Vol. 77 Wednesday, 

No. 158 August 15, 2012 

Part VI 

Environmental Protection Agency 

40 CFR Part 52 

Approval and Promulgation of Implementation Plans; States of Minnesota 

and Michigan; Regional Haze Federal Implementation Plan; Proposed Rule 

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49308 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R05–OAR–2010–0954; EPA–R05– 

OAR–2010–0037; FRL–9709–8] 

Approval and Promulgation of 

Implementation Plans; States of 

Minnesota and Michigan; Regional 

Haze Federal Implementation Plan 

AGENCY: Environmental Protection 

Agency. 

ACTION: Proposed rule. 

SUMMARY: The Environmental Protection 

Agency (EPA) is proposing a Federal 

Implementation Plan (FIP) to address 

the requirement for best available 

retrofit technology (BART) for taconite 

plants in Minnesota and Michigan. 

BART is a requirement of EPA’s regional 

haze rule which has not been satisfied 

by Minnesota or Michigan for its subject 

taconite plants. EPA developed this 

proposal in response to an inadequate 

BART determination by Michigan for its 

one subject taconite source. On June 12, 

2012, EPA approved revisions to the 

Minnesota State Implementation Plan 

(SIP) addressing regional haze but also, 

on that date, announced that in 

response to comments it was deferring 

action on emission limitations that 

Minnesota intended to represent BART 

for its taconite facilities. EPA is 

proposing to determine that the FIP 

satisfies requirements of the Clean Air 

Act (CAA or ‘‘the Act’’) that require 

states, or EPA in promulgating a FIP, to 

establish BART for applicable sources. 

DATES: Comments must be received on 

or before September 28, 2012. 

Public Hearing. EPA will hold a 

public hearing to solicit comments on 

its proposal to establish emission limits 

for taconite plants in Minnesota and 

Michigan, to satisfy requirements for 

best available retrofit technology for 

these facilities. This hearing will be 

held on Wednesday, August 29, 2012, 

10 a.m. to 2 p.m., Office of Minnesota 

Pollution Control Agency, 520 Lafayette 

Road, St. Paul, MN, Citizens Board 

Hearing Room. Information on this 

hearing is also available at http://

www.epa.gov/region5/mnhaze. 

ADDRESSES: Submit your comments, 

identified by Docket ID Nos. EPA–R05– 

OAR–2010–0954 and EPA–R05–OAR– 

2010–0037, by one of the following 

methods: 

1. www.regulations.gov: Follow the 

on-line instructions for submitting 

comments. 

2. Email: aburano.douglas@epa.gov. 

3. Fax: (312) 408–2279. 

4. Mail: Douglas Aburano, Chief, 

Attainment Planning and Maintenance 

Section, Air Programs Branch (AR–18J), 

U.S. Environmental Protection Agency, 

77 West Jackson Boulevard, Chicago, 

Illinois 60604. 

5. Hand Delivery: Douglas Aburano, 

Chief, Attainment Planning and 

Maintenance Section, Air Programs 

Branch (AR–18J), U.S. Environmental 

Protection Agency, 77 West Jackson 

Boulevard, Chicago, Illinois 60604. 

Such deliveries are only accepted 

during the Regional Office normal hours 

of operation, and special arrangements 

should be made for deliveries of boxed 

information. The Regional Office official 

hours of business are Monday through 

Friday, 8:30 a.m. to 4:30 p.m., excluding 

Federal holidays. 

Instructions: Direct your comments to 

Docket ID Nos. EPA–R05–OAR–2010– 

0954 and EPA–R05–OAR–2010–0037. 

EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or email. The www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to EPA without going 

through www.regulations.gov your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the Internet. If you 

submit an electronic comment, EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

disk or CD-ROM you submit. If EPA 

cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, EPA may not be 

able to consider your comment. 

Electronic files should avoid the use of 

special characters, any form of 

encryption, and be free of any defects or 

viruses. For additional instructions on 

submitting comments, go to Section I of 

the SUPPLEMENTARY INFORMATION section 

of this document. 

Docket: All documents in the docket 

are listed in the www.regulations.gov 

index. Although listed in the index, 

some information is not publicly 

available, e.g., CBI or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy. Publicly 

available docket materials are available 

either electronically in 

www.regulations.gov or in hard copy at 

the Environmental Protection Agency, 

Region 5, Air and Radiation Division, 77 

West Jackson Boulevard, Chicago, 

Illinois 60604. This facility is open from 

8:30 a.m. to 4:30 p.m., Monday through 

Friday, excluding federal holidays. We 

recommend that you telephone Steven 

Rosenthal at (312) 886–6052 before 

visiting the Region 5 office. 

FOR FURTHER INFORMATION CONTACT: 

Steven Rosenthal, Environmental 

Engineer, Attainment Planning & 

Maintenance Section, Air Programs 

Branch (AR–18J), U.S. Environmental 

Protection Agency, Region 5, 77 West 

Jackson Boulevard, Chicago, Illinois 

60604, (312) 886–6052, rosenthal.

steven@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Throughout this document whenever 

‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is used, we mean 

EPA. This supplementary information 

section is arranged as follows: 

I. What should I consider as I prepare my 

comments for EPA? 

II. What action is EPA taking today? 

III. Background 

IV. Requirements for a Regional Haze FIP 

V. EPA’s BART Analysis of Michigan and 

Minnesota’s Taconite Facilities 

VI. Proposed Action 

VII. Statutory and Executive Order Reviews 

I. What should I consider as I prepare 

my comments for EPA? 

When submitting comments, 

remember to: 

1. Identify the rulemaking by docket 

number and other identifying 

information (subject heading, Federal 

Register date, and page number). 

2. Follow directions—The EPA may 

ask you to respond to specific questions 

or organize comments by referencing a 

Code of Federal Regulations (CFR) part 

or section number. 

3. Explain why you agree or disagree; 

suggest alternatives and substitute 

language for your requested changes. 

4. Describe any assumptions and 

provide any technical information and/ 

or data that you used. 

5. If you estimate potential costs or 

burdens, explain how you arrived at 

your estimate in sufficient detail to 

allow for it to be reproduced. 

6. Provide specific examples to 

illustrate your concerns, and suggest 

alternatives. 

7. Explain your views as clearly as 

possible, avoiding the use of profanity 

or personal threats. 

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Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 49309 

1 Visual range is the greatest distance, in 

kilometers or miles, at which a dark object can be 

viewed against the sky. 

2Areas designated as mandatory Class I Federal 

areas consist of national parks exceeding 6000 

acres, wilderness areas and national memorial parks 

exceeding 5000 acres, and all international parks 

that were in existence on August 7, 1977. 42 U.S.C. 

7472(a). In accordance with section 169A of the 

CAA, EPA, in consultation with the Department of 

Interior, promulgated a list of 156 areas where 

visibility is identified as an important value. 44 FR 

69122 (November 30, 1979). The extent of a 

mandatory Class I area includes subsequent changes 

in boundaries, such as park expansions. 42 U.S.C. 

7472(a). Although states and tribes may designate 

as Class I additional areas which they consider to 

have visibility as an important value, the 

requirements of the visibility program set forth in 

section 169A of the CAA apply only to ‘‘mandatory 

Class I Federal areas.’’ Each mandatory Class I 

Federal area is the responsibility of a ‘‘Federal Land 

Manager.’’ 42 U.S.C. 7602(i). When we use the term 

‘‘Class I area’’ in this action, we mean a ‘‘mandatory 

Class I Federal area.’’ 

3Albuquerque/Bernalillo County in New Mexico 

must also submit a regional haze SIP to completely 

satisfy the requirements of section 110(a)(2)(D) of 

the CAA for the entire State of New Mexico under 

the New Mexico Air Quality Control Act (section 

74–2–4). 

4EPA’s regional haze regulations require 

subsequent updates to the regional haze SIPs. 40 

CFR 51.308(g)–(i). 

8. Make sure to submit your 

comments by the comment period 

deadline identified. 

II. What action is EPA taking today? 

EPA is proposing a FIP that 

establishes BART emission limitations 

for the taconite plants in Minnesota and 

Michigan that are subject to the 

Regional Haze Rule. 

III. Background 

A. Regional Haze 

Regional haze is visibility impairment 

that is produced by a multitude of 

sources and activities which are located 

across a broad geographic area and emit 

fine particulates (PM2.5) (e.g., sulfates, 

nitrates, organic carbon (OC), elemental 

carbon (EC), and soil dust), and their 

precursors (e.g., sulfur dioxide (SO2), 

nitrogen oxides (NOX)). Fine particle 

precursors react in the atmosphere to 

form PM2.5, which impairs visibility by 

scattering and absorbing light. Visibility 

impairment reduces the clarity, color, 

and visible distance that one can see. 

PM2.5 can also cause serious health 

effects and mortality in humans and 

contributes to environmental effects 

such as acid deposition and 

eutrophication. 

Data from the existing visibility 

monitoring network, the ‘‘Interagency 

Monitoring of Protected Visual 

Environments’’ (IMPROVE) monitoring 

network, show that visibility 

impairment caused by air pollution 

occurs virtually all the time at most 

national park and wilderness areas. The 

average visual range 1 in many Class I 

areas (i.e., NPs and memorial parks, 

WA, and international parks meeting 

certain size criteria) in the western 

United States is 100–150 kilometers, or 

about one-half to two-thirds of the 

visual range that would exist without 

anthropogenic air pollution. In most of 

the eastern Class I areas of the United 

States, the average visual range is less 

than 30 kilometers, or about one-fifth of 

the visual range that would exist under 

estimated natural conditions. 64 FR 

35715 (July 1, 1999). 

B. Requirements of the CAA and EPA’s 

Regional Haze Rule 

In section 169A of the 1977 

Amendments to the CAA, Congress 

created a program for protecting 

visibility in the nation’s national parks 

and wilderness areas. This section of the 

CAA establishes as a national goal the 

‘‘prevention of any future, and the 

remedying of any existing, impairment 

of visibility in mandatory Class I 

Federal areas 2 which impairment 

results from manmade air pollution.’’ 

On December 2, 1980, EPA promulgated 

regulations to address visibility 

impairment in Class I areas that is 

‘‘reasonably attributable’’ to a single 

source or small group of sources, i.e., 

‘‘reasonably attributable visibility 

impairment.’’ (45 FR 80084, December 

2, 1980). These regulations represented 

the first phase in addressing visibility 

impairment. EPA deferred action on 

regional haze that emanates from a 

variety of sources until monitoring, 

modeling and scientific knowledge 

about the relationships between 

pollutants and visibility impairment 

were improved. 

