on their NOX emissions controls

are not relevant to setting of Group 2,

Phase II NOX emission limitations under

section 407(b)(2) of the Act. An

analogous change is made in section 1

of appendix B to part 76.

Also excluded from cost reporting are

units that begin installing a new NOX

emission control system after 120 days

from publication of the instant direct

final rule in the Federal Register. In

light of the statutory requirement that

Group 2, Phase II emission limitations

be established by January 1, 1997, the

Agency maintains that cost information

on those units would be received too

late to be useful in the rulemaking on

such emission limitations.

Finally, the date for submission of

cost reports is revised in § 76.14(c)(3) to

take account of the vacating of the

March 22, 1994 rule by the Court. As in

the March 22, 1994 rule, the cost reports

must be submitted within 120 days after

completion of the low NOX burner

technology retrofit project. However, in

order to provide time for resumption

and completion of cost data collection

that may have been stopped when the

rule was vacated, the revised rule

ensures that all projects will have at

least 40 days, from the publication of

the revised rule in the Federal Register,

to submit the cost reports. Cost reports

on projects completed more than 80

days before publication of the direct

final rule must be submitted by the 40th

day after such publication.

B. Reissuance of the Emission Limits

Section 407(b)(1) requires the

Administrator to adopt by regulation the

presumptive emission limits unless she

finds that they cannot be achieved using

low NOX burner technology. In the

March 22, 1994 rule, the Administrator

found that the record evidence showed

that the presumptive limits were

achievable using low NOX burners plus

overfire air for wall-fired boilers and

separated overfire air for tangentially

fired boilers (59 FR 13546). In light of

the revised low-NOX-burner-technology

definition, the Administrator has

reviewed the record concerning the

performance of low NOX burners and

concludes that the presumptive limits

are still achievable. The revised rule

therefore reissues the presumptive

limits of 0.50 lb/mmBtu for wall-fired

boilers and 0.45 lb/mmBtu for

tangentially fired boilers.

The record includes analyses

conducted by DOE in which the

presumptive limits were examined in

light of the low-NOX-burner-technology

definition supported by DOE, i.e., the

third approach in the November 25,

1992 proposal. The revised rule adopts

in essence the same definition as DOE

supported. As discussed below, DOE

concluded, and the utilities agreed, that

most units could achieve the

presumptive limits using low NOX

burners without overfire air for wallfired boilers and without separated

overfire air for tangentially fired boilers.

See, e.g., Docket Item IV–D–162, Fourth

Supplementary Comments of UARG,

February 2, 1994 at 16–23.

After reviewing a number of sources

of information on control technology

efficiency, DOE estimated control

technology performance based primarily

on data from ongoing demonstration

projects and other recent installations of

NOX control systems. The analysis of

data from wall-fired and tangentially

fired boilers, fitted with low NOX burner

technology as defined by DOE,

indicated that NOX reductions of 45 to

50 percent would be achieved at wallfired boilers and of 35 to 37 percent

would be achieved at tangentially fired

boilers (57 FR 55646–55647). DOE’s

NOX control technology performance

estimates were consistent with average

NOX reductions projected by the

utilities. The utilities projected average

NOX reductions of 47 percent with use

of burner retrofits for wall-fired boilers

and 35 to 37 percent with the use of

LNCFS 1 for tangentially fired boilers

(Docket Item IV–D–111 at 59–61).12

Further, the utilities supported DOE’s

performance estimates in their brief to

the Court in Alabama Power (Docket

Item VIII–A–1, Brief of Petitioners, July

1, 1994, at 18–19).

DOE’s analysis also showed that,

assuming 45 percent control efficiency

for wall-fired boilers and 35 percent for

tangentially fired boilers, less than 10

percent of the Group 1 units would fail

to meet the presumptive limits (57 FR

55648). Further, the utilities similarly

concluded that ‘‘review of the

uncontrolled emissions at wall-fired and

tangentially fired boilers, and of the

capabilities of low NOX burner

technology, show that (the presumptive)

limits are aggressive but generally

achievable by most Group 1 units with

the use of (low NOX burners) alone’’

(Docket Item IV–D–111 at 138). The

utilities reiterated this conclusion before

the Court in Alabama Power. The

utilities stated that ‘‘all of the

tangentially fired boiler groupings

analyzed by EPA’s contractor would

comply with the final presumptive

emission limitation using low NOX

burners alone for tangentially fired

boilers (i.e., LNCFS 1), without the use

of separated overfire air’’ (Docket Item

VIII–A–1, Brief of Petitioners at 40).

In the March 22, 1994 preamble, EPA

did not adopt DOE’s analysis and

instead presented its own analysis of

control technology performance data

available after promulgation of the

November 25, 1992 proposal. The EPA

found that the majority of wall-fired

boilers would be expected to achieve

NOX reductions of 40 to 50 percent

using low NOX burners only and no

overfire air (59 FR 13546). The EPA also

found that tangentially fired boilers

using LNCFS 1 would achieve reduction

of 20 to 25 percent. While EPA’s finding

on wall-fired boilers is consistent with

DOE’s finding, the two analyses differ

concerning tangentially fired boilers.

However, upon reconsideration, the

Agency finds that the 20 to 25 percent

estimate of reductions achievable using

LNCFS 1 erroneously excluded the

reductions using a form of LNCFS 1

referred to in the March 22, 1994

preamble as ‘‘LNCFS 1+.’’ 59 FR 13546–

13547. Because ‘‘LNCFS 1+’’ (i.e.,

Lansing Smith Unit 2) 13 employs the
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 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.