Congress added section 169B to the 

CAA in 1990 to address regional haze 

issues. EPA promulgated a rule to 

address regional haze on July 1, 1999. 

(64 FR 35714, July 1, 1999), codified at 

40 CFR part 51, subpart P. The Regional 

Haze Rule revised the existing visibility 

regulations to integrate into the 

regulation provisions addressing 

regional haze impairment and 

established a comprehensive visibility 

protection program for Class I areas. The 

requirements for regional haze, found at 

40 CFR 51.308 and 51.309, are included 

in EPA’s visibility protection 

regulations at 40 CFR 51.300–309. Some 

of the main elements of the regional 

haze requirements are summarized in 

this section of this preamble. The 

requirement to submit a regional haze 

SIP applies to all 50 states, the District 

of Columbia and the Virgin Islands.3 40 

CFR 51.308(b) requires states to submit 

the first implementation plan 

addressing regional haze visibility 

impairment no later than December 17, 

2007.4

Few states submitted a Regional Haze 

SIP prior to the December 17, 2007 

deadline, and on January 15, 2009, EPA 

found that 37 states, including Michigan 

and Minnesota, had failed to submit 

SIPs addressing the regional haze 

requirements. (74 FR 2392, January 15, 

2009). Once EPA has found that a state 

has failed to make a required 

submission, EPA is required to 

promulgate a FIP within two years 

unless the state submits a SIP and the 

Agency approves it within the two year 

period. CAA § 110(c)(1). 

C. Roles of Agencies in Addressing 

Regional Haze 

Successful implementation of the 

regional haze program will require longterm regional coordination among 

states, tribal governments and various 

federal agencies. As noted above, 

pollution affecting the air quality in 

Class I areas can be transported over 

long distances, even hundreds of 

kilometers. Therefore, to effectively 

address the problem of visibility 

impairment in Class I areas, states, or 

the EPA when implementing a FIP, need 

to develop strategies in coordination 

with one another, taking into account 

the effect of emissions from one 

jurisdiction on the air quality in 

another. 

Because the pollutants that lead to 

regional haze can originate from sources 

located across broad geographic areas, 

EPA has encouraged the states and 

tribes across the United States to 

address visibility impairment from a 

regional perspective. Five regional 

planning organizations (RPOs) were 

developed to address regional haze and 

related issues. The RPOs first evaluated 

technical information to better 

understand how their states and tribes 

impact Class I areas across the country, 

and then pursued the development of 

regional strategies to reduce emissions 

of particulate matter (PM) and other 

pollutants leading to regional haze. 

IV. Requirements for a Regional Haze 

FIP 

The following is a summary of the 

requirements of the Regional Haze Rule. 

See 40 CFR 51.308 for further detail 

regarding the requirements of the rule. 

A. The CAA and the Regional Haze Rule 

Regional haze FIPs must assure 

Reasonable Progress towards the 

national goal of achieving natural 

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5The set of ‘‘major stationary sources’’ potentially 

subject to BART is listed in CAA section 169A(g)(7), 

and includes ‘‘taconite ore processing facilities.’’ 

6BART-eligible sources are those sources that 

have the potential to emit 250 tons or more of a 

visibility-impairing air pollutant, were not in 

operation prior to August 7, 1962, but were in 

existence on August 7, 1977, and whose operations 

fall within one or more of 26 specifically listed 

source categories. 40 CFR 51.301. 

visibility conditions in Class I areas. 

Section 169A of the CAA and EPA’s 

implementing regulations require states, 

or EPA when implementing a FIP, to 

establish long-term strategies for making 

Reasonable Progress toward meeting 

this goal. The FIP must also give 

specific attention to certain stationary 

sources that were in existence on 

August 7, 1977, but were not in 

operation before August 7, 1962, and 

require these sources, where 

appropriate, to install BART controls for 

the purpose of eliminating or reducing 

visibility impairment. The specific 

regional haze FIP requirements are 

discussed in further detail below. 

B. EPA’s Authority To Promulgate a FIP 

Under section 110(c) of the Act, 

whenever we find that a State has failed 

to make a required submission we are 

required to promulgate a FIP. 

Specifically, section 110(c) provides: 

(1) The Administrator shall 

promulgate a Federal implementation 

plan at any time within 2 years after the 

Administrator— 

(A) finds that a State has failed to 

make a required submission or finds 

that the plan or plan revision submitted 

by the State does not satisfy the 

minimum criteria established under 

[section 110(k)(1)(A)], or 

(B) disapproves a State 

implementation plan submission in 

whole or in part, unless the State 

corrects the deficiency, and the 

Administrator approves the plan or plan 

revision, before the Administrator 

promulgates such Federal 

implementation plan. Section 302(y) 

defines the term ‘‘Federal 

implementation plan’’ in pertinent part, 

as: 

[A] plan (or portion thereof) promulgated 

by the Administrator to fill all or a portion 

of a gap or otherwise correct all or a portion 

of an inadequacy in a State implementation 

plan, and which includes enforceable 

emission limitations or other control 

measures, means or techniques (including 

economic incentives, such as marketable 

permits or auctions or emissions 

allowances)* * *. 

Thus, because the Michigan and 

Minnesota failed to adequately establish 

BART limits for its subject taconite ore 

processing facilities we are required to 

promulgate a FIP. 

C. Best Available Retrofit Technology 

(BART) 

Section 169A of the CAA directs 

states, or EPA if implementing a FIP, to 

evaluate the use of retrofit controls at 

certain larger, often uncontrolled, older 

stationary sources in order to address 

visibility impacts from these sources. 

Specifically, section 169A(b)(2)(A) of 

the CAA requires EPA to implement a 

FIP to contain such measures as may be 

necessary to make Reasonable Progress 

toward the natural visibility goal, 

including a requirement that certain 

categories of existing major stationary 

sources 5 built between 1962 and 1977 

procure, install, and operate the ‘‘Best 

Available Retrofit Technology’’ as 

determined by EPA. Under the Regional 

Haze Rule, EPA is directed to conduct 

BART determinations for such ‘‘BARTeligible’’ sources that may be 

anticipated to cause or contribute to any 

visibility impairment in a Class I area. 

On July 6, 2005, EPA published the 

Guidelines for BART Determinations 

Under the Regional Haze Rule at 

appendix Y to 40 CFR part 51 

(hereinafter referred to as the ‘‘BART 

Guidelines’’) to assist states, or EPA if 

implementing a FIP, in determining 

which of their sources should be subject 

to the BART requirements and in 

determining appropriate emission limits 

for each applicable source. (70 FR 

39104, July 6, 2005). In making a BART 

determination for a fossil fuel-fired 

electric generating plant with a total 

generating capacity in excess of 750 

megawatts (MW), EPA must use the 

approach set forth in the BART 

Guidelines. EPA is encouraged, but not 

required, to follow the BART Guidelines 

in making BART determinations for 

other types of sources. Regardless of 

source size or type, EPA must meet the 

requirements of the CAA and our 

regulations for selection of BART, and 

EPA’s BART analysis and determination 

must be reasonable in light of the 

overarching purpose of the regional 

haze program. 

The process of establishing BART 

emission limitations can be logically 

broken down into three steps: First, EPA 

identifies those sources which meet the 

definition of ‘‘BART-eligible sources’’ 

set forth in 40 CFR 51.301; 6 second, 

EPA determines which of such sources 

‘‘emits any air pollutant which may 

reasonably be anticipated to cause or 

contribute to any impairment of 

visibility in any such area’’ (a source 

which fits this description is ‘‘subject to 

BART’’); and third, for each source 

subject to BART, EPA then identifies the 

best available type and level of control 

for reducing emissions. 

States, or EPA if implementing a FIP, 

must address all visibility-impairing 

pollutants emitted by a source in the 

BART determination process. The most 

significant visibility impairing 

pollutants are SO2, NOX, and PM. 

A regional haze FIP must include 

source-specific BART emission limits 

and compliance schedules for each 

source subject to BART. Once EPA has 

made its BART determination, the 

BART controls must be installed and in 

operation as expeditiously as 

practicable, but no later than five years 

after the date of the final FIP. CAA 

section 169(g)(4) and 40 CFR 

51.308(e)(1)(iv). In addition to what is 

required by the Regional Haze Rule, 

general SIP, or FIP, requirements 

mandate that the SIP, or FIP, must also 

include all regulatory requirements 

related to monitoring, recordkeeping, 

and reporting for the BART controls on 

the source. See CAA section 110(a). 

V. EPA’s BART Analysis of Michigan 

and Minnesota’s Taconite Facilities 

A. Sources Subject to BART 

EPA agrees with Michigan and 

Minnesota with respect to the taconite 

facilities that the States determined to 

be subject to BART. These 

determinations are included in 

Minnesota’s December 2009 Regional 

Haze Plan and Michigan’s November 

2010 Regional Haze Plan. EPA also 

agrees with the States’ determination 

that BART for direct PM is satisfied by 

the taconite maximum achievable 

control technology (MACT) rule. See, 

National Emission Standards for 

Hazardous Air Pollutants: Taconite Iron 

Ore Processing, 40 CFR part 63, subpart 

RRRRR. The primary sources that have 

been specifically identified as being 

subject to BART and requiring an 

analysis to establish BART are the 

taconite pelletizing, or indurating, 

furnaces identified in Table V–A.1. 

While they mean the same thing, we 

have chosen to refer to these furnaces as 

indurating furnaces or pelletizing 

furnaces in a manner consistent with 

how they are referred to by the States. 

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TABLE V–A.1—LIST OF TACONITE FACILITIES

State Company Unit 

Minnesota ........................................................... U.S. Steel, Minntac .......................................... Grate-Kiln Lines 3–7. 

Minnesota ........................................................... Northshore Mining Company ........................... Straight-Grate Furnaces 11 and 12. 

Minnesota ........................................................... United Taconite ................................................ Grate-Kiln Lines 1 and 2. 

Minnesota ........................................................... ArcelorMittal Steel ............................................ 1 Straight-Grate. 

Minnesota ........................................................... Hibbing Taconite .............................................. Straight-Grate Lines 1–3. 

Minnesota ........................................................... U.S. Steel, Keetac ........................................... 1 Grate-Kiln. 