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 tangentiallyfired boilers submitted NOX compliance

plans. (See 59 FR 13567 (§ 76.9 (a)

through (c))). For units lacking Acid

Rain permits, the NOX compliance plans

were submitted along with applications

for such permits. For units that already

had Acid Rain permits covering SO2

emission limitations, the NOX

compliance plans were submitted as

permit revisions. Most of the plans

required NOX compliance commencing

on January 1, 1995. Twenty-five units

had previously been granted 2-year

extensions for NOX compliance under

§ 72.42, and designated representatives

for 6 more units requested 15-month

extensions under § 76.12 of the March

22, 1994 rule.

The Agency followed the applicable

permit issuance and revision procedures

under part 72 of the Acid Rain permits

rule. These procedures required notice

of a proposed permit or proposed permit

revision and opportunity for public

comment prior to issuance of a final

permit or final revised permit. Most of

the submitted NOX compliance plans

were already approved and included in

final permits or final revised permits

before the November 29, 1994 Alabama

Power decision vacating the March 22,

1994 rule. Because of the vacating of the

rule, the Agency has deferred action on

those plans and extension requests that

were not yet approved when the Court

issued its decision.

Under the March 22, 1994 rule, NOX

compliance plans had to identify which

one of several possible compliance

options was proposed for each Phase I

unit with a Group 1 boiler. Id.

(§ 76.9(c)(4)). In the NOX compliance

plans already submitted to the Agency,

units sought to comply either with the

presumptive limits or through NOX

emissions averaging plans. The units

that requested NOX compliance

extensions sought to comply either with

the presumptive limits or through NOX

emissions averaging plans after the

extensions expire.

If, as anticipated, the revised rule

becomes final and thereby reinstates the

NOX emission reduction program, the

Agency sees no need for utilities to

resubmit and for EPA to reissue,

through notice and comment

procedures, the NOX compliance plans

that have already been approved and

issued in final form in permits or permit

revisions. The final permits and permit

revisions set forth the applicable NOX

emission limitations and do not state

any definition for low NOX burner

technology. The revised rule changes

the low-NOX-burner-technology

definition but does not change the

presumptive limits or the formulas for

setting individual-unit limits or

showing group compliance in averaging

plans. The revised rule preserves

without change the provisions

governing the Phase I extensions that

were requested and either were

approved or that would have been

approved under the March 22, 1994

rule. The revised rule also does not

change the application requirements in

§ 76.9 or the permit issuance or permit

revision procedures in parts 72 and 76

applicable to NOX compliance plans.

The only changes that the revised rule

makes in the submitted NOX

compliance plans are in the general

compliance date and in the effect of

group compliance on individual-unit

limits in NOX averaging plans. The

general deadline for compliance by a

Group 1, Phase I unit with NOX

emission limitations is now the later of

January 1, 1996 (rather than 1995) or the

date on which a unit is subject to SO2

emission reduction requirements under

section 404(d) of the Act. The revised

rule also mandates, for all NOX

averaging plans, that where the units in

an averaging plan show they meet the

group compliance requirement, the

units are deemed to meet their

individual-unit limits. All NOX

compliance plans must conform to the

revised rule.

As discussed above, the Agency has

issued, elsewhere in this Federal

Register, a notice of proposal requesting

comments on the provisions of the

revised rule. Any comments concerning

the compliance deadline and the group

compliance provisions should be made

in response to that notice and would not

be appropriate in the context of permit

issuance. All other aspects of the

submitted NOX compliance plans have

already been subject to notice and

comment and are unchanged by the

revised rule.

The Agency concludes that, once the

revised rule becomes final as

anticipated, conforming changes in the

compliance date and group compliance

provisions in otherwise unchanged NOX

compliance plans are properly

considered administrative amendments

under § 72.83 of the Acid Rain permits

rule because there is no basis for

requiring notice and comment on the

changes. All existing permits that

include NOX compliance plans will be

amended under § 72.83 to the extent

necessary to make them consistent with

the new compliance date and group

compliance requirements. The

administrative amendments will

reinstate the NOX compliance plans as

amended and the approved Phase I NOX

compliance extensions under §§ 72.42

and 76.12 that are referenced in the

plans.

With regard to NOX compliance plans

in permits or permit revisions issued in

draft form for public comment but not

yet issued in final form, the Agency will

complete the issuance procedure in

accordance with the revised rule once

the rule becomes final. Since, except for

the compliance date and group

compliance provisions, neither the

substance of such plans nor the issuance

procedures were changed by the revised

rule, there is no need to reopen the

public comment period on the plans.

Any plans that have not yet been

issued in draft form will also be

processed by the Agency in accordance

with the revised rule and part 72.

Similarly, any Phase I NOX compliance

extensions requested under § 76.12 and

not acted on before November 29, 1994

will be acted on consistent with the

revised rule. It should be noted that, if

significant, adverse comment is timely

received on relevant portions of the

instant direct final rule, the NOX

compliance plans could be subject to

further change depending on the

outcome of the rulemaking initiated by

the notice of proposed rule issued

elsewhere in this Federal Register.

IV. Administrative Requirements

A. Executive Order 12866

Under Executive Order 12866 (58 FR

51735 (October 4, 1993)), the Agency

must determine whether the regulatory

action is ‘‘significant’’ and therefore

subject to Office of Management and

Budget (OMB) review and the

requirements of the Executive Order.