Michigan ............................................................. Tilden Mining .................................................... Grate-Kiln Line 1. 

The U.S. taconite iron ore industry 

uses two types of pelletizing machines 

or processes: Straight-grate and gratekiln. A significant difference is that 

straight-grate kilns do not burn coal and 

they therefore have a much lower 

potential for emitting SO2.

In the straight-grate kiln, a continuous 

bed of agglomerated green pellets is 

carried through different temperature 

zones with upward draft or downward 

draft blown through the pellets on the 

metal grate. Pellet residence time inside 

the machine is about 40 minutes. Fuel 

combustion chambers supply hot flue 

gas to a zone in the middle portion of 

the machine (combustion zone). (In 

order to make fully fluxed pellets, 

auxiliary burners need to be added to 

the preheating zone.) Fired pellets are 

cooled on the remaining portion of the 

machine. To protect the metal grate and 

other parts of the machine, about 20 

percent of the cooled, fired pellets are 

used to make a hearth layer at the 

bottom and two sides of the pellet bed. 

For the straight-grate kiln, used 

process gas consists of exhaust gas from 

the updraft drying zone and exhaust gas 

closer to the firing zone. The former can 

be called ‘‘hood exhaust’’ and the latter 

‘‘windbox exhaust.’’ For many straightgrate kilns, both hood exhaust and 

windbox exhaust are directed to one 

common header. The common exhaust 

header has one ‘‘hot side’’ inlet to 

receive windbox exhaust and one ‘‘cold 

side’’ inlet to receive hood exhaust. 

From the common exhaust header, the 

exhaust gas is vented through four 

parallel stacks, which are outfitted with 

air pollution control equipment. For 

some older machines, two separate 

common headers are used to vent hood 

exhaust and windbox exhaust. The hood 

exhaust header vents through three 

stacks, and the wind exhaust (often 

referred to as ‘‘waste gas’’) header vents 

through two stacks. 

Gases are passed numerous times 

through the pellet bed in order to heat 

and cool the pellets as they pass along 

a large grate. ‘‘Windbox exhaust’’ gases 

are derived from the down draft and 

preheat zones, but are passed through 

multiclone dust collectors before 

entering the wet scrubber/exhaust 

system. ‘‘Hood exhaust’’ gases from the 

updraft drying zone originate from the 

second cooling zone and pass directly 

into the wet scrubber/exhaust system. 

Windbox and hood exhaust gases 

partially mix in a common header 

before being vented to the atmosphere 

through a series of four stacks. 

The grate-kiln system actually 

consists of a traveling grate, a rotary 

kiln, and an annular cooler. Pellet 

residence time inside the system is 

about 55 minutes (less than 10 minutes 

in the grate, about 20 minutes in the 

kiln, and about 30 minutes in the 

cooler). The grate-kiln system does not 

need a hearth layer for the grate, which 

handles only drying and preheating. 

The rotary kiln does not need a hearth 

layer, either, because it is lined with 

refractory material. One waste gas stack, 

or two side-by-side waste gas stacks, is 

used for the grate-kiln system. 

Combustion gases for heating the 

pellets are directed up a large rotating 

kiln and then down through the pellet 

bed in the preheat zone. The gases are 

then used for initial heating and drying 

of the green pellet feed. Gases used for 

cooling the hot pellets are also used to 

dry and heat the pellets. Depending on 

the operation, the waste gases are 

passed through one or more scrubbers 

and vented through one or more 

separate stacks. 

It is very common to use intermediate 

cyclones to clean the gas stream in the 

straight grate and grate-kiln pelletizers, 

as it is ducted to various locations in the 

grate. The cyclones protect the blades of 

gas movers (fans) and recover good 

materials (particles of high iron 

content). Inclined plates are also used 

along with periodic water wash to 

remove ‘‘solid spills’’ under the grate to 

recover the iron units. These measures 

also help reduce dust loading near the 

waste gas stack, even though they are 

not considered air pollution control 

equipment. 

B. BART Five-Factor Determinations 

and Proposed FIP Emission Limits for 

NOX and SO2

EPA proposes to find that BART for 

NOX for indurating furnaces is low NOX

burners for both straight-grate and gratekilns. The feasibility of using low NOX

burners on grate-kilns is based on an 

October 26, 2011 ‘‘Summary Report for 

USS On NOX reduction for Kilns #6 and 

7’’ by S. Londerville, which documents 

a baseline of 4 pounds per million 

British Thermal Units (lbs/MMBtu) 

when burning gas; the December 1, 2011 

‘‘U.S. Steel Minntac Line 6 Low NOX

Main Burner Final Report & Facility 

NOX Management,’’ which states that 

there has been neither an increase in 

fuel consumption nor degradation of 

pellet quality with the use of a low NOX

burner; and continuous emission 

monitoring system (CEMS) data from 

U.S. Steel Minntac Line 6. These data 

support a limit of 1.2 lbs/MMBtu on a 

30-day rolling average. Also, costcalculations for Minntac’s Line 6 result 

in cost-effectiveness values of $441/ton 

of NOX reduced when burning coal and 

gas and $210/ton of NOX reduced when 

burning gas. 

In a July 2, 2012, conversation with 

U.S. Steel and COEN, EPA discussed the 

potential for any negative issues 

associated with the use of Minntac’s low 

NOX burners. During this conversation 

it was stated that although there was 

initially an increase in fuel use, that 

increase has been eliminated so there is 

not an increase in MMBtu/ton of NOX

emitted. There is also no increase in 

combustion related emissions, such as 

carbon monoxide or volatile organic 

compounds, and there is no reason for 

SO2 emissions to increase through use 

of a low NOX burner. There is a small 

(less than 1 MW/hr) increase in 

electricity use and no increase in water 

use. U.S. Steel was certain that there 

was absolutely no product/pellet 

degradation. Some of their pellets are 

shipped to other (non-U.S. Steel) 

customers and some are shipped a long 

distance so there can be no slip (e.g. 

pellet degradation) in quality. The July 

2, 2012 conversation also included 

discussion of installation schedules 

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49312 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

7The MPCA organizes conditions and illustrates 

associations in its permits using the Emission Unit 

(EU), Control Equipment (CE), and Stack/Vent (SV) 

numbers. 

during which it was stated that 

engineering for adding additional 

burners would be expected to take about 

6 months, although engineering could 

be combined for installation of more 

than one burner. Installation of new low 

NOX burners would need to be timed 

with line outages, which typically occur 

about 6 months apart, and could take 

about a year. 

The feasibility of low NOX burners on 

straight-grate kilns is documented in a 

September 19, 2011 summary of 

findings presented to the Minnesota 

Pollution Control Board titled ‘‘Results 

of Testing at 1⁄4-Scale of LE Low NOX

Burner Prototype for Straight-Grate 

Pelletizing Furnaces’’ by Fives North 

American Combustion, Inc. (Fives) for 

Essar (formerly Minnesota) Steel (Essar), 

and in presentations made at the April 

17 and 18, 2012 Society for Mining, 

Metallurgy and Exploration meeting in 

Duluth, Minnesota. These presentations 

were ‘‘Reducing NOX from Pelletizing 

Furnaces,’’ by Fives and 

‘‘Environmental Benefits for the 

Adaptation of Commonly Used LowNOX Burner Technology to a StraightGrate Natural Gas Fired Taconite 

Indurating Furnace,’’ by Lori L. Stegink, 

from Barr Engineering and Kevin 

Kangas from Essar. These presentations 

revealed that Essar and Fives first 

examined the applicability of numerous 

traditional methods for reducing NOX

from combustion as well as posttreatment methods for NOX removal. 

This was followed by successful benchscale testing of Fives low NOX LE 

burners to achieve NOX reductions 

greater than 70 percent in a straightgrate pelletizing furnace. Therefore 

Essar and Fives proceeded with a joint 

$2 million investment in a test rig to 

simulate a straight-grate pelletizing 

furnace. In the 1⁄4-scale test rig, the cross 

sectional area scaling was very 

representative of actual furnace 

geometry, as were the energy inputs and 

flows. This testing demonstrated a 90 

percent reduction in NOX emissions and 

a rate of 0.25 lbs. NOX/MMBtu at an 

estimated cost-effectiveness of $370/ton. 

Based on the results of this test program, 

it was concluded that NOX emissions in 

the actual furnace should be consistent 

with those measured in the 1⁄4 scale test 

conditions. Subsequent conversations 

with representatives of Essar and Fives 

indicated that an increase in fuel use 

and emissions from other pollutants is 

not anticipated and that the type of 

furnace that Essar will be using is the 

most difficult design for NOX control. 

Based on the range of cost-effectiveness 

values provided, a conservative value of 

$500/ton will be used as the costeffectiveness value for low NOX burners. 

EPA proposes to determine that BART 

for SO2 for straight-grate kilns is existing 

controls because these furnaces do not 

burn coal. EPA also proposes to find 

that BART for SO2 is existing controls 

at Keetac and Minntac because the costeffectiveness of additional controls is 

excessive due to the amount of coal 

fired, the sulfur content of the coal used 

there and their existing controls. 

For Tilden Line 1 and United 

Taconite’s Lines 1 and 2, EPA is 

proposing to determine that a dry fluegas desulfurization (FGD) system (for 

United Taconite’s Lines 1 and 2), and 

either a wet or dry FGD system at 

Tilden, with an emission rate of 5 parts 

per million by volume (ppmv) of SO2, 

or a 95 percent emission reduction 

requirement, on a 30-day rolling 

average, has been determined to be 

BART for SO2. The cost-effectiveness of 

these controls has been determined 

based upon EPA’s Air Pollution Control 

Cost Manual, information provided in 

Tilden’s and United Taconite’s BART 

determinations, information on existing 

operating costs supplied by United 

Taconite and a summary of information 

provided on capital and operating costs 

as well as the SO2 emission rate 

provided by FGD manufacturers. 

Also, there is no indication that the 

useful life of any of these facilities is 

less than 20 years. 

BART analyses conducted for each of 

the subject facilities are presented 

below. EPA will carefully consider any 

comments that disagree with any of its 

facts or conclusions. It should be noted, 

however, that more weight will be 

provided to fact-based comments such 

as test results or vendor quotes and less 

to unsubstantiated engineering 

estimates or opinions. 