The Order defines ‘‘significant

regulatory action’’ as one that is likely

to result in a rule that may:

(1) Have an annual effect on the

economy of $100 million or more or

adversely affect in a material way the

economy, a sector of the economy,

productivity, competition, jobs, the
18760 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

environment, public health or safety, or

State, local, or tribal governments or

communities;

(2) Create a serious inconsistency or

otherwise interfere with an action taken

or planned by another agency;

(3) Materially alter the budgetary

impact of entitlements, grants, user fees,

or loan programs or the rights and

obligations of recipients thereof; or

(4) Raise novel legal or policy issues

arising out of legal mandates, the

President’s priorities, or the principles

set forth in the Executive Order.

Pursuant to the terms of Executive

Order 12866, it has been determined

that this rule is a ‘‘significant regulatory

action’’ because it will have an annual

effect on the economy of approximately

$276 million starting in 2000. As such,

this action was submitted to OMB for

review. Any written comments from

OMB to EPA and any written EPA

response to those comments are

included in the docket. The docket is

available for public inspection at the

EPA’s Air Docket Section, which is

listed in the ADDRESSES section of this

preamble.

EPA does not believe a revised

Regulatory Impact Analysis (RIA) is

needed for the direct final rule, which,

in large part, reinstates the March 22,

1994 rule and which imposes no new

costs beyond what costs were estimated

in the RIA to the March 22, 1994 rule.

The EPA does not anticipate major

increases in prices, costs, or other

significant adverse effects on

competition, investment, productivity,

or innovation or on the ability of U.S.

enterprises to compete with foreign

enterprises in domestic or foreign

markets due to the final rule.

In assessing the impacts of a

regulation, it is important to examine:

(1) The costs to the regulated

community, (2) the costs that are passed

on to customers of the regulated

community, and (3) the impact of these

cost increases on the financial health

and competitiveness of both the

regulated community and their

customers. The costs of this rule to

electric utilities are generally very small

relative to their annual revenues.

(However, the relative amount of the

costs will definitely vary in individual

cases.) Moreover, EPA expects that most

or all utility expenses from meeting

NOX requirements will be passed along

to ratepayers. When NOX requirements

are fully implemented in the year 2000,

consumer electric utility rates are

expected to rise by 0.12 percent on

average due to this rulemaking.

Consequently, the rule is not likely to

have an impact on utility profits or

competitiveness.

B. Unfunded Mandates Act

Section 202 of the Unfunded

Mandates Reform Act of 1995

(‘‘Unfunded Mandates Act’’) (signed

into law on March 22, 1995) requires

that the Agency prepare a budgetary

impact statement before promulgating a

rule that includes a Federal mandate

that may result in expenditure by State,

local, and tribal governments, in the

aggregate, or by the private sector, of

$100 million or more in any one year.

The budgetary impact statement must

include: (i) Identification of the Federal

law under which the rule is

promulgated; (ii) a qualitative and

quantitative assessment of anticipated

costs and benefits of the Federal

mandate and an analysis of the extent to

which such costs to State, local, and

tribal governments may be paid with

Federal financial assistance; (iii) if

feasible, estimates of the future

compliance costs and any

disproportionate budgetary effects of the

mandate; (iv) if feasible, estimates of the

effect on the national economy; and (v)

a description of the Agency’s prior

consultation with elected

representatives of State, local, and tribal

governments and a summary and

evaluation of the comments and

concerns presented. Section 203

provides that if any small governments

may be significantly or uniquely

impacted by the rule, the Agency must

establish a plan for obtaining input from

and informing, educating, and advising

any such potentially affected small

governments.

Under section 205 of the Unfunded

Mandates Act, the Agency must identify

and consider a reasonable number of

regulatory alternatives before

promulating a rule for which a

budgetary impact statement must be

prepared. The Agency must select from

those alternatives the least costly, most

cost-effective, or least burdensome

alternative, for State, local, and tribal

governments and the private sector, that

achieves the objectives of the rule,

unless the Agency explains why this

alternative is not selected or unless the

selection of this alternative is

inconsistent with law.

Because this direct final rule is

estimated to result in the expenditure by

State, local, and tribal governments, in

aggregate, or the private sector of over

$100 million per year starting in 2000,

EPA has prepared a supplement to the

Regulatory Impact Statement in

compliance with the Unfunded

Mandates Act. EPA summarizes that

supplement as follows.

The direct final rule is promulgated

under section 407 of the Clean Air Act.

The rule is issued in response to a

remand by the U.S. Court of Appeals for

the District of Columbia Circuit and, in

large part, reinstates the remanded

March 22, 1994 rule. Thus, the analysis

in the RIA developed in preparation of

the March 22, 1994 rule was

appropriately considered in response to

the requirements of the Unfunded

Mandates Act.

Total expenditures resulting from the

direct final rule are estimated at: $69

million (of which less than $1 million

is by State, local, and tribal

governments) per year in 1995–1999;

and $276 million (of which $21 million

is by State, local, and tribal

governments) per year starting in 2000.

There are no federal funds available to

assist State, local, and tribal

governments in meeting these costs.

There are important benefits from NOX

emission reductions because

atmospheric emissions of NOX have

significant, adverse impacts on human

health and welfare and on the

environment.

The rule does not have any

disproportionate budgetary effects on

any particular region of the nation, any

State, local, or tribal government, or

urban or rural or other type of

community. On the contrary, the rule

will result in only a minimal increase in

average electricity rates. Moreover, the

rule will not have a material effect on

the national economy.

Prior to issuing the March 22, 1994

rule, EPA provided numerous

opportunities, e.g., through the Acid

Rain Advisory Committee proceedings,

the public comment period, and public

hearings, for consultation with

interested parties, including State, local,

and tribal governments. In general, State

and local environmental agencies

advocated that EPA adopt more

stringent environmental controls while

municipally-owned utilities advocated

less stringent controls and more

compliance flexibility. EPA evaluated

the comments and concerns expressed,

and the direct final rule reflects, to the

extent consistent with section 407 of the

Clean Air Act, those comments and

concerns. While small governments are

not significantly or uniquely affected by

the rule, these procedures, as well as

additional public conferences and

meetings, gave small governments an

opportunity to give meaningful and

timely input and obtain information,

education, and advice on compliance.

The Agency considered several

regulatory options in developing the

rule. The option selected in the direct

final rule is the least costly and least

burdensome alternative currently

available for achieving the objectives of
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 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 NOX emission limitations for Group 1

boilers.

76.6 NOX emission limitations for Group 2

boilers. [Reserved]

76.7 Revised NOX 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 NOX 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.

§ 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 SO2 under Phase I or

Phase II pursuant to sections 404, 405,

or 409 of the Act.

(b) The emission limitations for NOX

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 SO2.

(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

§§ 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 coalfired 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 § 72.41 of this chapter and

the unit is no longer required to meet

Phase I SO2 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
18762 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

§ 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

§ 72.42(c)(5) of this chapter (as adjusted

under § 72.42(d) of this chapter) unless

the transfer unit is the last unit allocated

Phase I extension reserve allowances

under the plan.

§ 76.2 Definitions.

All terms used in this part shall have

the meaning set forth in the Act, in

§ 72.2 of this chapter, and in this section

as follows:

Alternative contemporaneous annual

emission limitation means the

maximum allowable NOX emission rate

(on a lb/mmBtu, annual average basis)

assigned to an individual unit in a NOX

emissions averaging plan pursuant to

§ 76.10.

Alternative technology means a

control technology for reducing NOX

emissions that is outside the scope of

the definition of low NOX 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

NOX retrofit of a cell burner boiler that

reuses the existing cell burner, closecoupled 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 § 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 § 76.10, for

demonstrating that the affected unit

cannot meet the applicable emission

limitation under §§ 76.5, 76.6, or 76.7

and establishing the minimum NOX

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 NOX burners and low NOX burner

technology means commercially

available combustion modification NOX

controls that minimize NOX 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 NOX 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 § 76.10,

during which the owner or operator of

an affected unit that cannot meet the

applicable emission limitation:

(1) Operates the installed NOX

emission controls in accordance with

primary vendor specifications and

procedures, with the unit operating

under normal conditions; and

(2) records and reports qualityassured 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 NOX 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 NOX is inhibited in the main burner

zone due to the reduced combustion

intensity, and NOX is destroyed in the

fuel-rich secondary combustion zone by

conversion to molecular nitrogen.

Selective catalytic reduction means a

noncombustion control technology that

destroys NOX 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 NOX into molecular nitrogen

and water.

Selective noncatalytic reduction

means a noncombustion control

technology that destroys NOX by

injecting a reducing agent (e.g.,

ammonia, urea, or cyanuric acid) into

the flue gas, downstream of the

combustion zone that converts NOX to

molecular nitrogen, water, and when

urea or cyanuric acid are used, to carbon

dioxide (CO2).

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
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 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.

§ 76.3 General Acid Rain Program

provisions.

The following provisions of part 72 of

this chapter shall apply to this part:

(a) § 72.2 (Definitions);

(b) § 72.3 (Measurements,

abbreviations, and acronyms);

(c) § 72.4 (Federal authority);

(d) § 72.5 (State authority);

(e) § 72.6 (Applicability);

(f) § 72.7 (New unit exemption);

(g) § 72.8 (Retired units exemption);

(h) § 72.9 (Standard requirements);

(i) § 72.10 (Availability of

information); and

(j) § 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.

§ 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 § 76.15.

(2) ASTM D 3172–89, Standard

Practice for Proximate Analysis of Coal

and Coke, IBR approved May 23, 1995

for § 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 § 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 § 76.15.

(2) [Reserved]

§ 76.5 NOX 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 SO2, 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 NOX to

the atmosphere in excess of the

following limits, except as provided in

paragraphs (c) or (e) of this section or in

§§ 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 NOX

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 § 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 § 76.1(c)(2), shall

comply with the NOX 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 SO2 shall comply, by

such respective date or January 1, 1996,

whichever is later, with the NOX

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 §§ 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 SO2 is exempt from the

NOX emissions limitations specified in

paragraph (a) of this section, but shall

comply with the NOX emission

limitations for Group 2 boilers under

§ 76.6.

(f) Except as provided in § 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 § 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.

§ 76.6 NOX emission limitations for Group

2 boilers. [Reserved]

§ 76.7 Revised NOX emission limitations

for Group 1, Phase II boilers. [Reserved]

§ 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 NOX

under § 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 § 76.5 shall not be subject to any

revised NOX emissions limitation for

Group 1 boilers that the Administrator

may issue pursuant to section 407(b)(2)

of the Act until January 1, 2008,
18764 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

provided the designated representative

demonstrates that the unit is in

compliance with the limitation under

§ 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 § 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 § 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 NOX

for Phase II units with Group 1 boilers

under §§ 76.5(g) and if revised emission

limitations are issued for Group 1

boilers pursuant to section 407(b)(2) of

the Act, § 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 § 72.40 of this chapter,

and unless the unit is a substitution unit

under § 72.41 of this chapter or a

compensating unit under § 72.43 of this

chapter, a complete compliance plan

covering the unit shall not include the

provisions for SO2 emissions under

§ 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

§ 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 § 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 NOX

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 § 72.9 of this chapter,

a unit that is governed by an approved

early election plan and that is not a

substitution unit under § 72.41 of this

chapter or a compensating unit under

§ 72.43 of this chapter shall not be

subject to the following standard

requirements under § 72.9 of this

chapter for Phase I:

(A) The permit requirements under

§§ 72.9(a)(1) (i) and (ii) of this chapter;

(B) The sulfur dioxide requirements

under § 72.9(c) of this chapter; and

(C) The excess emissions

requirements under § 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 NOX 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 § 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 § 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 NOX for Phase II units

with Group 1 boilers under § 76.5(g)

and, if revised emission limitations are

issued pursuant to section 407(b)(2) of

the Act, § 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 NOX for Phase

II units with Group 1 boilers under

§ 76.5(g) and, if revised emission

limitations are issued pursuant to

section 407(b)(2) of the Act, § 76.7.