Please note that in the following 

analyses, unless otherwise specified, 

information related to the technical and 

economic feasibility of various controls 

was provided in Minnesota’s December 

30, 2009 Regional Haze SIP submission 

and reflects information provided in the 

company specific BART analyses. The 

same is also true for Michigan and 

Tilden. 

1. U.S. Steel Minntac 

U.S. Steel Minnesota Ore Operations 

(Minntac) operates five grate-kiln 

indurating furnaces which are identified 

in table V–B.1 below. 

TABLE V–B.1 MINNTAC EMISSION UNITS

Emission unit name EU No.7 Control equipment 

and stack numbers 

Line 3 Indurating Furnace ....................................................................................................................... EU225 CE146/SV103 

Line 4 Indurating Furnace ....................................................................................................................... EU261 CE103/SV118 

Line 5 Indurating Furnace ....................................................................................................................... EU282 CE113/SV127 

Line 6 Indurating Furnace ....................................................................................................................... EU315 CE126/SV144 

Line 7 Indurating Furnace ....................................................................................................................... EU334 CE136/SV151 

a. NOX BART Analysis 

Step 1: Identify all Available Retrofit 

Control Technologies 

The following NOX retrofit control 

technologies have been identified as 

being available for indurating furnaces: 

• External Flue Gas Recirculation, 

• Low NOX Burners, 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Ported Kilns, 

• Alternate Fuels, and 

• Selective Catalytic Reduction (SCR). 

Step 2: Eliminate Technically Infeasible 

Options 

Minntac eliminated External Flue Gas 

Recirculation and Induced Flue Gas 

Recirculation Burners from 

consideration since they were 

technically infeasible for the specific 

application to pellet furnaces due to the 

high oxygen content of the flue gas. 

Minntac eliminated Energy Efficiency 

Projects due to the difficulty of 

assigning a general potential emission 

reduction for this category. Minntac 

noted in their analysis that the facility 

has already implemented several energy 

efficiency projects and that it will 

continue to evaluate and implement 

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Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 49313 

8See September 8, 2006 BART analysis submitted 

to MPCA by U.S. Steel, http://www.pca.state.mn.us/ 

index.php/view-document.html?gid=2228. 

energy efficiency projects. Minntac 

eliminated Alternative Fuels because 

the environmental and economic 

benefits of such a change are uncertain 

and Minntac believes that this option is 

not mandated by EPA. Also, U.S. Steel 

documented the infeasibility of SCR 

controls. Two SCR vendors declined to 

bid on NOX reduction testing at 

Minntac. EPA agrees that SCR controls 

are infeasible for indurating furnaces. 

The remaining technologies, considered 

by Minntac to be technically feasible, 

include: 

• Low NOX burners, 

• Low NOX burners + Ported kilns 

(Lines 4 and 5), and 

• Ported kilns (Lines 3, 4, and 5— 

kilns on lines 6 and 7 are already 

ported). 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

The following tables illustrate the 

assumed control efficiencies and the 

projected NOX emission reductions 

projected by Minntac with the 

technically feasible control 

technologies. 

TABLE V–B.2—PELLET FURNACE PROJECTED NOX EMISSION REDUCTIONS

[TPY] 

NOX Control technology 

Assumed 

control 

efficiency 

(percent) 

Line 3 Line 4 Line 5 Line 6 Line 7 

None (Baseline) ....................................... ........................ 1,345 1,812 1,820 1,776 1,928 

Low NOX burners + Ported kilns ............. 15 na 249 273 na na 

Low NOX burners ..................................... 10 na 181 182 na 193 

Ported kilns .............................................. 5 67 91 91 na na 

Step 4: Evaluate Impacts and Document 

the Results 

Minntac’s estimates of the annualized 

pollution control cost of operating the 

various control technologies are shown 

in the following table. 

TABLE V–B.3—PELLET FURNACE PROJECTED NOX CONTROL COST

[$/Ton] 

NOX Control technology Line 3 Line 4 Line 5 Line 6 Line 7 

Low NOX burners + Ported kilns ......................................... na $5,844 $5,974 na na 

Low NOX Burners ................................................................ na 768 765 na $588 

Ported kilns .......................................................................... $5,076 5,209 5,186 na na 

Step 5: Evaluate Visibility Impacts 

See Section V.C. 

Step 6: Propose BART 

EPA is proposing a limit of 1.20 lbs/ 

MMBtu on a 30-day rolling average for 

all lines to be achieved as follows: 1 

year after the effective date of this rule 

for line 6, 2 years after the effective date 

for Line 7, 3 years after the effective date 

for Line 4, 4 years after the effective date 

for Line 5 and 4 years, and 11 months 

after the effective date for Line 3. 

b. SO2 BART Analysis 

Lines 3, 4, and 5 can burn natural gas, 

wood and fuel oil, but natural gas and 

wood are used most frequently. Since 

these fuels are low in sulfur, the 

primary source of sulfur in these 

furnaces is the iron ore used to form the 

pellets. Additional sulfur may be 

present in the additives used in the 

pellets. In addition to natural gas, wood, 

and fuel oil, coal is used in Lines 6 

and 7. 

The lines are controlled by wet 

scrubbers designed to remove PM. Since 

collateral SO2 reductions occur within 

the existing wet scrubbers, they are 

considered low efficiency SO2

scrubbers. Minntac estimates that these 

existing scrubbers remove 15 to 30 

percent of the SO2 in the exhaust gas 

from these lines. 

Step 1: Identify all Available Retrofit 

Control Technologies 

Minntac identified the following SO2

retrofit control technologies:8

• Wet Walled Electrostatic 

Precipitator (WWESP), 

• Wet Scrubbing (High and Low 

Efficiency), 

• Dry Sorbent Injection (Dry 

Scrubbing Lime/Limestone Injection), 

• Spray Dryer Absorption, 

• Energy Efficiency Projects, 

• Alternate Fuels, and 

• Coal Processing. 

Step 2: Eliminate Technically Infeasible 

Options 

Minntac eliminated Dry Sorbent 

Injection, Spray Dryer Absorption, 

Alternative Fuels, and Coal Drying from 

consideration due to technical 

infeasibility. With Dry Sorbent Injection 

and Spray Dryer Absorption, the high 

moisture content of the exhaust would 

lead to saturation of the baghouse filter 

cake and plugging of the filters and the 

dust collection system. To achieve a 

reduction of SO2 emissions through 

alternative fuel usage, the source must 

switch from a high sulfur fuel to a lower 

sulfur fuel. Lines 3, 4, and 5 are burning 

natural gas and wood, both of which are 

low in sulfur. Lines 7 and 8 are allowed 

to burn coal. Due to the uncertainty of 

alternative fuel costs, the potential of 

replacing one visibility impairment 

pollutant for another, and the fact that 

BART cannot mandate a fuel switch, 

Minntac did not evaluate this option 

further. Coal drying requires a source of 

excess heat or low pressure steam. This 

heat source is not available at the 

Minntac facility so coal drying was 

found to be technically infeasible. 

In addition, Minntac has already 

implemented Energy Efficiency Projects. 

The company indicated that the 

potential fuel reductions and the 

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49314 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

commensurate emission reductions for 

future Energy Efficiency Projects cannot 

accurately be predicted without specific 

details; since no particular project has 

been envisioned, the company did not 

evaluate this option any further. 

Minntac evaluated the possibility of 

improving the SO2 removal efficiency of 

the existing scrubbers through the 

additions of caustic, lime, or limestone 

in the scrubber water to raise the pH. 

The existing scrubbers on lines 3–7 

currently operate at a neutral pH. The 

scrubbers, piping, pumps, and water 

tanks were not designed to operate at a 

higher pH so corrosion of the system 

would be a concern. Also, the additions 

and increased SO2 removal would create 

additional solids and sulfates in the 

scrubber discharged to the tailings 

basin. This would require substantial 

and expensive treatment to maintain an 

acceptable water quality which could be 

discharged through the existing 

National Pollutant Discharge 

Elimination System permit. The new 

scrubber on Line 3 is a recirculating 

scrubber which operates at a pH that is 

typically less than 7. The scrubber was 

operated temporarily at a higher pH, but 

plugging and other operational 

problems resulted. Based on these 

concerns, Minntac found the 

improvement of SO2 removal efficiency 

of the existing scrubbers to be 

impractical and did not further consider 

this option. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Minntac estimated the control 

efficiency of WWESPs to be 

approximately 80 percent. A secondary 

wet scrubber was estimated to control 

roughly 60 percent of the SO2 remaining 

after the existing scrubber. The 

following tables illustrate the SO2

emission reductions projected by 

Minntac with the technically feasible 

control technologies. 

TABLE V–B.4—ANNUAL SO2 EMISSIONS

[TPY] 

Line 3 Line 4 Line 5 Line 6 Line 7 Total 

Baseline SO2 Emissions .......................... 329.4 447.5 447.5 544.8 544.8 2314 

TABLE V–B.5—PROJECTED SO2 EMISSION REDUCTIONS

[TPY] 

SO2 Control technology Line 3 Line 4 Line 5 Line 6 Line 7 Total 

WWESP ................................................... 263.5 358.0 358.0 435.9 435.9 1851.3 

Secondary Wet Scrubber ......................... 197.6 268.5 268.5 326.9 326.9 1388.4 

Step 4: Evaluate Impacts and Document 

the Results 

Cost of Control 

Minntac estimated the annualized 

pollution control cost of installing and 

operating WWESPs on Lines 3, 4, and 5 

to be between $20,000 and $24,000 per 

ton of SO2 removed. The cost of 

installing and operating a secondary wet 

scrubber on these lines was estimated to 

be between $14,000 and $16,000 per ton 

of SO2 removed. The annualized 

pollution control cost of installing and 

operating WWESPs on Lines 6 and 7 

was estimated to be approximately 

$18,000 per ton of SO2 removed. The 

cost of installing and operating a 

secondary wet scrubber on these lines 

was estimated to be between 

approximately $12,000 per ton of SO2

removed. 

Energy and Non-Air Quality 

Environmental Impacts 

There are no energy or non-air quality 

impacts because, as discussed above 

and in the Step 6 discussion, no 

additional controls were determined to 

be required. 

Step 5: Evaluate Visibility Impacts 

Additional SO2 controls for Minntac 

are not reasonably cost effective, so 

visibility impacts were not modeled for 

additional SO2 controls. 