§ 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 NOX emissions covering the

unit.

(2) The original and three copies of

the permit application and compliance

plan for NOX 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 NOX emissions for
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 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 NOX 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 NOX 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 NOX

compliance plans. (1) In accordance

with § 72.40(a)(2) of this chapter, a

complete compliance plan for NOX

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 § 76.5, 76.6, or 76.7 or

specify one or more other Acid Rain

compliance options for NOX in

accordance with the requirements of

this part. A complete compliance plan

for NOX 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 §§ 76.5, 76.6, 76.7, 76.8

(early election), 76.10 (alternative

emission limitation), 76.11 (NOX

emissions averaging), or 76.12 (Phase I

NOX compliance extension)) and any

additional information required for the

appropriate option in accordance with

this part;

(v) Reference to the standard

requirements in § 72.9 of this chapter

(consistent with § 76.8(e)(1)(i)); and

(vi) The requirements of §§ 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 NOX emissions

covering the unit, in accordance with

the deadlines in § 72.30(c) of this

chapter.

§ 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 § 76.8 and cannot meet the

applicable emission limitation in

§§ 76.5, 76.6, or 76.7 using, for Group 1

boilers, either low NOX 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 §§ 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 NOX 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 NOX 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 NOX

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 NOX emission control

technology on which the applicable

emission limitation in § 76.6 is based;

and

(ii) The installed NOX emission

control system has been designed to

meet the applicable emission limitation

in §§ 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 NOX emission control system

has been properly installed and

properly operated according to

specifications and procedures designed

to minimize the emissions of NOX to the

atmosphere;

(B) Unit operating data as specified in

this section show that the unit and NOX

emission control system were operated

in accordance with the bid and design

specifications on which the design of

the NOX 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 NOX emission control

system show that the unit could not

meet the applicable emission limitation

in §§ 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 NOX emission control

system, that shows that the specific unit

and the NOX emission control system

was unable to meet the applicable

emissions limitation under §§ 76.5, 76.6,

or 76.7 and was operated in accordance

with the operating conditions upon

which the design of the NOX 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 §§ 76.5, 76.6, or 76.7 and the

minimum NOX emissions rate that the

specific unit can achieve during longterm 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 NOX 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 NOX

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:
18766 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

(A) 120 days after January 1 of that

calendar year, or

(B) 120 days after startup of the NOX

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 NOX 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 NOX control

technology installed (e.g., low NOX

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

§ 76.14(a)(1) showing that the installed

NOX emission control system has been

designed to meet the applicable

emission limitation in §§ 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 NOX to the

atmosphere;

(5) The date the unit commenced

operation following the installation of

the NOX emission control system or the

date the specific unit became subject to

the emission limitations of §§ 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 NOX

emission control system during the

operating period in accordance with:

Specifications and procedures designed

to achieve the maximum NOX reduction

possible with the installed NOX

emission control system or the

applicable emission limitation in

§§ 76.5, 76.6, or 76.7; the operating

conditions upon which the design of the

NOX 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 §§ 76.5, 76.6, or 76.7;

(9) A demonstration period plan, as

set forth in § 76.14(a)(2);

(10) Unit operating data and qualityassured continuous emission

monitoring data (including the specific

data items listed in § 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

§§ 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 NOX

emission reduction obtainable with the

installed system. The report shall

include the reasons for the NOX

emission control system’s failure to

meet the applicable emission limitation,

and the tests and procedures that will be

followed to optimize the NOX emission

control system’s performance. Such

tests and procedures may include those

identified in § 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 NOX emission control system during

the demonstration period in accordance

with: specifications and procedures

designed to achieve the maximum NOX

reduction possible with the installed

NOX emission control system or the

applicable emissions limitation in

§§ 76.5, 76.6, or 76.7; the operating

conditions (including load dispatch

conditions) upon which the design of

the NOX 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 NOX 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 NOX

emission reduction performance,

consistent with the demonstration

period plan and the proper operation of

the installed NOX emission control

system. Such certification shall explain

any differences between the installed

NOX 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 NOX 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

§ 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 §§ 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
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18767

design of the NOX emission control

system was based and describes the

reason or reasons for the failure of the

installed NOX emission control system

to meet the applicable emission

limitation in §§ 76.5, 76.6, or 76.7 on an

annual average basis.