Step 6: Propose BART 

Although we do not agree that the 

Minnesota Pollution Control Agency 

(MPCA) and Minntac have adequately 

documented the infeasibility of all of 

the SO2 controls described above, we 

agree that additional SO2 controls are 

not economically reasonable and are, 

therefore, not necessary for BART. EPA 

is proposing to determine that BART is 

existing controls. Based on CEM data 

provided by Minntac for 2010, 2011, 

and part of 2012, EPA is proposing the 

following limits: 71.3 lb SO2/hr for Line 

3, 56.1 lb SO2/hr for Line 4, 67.9 lb SO2/ 

hr for Line 5, 64.5 lb SO2/hr for Line 6, 

and 67.1 lb SO2/hr for Line 7. These 

limits are measured on a 30-day rolling 

average and compliance is required 

within 30 days after the effective date of 

this rule. 

c. Non-Furnace BART Analysis 

Minntac also operates four heating 

boilers that are subject to a full BART 

analysis. The facility’s two Step I 

Heating Boilers (#1 and #2) are each 

rated at 104 MMBtu/hr and the two Step 

III Heating Boilers (#4 and #5) are rated 

at 153 MMBtu/hr. Each boiler is capable 

of burning natural gas and fuel oil. 

Step 1: Identification of Available 

Retrofit Control Technologies 

The following NOX retrofit control 

technologies have been identified as 

being available for the heating boilers: 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• LNB with Overfire Air (LNB/OFA), 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Alternate Fuels, 

• Low Temperature Oxidation, 

• Selective Catalytic Reduction, 

• Regenerative SCR, and 

• Selective Non-Catalytic Reduction. 

Step 2: Eliminate Technically Infeasible 

Options 

Minntac eliminated External Flue Gas 

Recirculation from consideration since 

it was technically infeasible for the 

boilers based on Minntac staff judgment 

that the existing fireboxes for the boilers 

would be unable to accommodate longer 

flame length to avoid flame 

impingement. Minntac eliminated 

energy efficiency projects due to the 

difficulty of assigning a general 

potential emission reduction for this 

category, but stated that Minntac will 

continue to evaluate and implement 

energy efficiency projects. Minntac 

eliminated alternative fuels because the 

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environmental and economic benefits of 

such a change are uncertain, the limited 

fuel options available, and the fact that 

natural gas is the typical fuel burned in 

the boilers. Minntac stated that it would 

continue to evaluate and implement 

alternative fuel usage as feasible. 

Step 3: Evaluation of the Control 

Effectiveness of the Remaining Control 

Technologies 

The following table illustrates the 

assumed control efficiencies and the 

projected NOX emission reductions 

projected by Minntac with the 

technically feasible control 

technologies. 

TABLE V–B.6—HEATING BOILER PROJECTED NOX EMISSION REDUCTIONS

[TPY] 

NOX Control technology Control 

efficiency 

Boilers 

#1, #2, #4, #5 Emissions Cost 

None (Baseline) ....................................................................... 13.8–14.8 56.7 

Low Temperature Oxidation .................................................... 90% 12.4–13.3 5.7 $23,668–$27,713 

SCR ......................................................................................... 80% 11.0–11.8 11.3 $50,632-$60,211 

LNB/Flue gas recirculation ...................................................... 75% 10.4–11.1 14.2 $15,558–$20,299 

Regenerative SCR ................................................................... 70% 9.7–10.4 17.0 $22,879–$30,710 

LNB/Overfire Air ....................................................................... 67% 9.2–9.9 18.7 $14,282–$18,634 

Low NOX Burner ...................................................................... 50% 6.9–7.4 28.3 $6,653–$8,646 

Selective Non-Catalytic Reduction .......................................... 50% 6.9–7.4 28.3 $42,037–$51,494 

Step 4: Evaluate Impacts and Document 

the Results 

The NOX emissions generated by the 

four heating boilers at the Minntac 

facility total 56.7 TPY. The most cost 

efficient control is low NOX burners at 

$6,653 to $8,646 per ton, which would 

yield a 28.4 TPY reduction. 

Step 5: Evaluate Visibility Impacts 

Additional NOX controls are not 

required because they are not 

reasonably cost-effective. Therefore 

there are no resulting visibility impacts. 

Step 6: Propose BART 

Given that the control options result 

in modest reductions in NOX emissions 

on a TPY basis, that modest reduction 

would need to provide a strong 

visibility improvement or be trivial in 

cost to justify a BART limit indicative 

of additional control. That is not the 

case for the Minntac heating boilers. 

Minntac’s current Title V permit 

(13700005—002) does not include NOX

emission limits for the heating boilers. 

Thus, EPA is not proposing a NOX

emission limit for the Minntac heating 

boilers. EPA is proposing to determine 

that the existing operational 

requirements, including fuels (natural 

gas with fuel oil as back up) and 

compliance requirements in the existing 

permits are NOX BART for the Minntac 

heating boilers. 

2. Northshore Mining 

Northshore operates two straight-grate 

indurating furnaces which are identified 

in Table V–B.7 below. 

TABLE V–B.7—NORTHSHORE EMISSION UNITS

Emission unit name EU No. Control equipment and stack numbers 

Indurating Furnace #11—Hood Exhaust .................................... EU100 CE101/SV101, CE102/SV102, CE103/SV103. 

Indurating Furnace #11—Waste Gas ......................................... EU104 CE104/SV104, CE105/SV105. 

Indurating Furnace #12—Hood Exhaust .................................... EU110 CE111/SV111, E112/SV112, CE113/SV113. 

Indurating Furnace #12—Waste Gas ......................................... EU114 CE114/SV114, CE115/SV115. 

a. NOX BART Analysis 

Step 1: Identify All Available Retrofit 

Control Technologies 

The following NOX retrofit control 

technologies have been identified as 

being available for indurating furnaces: 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Ported Kilns, 

• Alternate Fuels, and 

• Selective Catalytic Reduction. 

Step 2: Eliminate Technically Infeasible 

Options 

Northshore eliminated External Flue 

Gas Recirculation and Induced Flue Gas 

Recirculation Burners from 

consideration since they were 

technically infeasible for the specific 

application to pellet furnaces due to the 

high oxygen content of the flue gas. 

Northshore eliminated Energy 

Efficiency Projects due to the difficulty 

of assigning a general potential emission 

reduction for this category. The 

company has already implemented 

several energy efficiency projects and 

will continue to evaluate and 

implement energy efficiency projects. 

Northshore’s use of straight grate 

indurating furnaces makes the use of 

Ported Kilns infeasible, since they can 

be used only at grate-kiln furnaces. 

Northshore eliminated Alternative Fuels 

because the environmental and 

economic benefits of such a change are 

uncertain and Northshore believes that 

this option is not mandated by EPA. In 

addition, Northshore’s furnace is 

currently incapable of handling solid 

fuels. Also, U.S. Steel documented the 

infeasibility of SCR controls. (see 

section V.B.1.a., above). 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

The following table illustrates the 

NOX emission baseline for Northshore 

and the reductions achievable using low 

NOX burners. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS5

49316 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

9See BART analysis submitted to MPCA by 

Northshore Mining Company in September 2006, 

http://www.pca.state.mn.us/index.php/viewdocument.html?gid=2225. 

TABLE V–B.8—PROJECTED ANNUAL NOX EMISSION REDUCTION

[TPY] 

NOX Control Assumed 

control 

Furnace 11 Furnace 12 

Hood exhaust Waste gas Hood exhaust Waste gas 

None (Baseline) ......................................................... .......................... 112 .4 273 .7 109 .9 267 .7 

Low NOX Burners ...................................................... 70% 79 192 77 187 

Step 4: Evaluate Impacts and Document 

Results 

Cost of Control 

TABLE V–B.9—PELLET FURNACE PROJECTED NOX CONTROL

[Cost per ton of pollutant removed] 

NOX Control Technology Furnace 11 

(hood) 

Furnace 11 

(waste) 

Furnace 12 

(hood) 

Furnace 12 

(waste) 

Low NOX Burners ............................................................................................ $500 $500 $500 $500 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

EPA is proposing a limit of 1.2 lbs/ 

MMBtu on a 30-day rolling average for 

all lines to be achieved as follows: 1 

year and 6 months after the effective 

date for Line 11 and 2 years and 6 

months after the effective date for Line 

12. 

b. SO2 BART Analysis 

Although the indurating furnaces can 

burn both natural gas and fuel oil, 

natural gas is the primary fuel. Since 

natural gas is low in sulfur, the primary 

source of SO2 emissions is from trace 

amounts of sulfur in the iron 

concentrate and binding agents. Sulfur 

is also present in distillate fuel oil. 

Both lines are controlled by wetwalled electrostatic precipitators using 

caustic reagent. 

Step 1: Identify All Available Retrofit 

Control Technologies 

Northshore identified the following 

SO2 retrofit control technologies:9

• Wet-Walled Electrostatic 

Precipitator, 

• Wet Scrubbing (High and Low 

Efficiency), 

• Dry Sorbent Injection (Dry 

Scrubbing Lime/Limestone Injection), 

• Spray Dryer Absorption, 

• Energy Efficiency Projects, 

• Alternate Fuels, and 

• Coal Processing. 

Step 2: Eliminate Technically Infeasible 

Options 

Northshore eliminated Dry Sorbent 

Injection, Spray Dryer Absorption, 

Alternative Fuels, and Coal Drying from 

consideration due to technical 

infeasibility. With Dry Sorbent Injection 

and Spray Dryer Absorption, the high 

moisture content of the exhaust would 

lead to saturation of the baghouse filter 

cake and plugging of the filters and the 

dust collection system. Alternative 

Fuels were eliminated because 

Northshore is prohibited from burning 

solid fuels. Coal Drying is technically 

infeasible because Northshore does not 

burn coal. 

Northshore indicated that the 

potential fuel reductions and the 

commensurate emission reductions for 

future Energy Efficiency Projects cannot 

accurately be predicted without specific 

details. Since no particular project has 

been envisioned, the company did not 

evaluate this option any further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Northshore estimated the control 

efficiency of a secondary WWESP to be 

approximately 80 percent. A secondary 

wet scrubber was estimated to control 

roughly 60 percent of the SO2 remaining 

after the existing scrubber. The 

following tables illustrate the SO2

emission reductions projected by 

Northshore with the technically feasible 

control technologies. 