(8) The minimum NOX emission rate,

in lb/mmBtu, that the affected unit can

achieve on an annual average basis with

the installed NOX 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 NOX 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 NOX burner technology

and cannot meet the applicable

emission limitation in § 76.5 shall

demonstrate, to the satisfaction of the

Administrator, that the actual

percentage reduction in NOX emissions

(lbs/mmBtu), on an annual average basis

is greater than 65 percent of the average

annual NOX emissions prior to the

installation of the NOX emission control

system. The percentage reduction in

NOX emissions shall be determined

using continuous emissions monitoring

data for NOX taken during the time

period (under paragraph (d)(3) of this

section) prior to the installation of the

NOX 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 §§ 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

§ 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 §§ 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 §§ 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 §§ 76.5, 76.6, or 76.7 (unless the unit

is participating in an approved

averaging plan under § 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 NOX 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

§§ 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 NOX

emission control system modifications

or upgrades that would produce further

NOX emission reductions, enabling the

affected unit to comply with or bring its

emission rate closer to the applicable

emissions limitation under §§ 76.5, 76.6,

or 76.7, the designated representative

may submit a request and the permitting

authority may grant, by administrative

amendment under § 72.83 of this

chapter, an extension of the

demonstration period for such period of

time (not to exceed 12 months) as may
18768 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

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 § 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 NOX 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

NOX emission control systems, make

any operational modifications, and

complete any upgrades and

maintenance to equipment specified in

the approved demonstration period plan

for optimizing NOX emission reduction

performance.

(C) When the owner or operator

identifies boiler or NOX emission

control system operating modifications

that would produce higher NOX

emission reductions, enabling the

affected unit to comply with, or bring its

emission rate closer to, the applicable

emission limitation under §§ 76.5, 76.6,

or 76.7, the designated representative

shall submit an administrative

amendment under § 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

§ 76.13(a).

§ 76.11 Emissions averaging.

(a) General provisions. In lieu of

complying with the applicable emission

limitation in §§ 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 NOX 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

§ 76.5 during all years for which the

unit is included in the plan.

(i) If a unit with an approved NOX

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 § 76.5 for the entire year 1996.

(ii) A Phase II unit approved for early

election under § 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 §§ 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 §§ 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 §§ 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

§§ 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:

R HI

HI

R HI

HI

Li i

i

n

i

i

n

li i

i

n

i

i

n

( ) ×

≤

( ) ×

( ) =

=

=

=

∑

∑

∑

∑

1

1

1

1

Equation 1

Where:

RLi = Alternative contemporaneous

annual emission limitation for unit

i, lb/mmBtu, as specified in the

averaging plan;

Rli = Applicable emission limitation for

unit i, lb/mmBtu, as specified in

§§ 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, Rli shall

equal the most stringent applicable

emission limitation under §§ 76.5 or

76.7;

HIi = 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, Rli shall equal the

applicable emissions limitation under

§§ 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
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 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 NOX averaging plan. A

complete NOX 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 §§ 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 NOX averaging plan

utilize a common stack pursuant to

§ 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 NOX 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 §§ 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

§§ 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 Btuweighted 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

§§ 76.5, 76.6, or 76.7.

(A) A group showing of compliance

shall be made based on the following

equation:

R HI

HI

R HI

HI

Equation 2

ai ai

i

n

ai

i

n

li ai

i

n

ai

i

n

( ) ×

≤

( ) ×

( ) =

=

=

=

∑

∑

∑

∑

1

1

1

1

Where:

Rai = 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

§ 75.17(a)(2)(i)(B) of this chapter,

use the same NOX 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;

Rli = Applicable annual emission

limitation for unit i lb/mmBtu, as

specified in §§ 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, Rli shall equal the

most stringent applicable emission

limitation under §§ 76.5 or 76.7;

HIai = 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, Rli shall equal the

applicable emission limitation under

§§ 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

§ 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.

§ 76.12 Phase I NOX 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 § 76.5 where

it is demonstrated, to the satisfaction of

the Administrator, that:

(i) The low NOX 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 NOX 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 NOX

compliance extension, the designated

representative shall submit a Phase I
18770 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

NOX compliance extension plan by

October 1, 1994.

(b) Contents of Phase I NOX

compliance extension plan. A complete

Phase I NOX 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 NOX burner

technology designed to meet the

applicable emission limitation under

§ 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 NOX burner technology

designed to meet the applicable

emission limitation under § 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 NOX burner

technology designed to meet the

applicable emission limitation under

§ 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

NOX 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 NOX

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 NOX 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 § 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 NOX compliance

extension plan within 3 months of

receipt.

(d) Special provisions.

(1) Emission limitations. The unit

shall comply with the applicable

emission limitation under § 76.5

beginning April 1, 1996. Compliance

shall be determined as specified in part

75 of this chapter using measured

values of NOX 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 NOX

compliance extension is included in an

averaging plan under § 76.11 for year

1996, the unit shall be treated, for

purposes of applying Equation 1 in

§ 76.11(a)(6) and Equation 2 in

§ 76.11(d)(1)(ii)(A), as subject to the

applicable emission limitation under

§ 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

NOX burner technology by January 1,

1997 may submit a petition for and

receive an extension for meeting the

applicable emission limitation under

§ 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 NOX control system at the

unit was scheduled to be installed by

January 1, 1997 and, because of

operational problems associated with

the NOX control system, will be

redesigned; and

(iii) Installation of the redesigned low

NOX 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 NOX

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 § 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

§ 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 NOX 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

§ 76.11 for year 1997, the unit shall be

treated, for the purpose of applying

Equation 1 in § 76.11(a)(6) and Equation

2 in § 76.11(d)(1)(ii)(A), as subject to the

applicable emission limitation under

§ 76.5 for the entire year 1997.

§ 76.13 Compliance and excess emissions.