TABLE V–B.10—ANNUAL SO2 EMISSIONS

[TPY] 

Furnace 11 Furnace 12 

Total 

Hood exhaust Waste gas Hood exhaust Waste gas 

Baseline SO2 Emissions ...................................................... 28.6 9.5 26.3 8.8 73.2 

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Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 49317 

TABLE V–B.11—PROJECTED SO2 EMISSION REDUCTIONS

[TPY] 

SO2 control technology 

Furnace 11 Furnace 12 

Total 

Hood exhaust Waste gas Hood exhaust Waste gas 

WWESP ............................................................................... 22.9 7.6 21.0 7.0 58.5 

Secondary Wet Scrubber ..................................................... 17.2 6.7 15.8 5.3 45.0 

Step 4: Evaluate Impacts and Document 

the Results 

Cost of Control 

Northshore estimated the annualized 

pollution control cost of installing and 

operating secondary WWESPs ranged 

from roughly $180,000 to $540,000 per 

ton of SO2 removed. The cost of 

installing and operating a secondary wet 

scrubber was estimated to be between 

$140,000 and $420,000 per ton of SO2

removed. 

Energy and Non-air Quality 

Environmental Impacts 

Because the cost of additional SO2

controls for Northshore does not meet a 

reasonable definition of cost-effective 

technology, no further evaluation of 

these alternatives was conducted. 

Step 5: Evaluate Visibility Impacts 

Additional SO2 controls for 

Northshore are not reasonably cost 

effective, so visibility impacts were not 

modeled for additional SO2 controls. 

Step 6: Propose BART 

Although we do not agree that MPCA 

and Northshore have adequately 

documented the infeasibility of all of 

the SO2 controls described above, we 

agree that, because Northshore is 

burning natural gas and fuel oil, 

additional SO2 controls are not 

economically reasonable and are, 

therefore, not necessary for BART. EPA 

is proposing to determine that BART is 

existing controls. In its regional haze 

submittal, MPCA also concluded that 

BART was existing controls and set a 

limit of 0.0651 lb SO2/long ton of pellets 

fired (finished) measured on a 30-day 

rolling average. Northshore provided 

2011 performance testing data which 

showed an average production rate of 

250 long ton of pellets fired (finished)/ 

hr for Furnace 11 and 263 long ton of 

pellets fired (finished)/hr for Furnace 

12. Based on these production rates and 

MPCA’s limit, EPA is proposing the 

following limits: 16.3 lb SO2/hr for 

Furnace 11 and 17.1 lb SO2/hr for 

Furnace 12, measured on a 30-day 

rolling average. These limits do not 

apply when the subject emissions unit 

is burning fuel oil. In addition, EPA is 

proposing to require that the emissions 

from SV101, SV102, SV103, SV104, 

SV105, SV111, SV112, SV113, SV114, 

and SV115 for Furnaces 11 and 12 be 

subject to an 80.0 percent emission 

reduction requirement. Compliance is to 

be achieved with these limits within 6 

months after the effective date of this 

rule. 

c. Non-Furnace BART Analysis 

Northshore also operates two process 

boilers that are subject to BART. Both 

process boilers were installed in 1965 

and are rated at 79 MMBtu/hr. The 

boilers are capable of burning fuel oil 

and natural gas. 

Step 1: Identification of Available 

Retrofit Control Technologies 

The following NOX retrofit control 

technologies have been identified as 

being available for the process boilers: 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• Overfire Air, 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Alternate Fuels, 

• Non-Selective Catalytic Reduction, 

• Selective Catalytic Reduction, 

• Regenerative SCR, and 

• Selective Non-Catalytic Reduction. 

Step 2: Elimination of Technically 

Infeasible Options 

Northshore found External Flue Gas 

Recirculation to be technically 

infeasible and eliminated it from further 

consideration because Northshore’s 

process boilers lack the capability 

needed to controlled combustion 

conditions at the boiler tip. Overfire air 

was eliminated due to the small size of 

Northshore’s process boilers and the 

number of burners. Northshore 

eliminated energy efficiency projects 

due to the difficulty of assigning a 

general potential emission reduction for 

this category. However, it has already 

implemented energy efficiency projects 

and it will continue to evaluate and 

implement energy efficiency projects. 

Northshore also rejected alternate fuels, 

as the process boilers burn distillate fuel 

oil and natural gas only. As those fuels 

have low nitrogen content, even a fuel 

alternative with no nitrogen content 

would provide little benefit. Northshore 

also believes that this option is not 

mandated by EPA and furthermore, 

Northshore’s boilers are incapable of 

handling solid fuels. 

Northshore identified low-NOX

burners, induced flue gas recirculation 

burners, selective catalytic reduction, 

and selective non-catalytic reduction as 

the only technically feasible alternative 

from the list above. These technologies 

were then evaluative for costeffectiveness. 

Step 3: Evaluation of the Control 

Effectiveness of the Remaining Control 

Technologies 

The following table illustrates the 

NOX emission reductions projected by 

Northshore with the technically feasible 

technologies. 

TABLE V–B.12—PROJECTED ANNUAL NOX EMISSION REDUCTIONS

[TPY] 

NOX Control technology 

Control 

efficiency 

(percent) 

Emissions Cost 

None (Baseline) ........................................................................................................................... ........................ 41.2 ........................

Selective Catalytic Reduction ...................................................................................................... 90 4.1 $30,160 

Low-NOX Burners w/Induced Flue Gas Recirculation ................................................................. 75 10.3 10,675 

Low-NOX Burners ........................................................................................................................ 50 20.6 723 

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49318 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

TABLE V–B.12—PROJECTED ANNUAL NOX EMISSION REDUCTIONS—Continued 

[TPY] 

NOX Control technology 

Control 

efficiency 

(percent) 

Emissions Cost 

Selective Non-Catalytic Reduction .............................................................................................. 50 20.6 12,126 

Step 4: Evaluate Impacts and Document 

Results 

The NOX emissions generated by the 

two process boilers are of modest size, 

totaling 41.2 TPY. The most cost 

efficient control is low NOX burners at 

$723 per ton, which would produce a 

20.6 TPY emission reduction for each 

unit. 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

Low NOX burners will reduce 

emissions from the process boilers at a 

modest cost, estimated at $723 per ton 

by Northshore. This control will reduce 

20.6 TPY of NOX emissions from each 

process boiler unit. Although the total 

41.2 ton annual reduction is modest, the 

low cost of adding the control, on a per 

ton and total cost bases, makes it 

reasonable. Thus, EPA is proposing a 

NOX emission limit of 0.085 lb/MMBtu 

on a 30-say rolling average for 

Northshore Mining’s Process Boiler #1 

and Process Boiler #2. Compliance is to 

be achieved with this limit within 5 

years after the effective date of this rule. 

This represents the BART emission 

limit when low NOX burners are added 

to each boiler unit. 

3. United Taconite 

United Taconite operates two gratekilns which are identified in Table V– 

B.13 below. 

TABLE V–B.13—UNITED TACONITE EMISSION UNITS

Emission unit name EU No. Control equipment and stack numbers 

Line 1 Pellet Induration ................................................................ EU40 ........... SV046 

Line 2 Pellet Induration ................................................................ EU42 ........... SV048, SV049 

a. NOX BART Analysis 

Step 1: Identify All Available Retrofit 

Control Technologies 

United Taconite identified the 

following NOX retrofit control 

technologies as being available for 

indurating furnaces: 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Ported Kilns, 

• Alternate Fuels, and 

• Selective Catalytic Reduction. 

Step 2: Eliminate Technically Infeasible 

Options 

United Taconite eliminated External 

Flue Gas Recirculation and Induced 

Flue Gas Recirculation Burners from 

consideration since they were 

technically infeasible for the specific 

application to pellet furnaces due to the 

high oxygen content of the flue gas. 

United Taconite eliminated Energy 

Efficiency Projects due to the difficulty 

of assigning a general potential emission 

reduction for this category. The 

company has already implemented 

several energy efficiency projects and it 

will continue to evaluate and 

implement energy efficiency projects. 

United Taconite eliminated Alternative 

Fuels because the environmental and 

economic benefits of such a change are 

uncertain and United Taconite believes 

that this option is not mandated by EPA. 

Also, U.S. Steel documented the 

infeasibility of SCR controls. (see 

section V.B.1.a., above). 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Table V–B.14 illustrates the NOX

emission baseline for United Taconite 

and the reductions achievable using low 

NOX burners. 

TABLE V–B.14—PROJECTED ANNUAL NOX EMISSION REDUCTIONS

[TPY] 

NOX Control Assumed 

control Line 1 Line 2 

None (Baseline) ........................................................................................................................... 1643 3687 

Low NOX Burners ........................................................................................................................ 70% 1150 2581 

Step 4: Evaluate Impacts and Document 

Results 

TABLE V–B.15—PELLET FURNACE

PROJECTED NOX

NOX Control Line 1 Line 2 

Low NOX Burners ............. $500 $500 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

A limit of 1.2 lbs/MMBtu on a 30-day 

rolling average for all lines to be 

achieved as follows: 1 year and 6 

months after the effective date for Line 

2 and 2 years and 6 months after the 

effective date for Line 1. 

b. SO2 BART Analysis 

Step 1: Identify All Available Retrofit 

Control Technologies 

In its BART analysis, United Taconite 

identified the following SO2 reduction 

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technologies as generally available to 

pellet furnaces: 

• Wet scrubbing (high efficiency), 

• Wet scrubbing (low efficiency), 

• Wet walled electrostatic 

precipitator (WWESP), 

• Dry sorbent injection, 

• Spray dryer absorption, 

• Alternative Fuels, and 

• Energy efficiency projects. 

Step 2: Eliminate Technically Infeasible 

Options 

United Taconite eliminated dry 

sorbent injection and spray dryer 

absorption as technically infeasible 

technologies. United Taconite identified 

the use of alternative fuels and energy 

efficiency projects as technically 

feasible, but did not evaluate the costs 

associated with these options. United 

Taconite justified its failure to evaluate 

the costs associated with the use of 

alternative fuels and with energy 

efficiency projects stating that a BART 

analysis does not require analysis of 

such options. The company noted EPA’s 

intent ‘‘for facilities to consider 

alternate fuels as an option, not to direct 

fuel choice’’ as its rationale for failing to 

conduct the cost analyses. 

EPA disagrees with United Taconite’s 

assessment of the feasibility of Flue-gas 

desulfurization, which will be discussed 

more fully elsewhere. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies and 

Step 4: Evaluate Impacts and Document 

Results 

TABLE V–B.16—SULFUR DIOXIDE REMOVAL ALTERNATIVES FOR UNITED TACONITE LINE 2 

Control technology 

Uncontrolled 

SO2 emissions rate 

(lb/MMBtu) 

Existing 

SO2

removal 

efficiency 

(percent) 

Additional 

control 

(BART analysis App A) 

(percent) 

lb/ 

MMBtu SO2

Max hourly 

emission 

rate (total) 

(lb/hr) 

Tons SO2

emitted 

Tons SO2

removed 

Total 

annualized 

cost 

$/Ton SO2

removed 

Existing Scrubber ...................... 5.32 25 N/A 3.99 1037 3,900 

WWESP .................................... 5.32 25 80 0.80 207 780 3,120 $20,291,473 $6,504 

Polishing Scrubber .................... 5.32 25 60 1.60 415 1,560 2,340 9,166,715 3,917 

Replacement Scrubber ............. 5.32 N/A 60 2.13 553 2,080 1,820 7,107,434 3,905 

Fuel Blend Changes ................. 2.26 25 N/A 1.70 442 1,660 2,240 1,341,482 599 

Fuel Blending + Polishing 

Scrubber ................................ 2.26 25 60 0.68 176 663 3,237 9,650,715 2,981 

Table V–B.16 above identified 

alternatives for controlling SO2 and 

their associated emissions rate, which 

MPCA determined were all costeffective. At the time this table was 

prepared by MPCA, Line 1 was not 

equipped to burn coal. Line 1 can now 

burn coal and so presumably the above 

table, or something similar, would also 

apply to Line 1. 

TABLE V–B.17—PROJECTED ANNUAL SO2 EMISSION REDUCTIONS AND RESULTING COST-EFFECTIVENESS

SO2 Control Assumed 

control Line 1 Line 2 

Dry FGD Reductions ............................... 90% 1164 ......................................................... 2475 

Cost-Effectiveness ................................... $2,000–$3,000 per ton ............................ $2,000–$3,000 per ton. 

EPA has determined that dry FGD 

scrubbers are feasible for United 

Taconite’s two indurating furnaces. 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

EPA is proposing a limit of 5 ppmv 

or a 95 percent reduction requirement, 

on a 30-day rolling average, to be 

achieved within 2 years after the 

effective date of this rule for Line 2 and 

4 years after the effective date of this 

rule for Line 1. 

4. ArcelorMittal 

ArcelorMittal Minorca Mine Inc. 

operates one straight grate indurating 

furnace which is identified in Table V– 

B.18 below. 

TABLE V–B.18 ARCELORMITTAL EMISSION UNITS

Emission unit name EU No. Control equipment and stack numbers 

Indurating Furnace ...................................................................... EU026 CE014/SV014, CE015/SV015, CE016/SV016, CE017/SV017. 

a. NOX BART Analysis 

Step 1: Identify All Available Retrofit 

Control Technologies 

ArcelorMittal identified the following 

NOX retrofit control technologies as 

being available for indurating furnaces: 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Ported Kilns, Alternate Fuels, and 

• Selective Catalytic Reduction. 

Step 2: Eliminate Technically Infeasible 

Options 

ArcelorMittal eliminated External 

Flue Gas Recirculation and Induced 

Flue Gas Recirculation Burners from 

consideration since they were 

technically infeasible for the specific 

application to pellet furnaces due to the 

high oxygen content of the flue gas. 

ArcelorMittal eliminated Energy 

Efficiency Projects due to the difficulty 

of assigning a general potential emission 

reduction for this category. 

ArcelorMittal noted in its analysis that 

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49320 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

10See September 8, 2006 BART analysis 

submitted to MPCA by Mittal Steel USA—Minorca 

Mine, http://www.pca.state.mn.us/index.php/viewdocument.html?gid=2224. 

the facility has already implemented 

several energy efficiency projects and 

that it will continue to evaluate and 

implement energy efficiency projects. 

Ported Kilns were eliminated by 

ArcelorMittal because they are 

applicable only to grate kiln furnaces 

not to the straight grate indurating 

furnaces that ArcelorMittal employs. 

ArcelorMittal eliminated Alternative 

Fuels because the environmental and 

economic benefits of such a change are 

uncertain and ArcelorMittal believes 

that this option is not mandated by EPA. 

Also, ArcelorMittal’s permit currently 

limits its fuels to natural gas and fuel 

oil. Also, U.S. Steel documented the 

infeasibility of SCR controls above. (See 

section V.B.1.a., above). 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Table V–B.19 illustrates the NOX

emission reductions from use of Low 

NOX burners. 

TABLE V–B.19—PROJECTED ANNUAL NOX EMISSION REDUCTIONS

[TPY] 

NOX Control technology Assumed control 

efficiency Total 

None (Baseline) 6 ..................................................................................................................................... 3639 

Low NOX Burners .................................................................................................................................... 70% 2547 

Step 4: Evaluate Impacts and Document 

Results 

The annualized pollution control cost 

of installing and operating low NOX

burners is in Table V–B.20 below. 

TABLE V–B.20—PELLET FURNACE

PROJECTED NOX CONTROL COSTEFFECTIVENESS

NOX Controls Indurating 

furnace 

Low NOX Burners ....................... $500/ton. 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

EPA is proposing a limit of 1.2 lbs/ 

MMBtu on a 30-day rolling average to be 

achieved within 1 year and 6 months 

after the effective date of this rule for its 

indurating furnace. 

b. SO2 BART Analysis 

Although the indurating furnaces can 

burn both natural gas and fuel oil, 

natural gas is the primary fuel. Since 

natural gas is low in sulfur, the primary 

source of sulfur at this furnace is the 

iron ore used to form the pellets. 

Additional sulfur may be present in the 

additives used in the pellets. 

Furnace emissions are controlled by 

four wet scrubbers. The wet scrubbers 

are designed to remove PM and would 

be considered high efficiency PM wet 

scrubbers. Since collateral SO2

reductions occur within the existing wet 

scrubbers, they are considered low 

efficiency SO2 scrubbers. ArcelorMittal 

estimates that these existing scrubbers 

remove 15 to 30 percent of the SO2 in 

the exhaust gas. 

Step 1: Identify all Available Retrofit 

Control Technologies 

ArcelorMittal identified the following 

SO2 retrofit control technologies 10: 

• Wet Walled Electrostatic 

Precipitator (WWESP), 

• Wet Scrubbing (High and Low 

Efficiency), 

• Dry Sorbent Injection (Dry 

Scrubbing Lime/Limestone Injection), 

• Spray Dryer Absorption (SDA), 

• Energy Efficiency Projects, and 

• Alternate Fuels. 

Step 2: Eliminate Technically Infeasible 

Options 

ArcelorMittal eliminated Dry Sorbent 

Injection, Spray Dryer Absorption, 

Alternative Fuels, and Coal Drying from 

consideration because they were 

technically infeasible. With Dry Sorbent 

Injection and Spray Dryer Absorption, 

the high moisture content of the exhaust 

would lead to saturation of the baghouse 

filter cake and plugging of the filters and 

the dust collection system. Alternative 

Fuels were eliminated because 

ArcelorMittal is prohibited from 

burning solids fuels and natural gas is 

a low-sulfur fuel. ArcelorMittal 

indicated that the potential fuel 

reductions and the commensurate 

emission reductions for future Energy 

Efficiency Projects cannot accurately be 

predicted without specific details; since 

no particular project has been 

envisioned, the company did not 

evaluate this option any further. 

ArcelorMittal evaluated the 

possibility of improving the SO2

removal efficiency of the existing 

scrubbers through the addition of 

caustic, lime, or limestone in the 

scrubber water to raise the pH. 

ArcelorMittal found this option to be 

impractical for several reasons. The 

scrubber currently operates at a neutral 

pH and the scrubbers, piping, pumps 

and water tanks were not designed to 

operate at a higher pH so corrosion of 

the system would be a concern. Also, 

the addition of caustic, lime, or 

limestone to increase SO2 removal 

would create additional solids in the 

scrubber recirculation system which 

would require an increased blowdown 

rate and therefore an increased make-up 

water rate. Because the water balance at 

the facility is at maximum usage, 

additional make-up water is not 

available. Based on these concerns, 

ArcelorMittal did not further consider 

this option. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

ArcelorMittal estimated the control 

efficiency of WWESPs to be 

approximately 80 percent. A secondary 

wet scrubber was estimated to control 

roughly 60 percent of the SO2 remaining 

after the existing scrubber. The 

following tables illustrate the SO2

emission reductions projected by 

ArcelorMittal with the technically 

feasible control technologies. 

TABLE V–B.21—ANNUAL SO2

EMISSIONS

[TPY] 

Total 

Baseline SO2 Emissions .............. 179.2 

TABLE V–B.22—PROJECTED SO2

EMISSION REDUCTIONS

[TPY] 

SO2 Control technology Total 

WWESP ........................................ 143.2 

Secondary Wet Scrubber ............. 107.6 

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Step 4: Evaluate Impacts and Document 

the Results 

Cost of Control 

ArcelorMittal estimated the 

annualized pollution control cost of 

installing and operating WWESPs to be 

about $116,000 per ton of SO2 removed. 

The cost of installing and operating a 

secondary wet scrubber was estimated 

to be approximately $83,000 per ton of 

SO2 removed. 

Energy and Non-air Quality 

Environmental Impacts 

Because the cost of additional SO2

controls for ArcelorMittal does not meet 

a reasonable definition of cost effective 

technology, no further evaluation of 

these alternatives was conducted. 

Step 5: Evaluate Visibility Impacts 

Additional SO2 controls for 

ArcelorMittal are not reasonably cost 

effective, so visibility impacts were not 

modeled for additional SO2 controls. 

Step 6: Propose BART 

Although we do not agree that MPCA 

and ArcelorMittal have adequately 

documented the infeasibility of all of 

the SO2 controls described above, we 

agree that, because ArcelorMittal is 

burning natural gas, additional SO2

controls are not economically 

reasonable and are, therefore, not 

necessary for BART. EPA is proposing 

to determine that BART is existing 

controls. ArcelorMittal provided the 

results of emissions testing that was 

performed on the stacks associated with 

the furnace. Based on these test results, 

EPA is proposing a limit of 23.0 lb SO2/ 

hr, measured on a 30-day rolling 

average. This limit does not apply when 

the subject unit is burning fuel oil. 