Excess emissions of nitrogen oxides

under § 77.6 of this chapter shall be

calculated as follows:
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18771

(a) For a unit that is not in an

approved averaging plan:

(1) Calculate EEi for each portion of

the calendar year that the unit is subject

to a different NOX emission limitation:

EE

R R HI

Equation 3 i

ai li i = ( ) − × ( ) 2000

Where:

EEi = Excess emissions for NOX for the

portion of the calendar year (in

tons);

Rai = 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 Rl is in effect;

Rli = Applicable emission limitation for

the unit, (in lb/mmBtu), as specified

in §§ 76.5, 76.6, or 76.7 or as

determined under § 76.10;

EE EE Equation i

i

n

= ( ) =

∑

1

4

HIi = 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, Rl, is in effect.

(2) If EEi 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 EEi

= ¥100, then EEi = 0).

(3) Sum all EEi values for the calendar

year:

Where:

EE = Excess emissions for NOX 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 § 76.11(d)(1) are not

met,

EE

R HI R HI

Equation

ai i li i

i

n

i

n

=

( ) × − × ( )

( ) = =

∑ ∑

1 1

2000

5

Where:

EE = Excess emissions for NOX for the

year (in tons);

Rai = Actual annual average emission

rate for NOX for unit i, (in lb/

mmBtu), determined according to

part 75 of this chapter;

Rli = Applicable emission limitation for

unit i, (in lb/mmBtu), as specified

in §§ 76.5, 76.6, or 76.7;

HIi = Actual annual heat input for unit

i, mmBtu, determined according to

part 75 of this chapter;

n = Number of units in the averaging

plan.

§ 76.14 Monitoring, recordkeeping, and

reporting.

(a) A petition for an alternative

emission limitation demonstration

period under § 76.10(d) shall include

the following information:

(1) In accordance with § 76.10(d)(4),

the following information:

(i) Documentation that the owner or

operator solicited bids for a NOX

emission control system designed for

application to the specific boiler and

designed to achieve the applicable

emission limitation in §§ 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 NOX emission control

system to the owner or operator

showing that such system was designed

to meet the applicable emission

limitation in §§ 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 NOX 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 § 76.10(a)(2).

(2) In accordance with § 76.10(d)(9),

the following information:

(i) The operating conditions of the

NOX emission control system including

load range, O2 range, coal volatile matter

range, and, for tangentially fired boilers,

distribution of combustion air within

the NOX 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 NOX

reduction performance of the NOX

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 NOX; 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 NOX emission

control system during the

demonstration period. The tests shall

include tests in § 76.15, which may be

modified as follows:

(A) The owner or operator of the unit

may add tests to those listed in § 76.15,

if such additions provide data relevant

to the failure of the installed NOX

emission control system to meet the

applicable emissions limitation in

§§ 76.5, 76.6, or 76.7; or

(B) The owner or operator of the unit

may remove tests listed in § 76.15 that

are shown, to the satisfaction of the

permitting authority, not to be relevant

to NOX emissions from the affected unit;

and

(C) In the event the performance

guarantee or the NOX emission control

system specifications require additional

tests not listed in § 76.15, or specify

operating conditions not verified by

tests listed in § 76.15, the owner or

operator of the unit shall include such

additional tests.

(3) In accordance with § 76.10(d)(10),

the following information for the

operating period:

(i) The average NOX emission rate (in

lb/mmBtu) of the specific unit;

(ii) The highest hourly NOX emission

rate (in lb/mmBtu) of the specific unit;

(iii) Hourly NOX 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,
18772 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

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 § 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 NOX 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 NOX

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

NOX 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 NOX

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 NOX burners or other

emission reduction equipment for

reducing NOX 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 NOX 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 NOX burner technology retrofit

project; or

(ii) May 23, 1995, if the project was

completed on or before January 23,

1995.

§ 76.15 Test methods and procedures.

(a) The owner or operator may use the

following tests as a basis for the report

required by § 76.10(e)(7):

(1) Conduct an ultimate analysis of

coal using ASTM D 3176–89

(incorporated by reference as specified

in § 76.4);

(2) Conduct a proximate analysis of

coal using ASTM D 3172–89

(incorporated by reference as specified

in § 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 § 76.4).

(b) The owner or operator may

measure and record the actual NOX

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 NOX 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 NOX 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

NOX emission control system was

designed to meet the NOX emission rate

guaranteed by the primary NOX

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 ± 5

percent from the baseline controlled

condition to determine the effects on

emissions of NOX, 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 NOX emission control

system to determine the effects on NOX

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).

§ 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.
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18773

TABLE 1.—PHASE I TANGENTIALLY FIRED UNITS—Continued

State Plant Unit Operator

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.
18774 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

TABLE 1.—PHASE I TANGENTIALLY FIRED UNITS—Continued

State Plant Unit Operator

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.
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18775

TABLE 2.—PHASE I DRY BOTTOM-FIRED UNITS—Continued

State Plant Unit Operator

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 CREEK2 1 WISCONSIN ELEC

PWR.

WISCONSIN ........................................................................................................ NORTH OAK CREEK2 2 WISCONSIN ELEC

PWR.

WISCONSIN ........................................................................................................ NORTH OAK CREEK2 3 WISCONSIN ELEC

PWR.

WISCONSIN ........................................................................................................ NORTH OAK CREEK2 4 WISCONSIN ELEC

PWR.

WISCONSIN ........................................................................................................ SOUTH OAK CREEK2 5 WISCONSIN ELEC

PWR.

WISCONSIN ........................................................................................................ SOUTH OAK CREEK2 6 WISCONSIN ELEC

PWR.

1Vertically fired boiler.

2Arch-fired boiler.
18776 Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations

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 NOX

emissions limitations for Group 2 boilers

pursuant to subsection (b)(2) of section 407

of the Act, the Administrator will consider

only those systems of continuous emission

reduction that, when applied on a retrofit

basis, are comparable in cost to the average

cost in constant dollars of low NOX burner

technology applied to Group 1, Phase I

boilers, as determined in section 3 below.

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 NOX removed) of installed

low NOX 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 costeffectiveness for Group 1, Phase I boilers. The

following units will be excluded from these

determinations of the average capital cost

and cost-effectiveness of NOX 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 NOX burner technology for

reducing NOX 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

NOX emissions; and (3) units that have not

achieved the applicable emission limitation.

2. Average Capital Cost for Low NOX 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 NOX 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 NOX burner technology. The

scope of installed low NOX 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 NOX 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 NOX burner technology. The

scope of installed low NOX 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 NOX 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 NOX 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 NOX

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 NOX removed) of installed

low NOX burner technology applied to Group

1, Phase I boilers.

3.1 Boiler-specific estimates of annual

tons NOX removed by the installed low NOX

burner technology will be determined for

each unit in the population specified in

section 1 above.

3.1.1 The baseline NOX emission rate (in

lb/mmBtu, annual average basis) will be

estimated prior to retrofitting any low NOX

burner technology controls. For units that

have installed and certified continuous

emission monitoring systems for measuring

the NOX emission rate pursuant to part 75 of

this chapter at least 120 days prior to the low

NOX burner technology retrofit, an estimate

of the average annual uncontrolled NOX

emission rate will be developed using

continuous emission monitoring data for the

120 days immediately before the low NOX

burner technology retrofit or another

continuous 120-day or longer period as

approved by the Administrator. (In cases

where 120 days of certified and qualityassured continuous emission monitoring data

are not available prior to the low NOX burner

technology retrofit, the Administrator may

use continuous emission monitoring data

over a shorter period or short-term test data

to estimate the uncontrolled NOX 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 NOX emission rate

(in lb/mmBtu, annual average basis) will be
Federal Register / Vol. 60, No. 71 / Thursday, April 13, 1995 / Rules and Regulations 18777

estimated after installation, shakedown, and/

or optimization of all low NOX 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 NOX 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 NOX emission reduction (in lb/

mmBtu, annual average basis) achieved by

the installed low NOX burner technology will

be estimated by subtracting the controlled

NOX emission rate defined in section 3.1.2

from the uncontrolled NOX emission rate

defined in section 3.1.1.

3.1.4 Annual estimates of the NOX

emission reduction achieved by the installed

low NOX burner technology will be

converted to annual tons of NOX 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 NOX 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 NOX 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

NOX 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 NOX 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 NOX 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 § 76.14(c):

4.1.1 Schedule and dates for baseline

testing, installation, and performance testing

of low NOX burner technology.

4.1.2 Estimates of the annual average

baseline NOX emission rate, as specified in

section 3.1.1, and the annual average

controlled NOX 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 postretrofit performance test reports.

4.1.4 Detailed estimates of the capital

costs based on actual contract bids for each

component of the installed low NOX 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 NOX burner

technology retrofit project.

4.1.6 Detailed breakdown of the actual

costs of the completed low NOX burner

technology retrofit project where low NOX

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 NOX 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 NOX 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 NOX 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

DEPARTMENT OF THE INTERIOR

Bureau of Land Management

43 CFR Public Land Order 7132

[AZ–930–1430–01; AR 06449]

Revocation of Public Land Order No.

1076; Arizona

AGENCY: Bureau of Land Management,

Interior.

ACTION: Public Land Order.

SUMMARY: This order revokes a public

land order which withdrew 240 acres of

public land for use by the National Park

Service in connection with the

administration and maintenance of the

Wupatki National Monument. The land

was added to the Wupatki National

Monument by Public Law 87–136, and

the revocation is needed to clarify the

records and give the National Park

Service total jurisdiction. The land has

been and will remain closed to surface

entry and mining. This is a record

clearing action only.

EFFECTIVE DATE: April 13, 1995.

FOR FURTHER INFORMATION CONTACT: John

Mezes, BLM Arizona State Office, P.O.

Box 16563, Phoenix, Arizona 85011,

602–650–0509.

By virtue of the authority vested in

the Secretary of the Interior by Section

204 of the Federal Land Policy and

Management Act of 1976, 43 U.S.C.

1714 (1988), it is ordered as follows:

1. Public Land Order No. 1076, which

withdrew the following described

public land, is hereby revoked in its

entirety:

Gila and Salt River Meridian

T. 25 N., R. 8 E.,

Sec. 3, W1⁄2, that part lying west of the west

right-of-way line of U.S. Highway 89

(consisting of lot 4, SW1⁄4NW1⁄4,

NW1⁄4SW1⁄4, part of the westerly portions

of lot 3, SE1⁄4NW1⁄4, and E1⁄2SW1⁄4)

The area described contains 240 acres in

Coconino County.

2. The land is located within the

Wupatki National Monument and will

remain closed to surface entry and

mining.

Dated: April 4, 1995.

Bob Armstrong,

Assistant Secretary of the Interior.

[FR Doc. 95–9098 Filed 4–12–95; 8:45 am]

BILLING CODE 4310–32–P

43 CFR Public Land Order 7133

[OR–943–1430–01; GP5–038; OR–

50706(WA)]

Withdrawal of National Forest System

Lands for Five Seed Orchards;

Washington

AGENCY: Bureau of Land Management,

Interior.

ACTION: Public land order.

SUMMARY: This order withdraws 496.22

acres of National Forest System lands in

the Colville and Kaniksu National

Forests from mining for a period of 20

years for the Department of Agriculture,

Forest Service, to protect the Brown