Compliance is required within 30 days 

of the effective date of this rule. 

5. Hibbing Taconite 

Hibbing operates three straight grate 

indurating furnaces which are identified 

in Table V–B.23 below. 

TABLE V–B.23—HIBBING EMISSION UNITS

Emission unit name EU No. Control equipment and stack numbers 

Line 1 Pelletizing furnace ............................................................. EU020 ......... CE022/SV021, CE023/SV022, CE024/SV023, CE025/SV024. 

Line 2 Pelletizing furnace ............................................................. EU021 ......... CE027/SV025, CE028/SV026, CE029/SV027, CE030/SV028. 

Line 3 Pelletizing furnace ............................................................. EU022 ......... CE032/SV029, CE033/SV030, CE034/SV031, CE035/SV032. 

a. NOX BART Analysis 

Step 1: Identify All Available Retrofit 

Control Technologies 

Hibbing identified the following NOX

retrofit control technologies as available 

and applicable to pellet furnaces: 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Ported Kilns, 

• Alternate Fuels, and 

• Selective Catalytic Reduction with 

Reheat. 

Step 2: Eliminate Technically Infeasible 

Options 

Hibbing eliminated External Flue Gas 

Recirculation and Induced Flue Gas 

Recirculation Burners from 

consideration since they were 

technically infeasible for the specific 

application to pellet furnaces due to the 

high oxygen content of the flue gas. 

Hibbing eliminated Energy Efficiency 

Projects due to the difficulty of 

assigning a general potential emission 

reduction for this category. Hibbing 

noted in their Analysis that the facility 

has already implemented several energy 

efficiency projects and that it will 

continue to evaluate and implement 

energy efficiency projects. Ported Kilns 

were eliminated by Hibbing because 

they are applicable only to grate kiln 

furnaces not to the straight grate 

indurating furnaces that Hibbing 

employs. Hibbing eliminated 

Alternative Fuels because the 

environmental and economic benefits of 

such a change are uncertain and 

Hibbing believes that this option is not 

mandated by U.S. EPA. Also, Hibbing’s 

permit currently limits its fuels to 

natural gas, fuel oil, and used oil. Also, 

U.S. Steel documented the infeasibility 

of SCR controls. (see section V.B.1.a., 

above). 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Table V–B.24 illustrates the NOX

emission reductions resulting from use 

of low NOX burners. 

TABLE V–B.24—PROJECTED ANNUAL NOX EMISSION REDUCTIONS

[TPY] 

NOX Control technology Assumed control efficiency Line 1 Line 2 Line 3 

None (Baseline) ............................................................................................... ........................ 2,143.5 2,143.5 2,247.1 

Low NOX Burners ............................................................................................ 70% 1,748 1,500 1,573 

Step 4: Evaluate Impacts and Document 

Results 

The annualized pollution control cost 

of installing and operating low NOX

burners is in Table V–B.25 below. 

mstockstill on DSK4VPTVN1PROD with PROPOSALS5

49322 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

11See BART analysis submitted to MPCA by 

Hibbing Taconite Company in September 2006, 

http://www.pca.state.mn.us/index.php/viewdocument.html?gid=2223. 

TABLE V–B.25—PELLET FURNACE PROJECTED NOX CONTROL COST

[cost per ton of pollutant removed] 

NOX Control Technology Line 1 Line 2 Line 3 

Low NOX Burners ...................................................................................................................................................... $500 $500 $500 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

EPA is proposing a limit of 1.2 lbs/ 

MMBtu on a 30-day rolling average for 

all lines to be achieved as follows: 1 

year and 6 months after the effective 

date for Line 1, 2 years and 6 months 

after the effective date for Line 3 and 3 

years and 6 months for Line 2. 

b. SO2 BART analysis 

Hibbing operates three straight grate 

indurating furnaces which are identified 

in table V–B.26 below. 

TABLE V–B.26—HIBBING SO2 EMISSION UNITS

Emission unit name EU No. Control equipment and stack numbers 

Line 1 Pelletizing Furnace ............................................................ EU020 ........ CE022/SV021, CE023/SV022, CE024/SV023, CE025/SV024. 

Line 2 Pelletizing Furnace ............................................................ EU021 ........ CE027/SV025, CE028/SV026, CE029/SV027, CE030/SV028. 

Line 3 Pelletizing Furnace ............................................................ EU022 ........ CE032/SV029, CE033/SV030, CE034/SV031, CE035/SV032. 

Although the indurating furnaces can 

burn both natural gas and fuel oil, 

natural gas is the primary fuel. Since 

natural gas is low in sulfur, the primary 

source of sulfur at these furnaces is the 

iron ore used to form the pellets. 

Additional sulfur may be present in the 

additives used in the pellets. 

Each line is controlled by four 

venture-rod scrubbers. The wet 

scrubbers are designed to remove PM 

and would be considered high 

efficiency PM wet scrubbers. Since 

collateral SO2 reductions occur within 

the existing wet scrubbers, they are 

considered low efficiency SO2

scrubbers. Hibbing estimates that these 

existing scrubbers remove 15 to 30 

percent of the SO2 in the exhaust gas 

from Lines 1, 2, and 3. 

Step 1: Identify all Available Retrofit 

Control Technologies 

Hibbing identified the following SO2

retrofit control technologies 11: 

• Wet Walled Electrostatic 

Precipitator (WWESP), 

• Wet Scrubbing (High and Low 

Efficiency), 

• Dry Sorbent Injection (Dry 

Scrubbing Lime/Limestone Injection), 

• Spray Dryer Absorption, 

• Energy Efficiency Projects, 

Alternate Fuels, and 

• Coal Processing. 

Step 2: Eliminate Technically Infeasible 

Options 

Hibbing eliminated Dry Sorbent 

Injection, Spray Dryer Absorption, 

Alternative Fuels, and Coal Drying from 

consideration due to technical 

infeasibility. With Dry Sorbent Injection 

and Spray Dryer Absorption, the high 

moisture content of the exhaust would 

lead to saturation of the baghouse filter 

cake and plugging of the filters and the 

dust collection system. Alternative 

Fuels were eliminated because Hibbing 

is prohibited from burning solids fuels. 

Coal Drying is technically infeasible 

because Hibbing does not burn coal. 

In addition, Hibbing has already 

implemented Energy Efficiency Projects. 

The company indicated that the 

potential fuel reductions and the 

commensurate emission reductions for 

future Energy Efficiency Projects cannot 

accurately be predicted without specific 

details; since no particular project has 

been envisioned, the company did not 

evaluate this option any further. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Hibbing estimated the control 

efficiency of WWESPs to be 

approximately 80 percent. A secondary 

wet scrubber was estimated to control 

roughly 60 percent of the SO2 remaining 

after the existing scrubber. Hibbing also 

expected that modifying the existing 

wet scrubber would control between 0 

and 50 percent of the SO2 currently 

emitted. The following tables illustrate 

the SO2 emission reductions projected 

by Hibbing with the technically feasible 

control technologies. 

TABLE V–B.27—ANNUAL SO2 EMISSIONS

[TPY] 

Line 1 Line 2 Line 3 Total 

Baseline SO2 Emissions .................................................................................. 202.2 179.5 188.1 569.8 

TABLE V–B.28—PROJECTED SO2 EMISSION REDUCTIONS

[TPY] 

SO2 Control technology Line 1 Line 2 Line 3 Total 

WWESP ........................................................................................................... 161.8 143.6 150.5 455.9 

Secondary Wet Scrubber ................................................................................ 121.3 121.3 121.3 363.9 

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Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 49323 

TABLE V–B.28—PROJECTED SO2 EMISSION REDUCTIONS—Continued 

[TPY] 

SO2 Control technology Line 1 Line 2 Line 3 Total 

Modification of Wet Scrubber .......................................................................... 0–101.1 0–101.1 0–101.1 0–303.3 

Step 4: Evaluate Impacts and Document 

the Results 

Cost of Control 

Hibbing estimated the annualized 

pollution control cost of installing and 

operating WWESPs to be about $37,000 

per ton of SO2 removed. The cost of 

installing and operating a secondary wet 

scrubber was estimated to be between 

$57,000 and $67,000 per ton of SO2

removed. Given the space limitations 

and equipment additions that would be 

required to modify the existing wet 

scrubber, Hibbing determined that it 

would be more cost effective to 

construct a new, secondary scrubber; 

therefore, no cost estimate was provided 

for modifications to the existing wet 

scrubber. 

Energy and Non-air Quality 

Environmental Impacts 

There are no impacts because no 

additional controls are being proposed, 

as discussed in the Step 4 and Step 6 

discussions. 

Step 5: Evaluate Visibility Impacts 

There are no visibility impacts 

because no additional controls are being 

proposed, as discussed in the Step 4 and 

Step 6 discussions. 

Step 6: Propose BART 

Although we do not agree that MPCA 

and Hibbing have adequately 

documented the infeasibility of all of 

the SO2 controls described above, we 

agree that, because Hibbing is burning 

natural gas, additional SO2 controls are 

not economically reasonable and are, 

therefore, not necessary for BART. EPA 

is proposing to determine that BART is 

existing controls. Hibbing provided the 

results of emissions testing that was 

performed in 2010 on the stacks 

associated with Lines 1, 2, and 3. Based 

on these test results, EPA is proposing 

the following limits: 56.0 lb SO2/hr for 

Line 1, 63.0 lb SO2/hr for Line 2, and 

64.0 lb SO2/hr for Line 3. These limits 

are measured on a 30-day rolling 

average and do not apply when the 

subject units are burning fuel oil. 

Compliance is required within 30 days 

of the effective date of this rule. 

6. U.S. Steel Keewatin 

U.S. Steel Keewatin (Keetac) operates 

one straight grate indurating furnace 

which is identified in Table V–B.29 

below. 

TABLE V–B.29—KEETAC EMISSION

UNITS

Emission Unit Name EU No. Stack 

No. 

Phase II Grate-Kiln 

Indurating Furnace .... EU030 SV051 

a. NOX BART Analysis 

Step 1: Identify All Available Retrofit 

Control Technologies 

Keetac identified the following NOX

retrofit control technologies as available 

and applicable to pellet furnaces: 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Ported Kilns, 

• Alternate Fuels, and 

• Selective Catalytic Reduction with 

Reheat. 

Step 2: Eliminate Technically Infeasible 

Options 

Keetac eliminated External Flue Gas 

Recirculation and Induced Flue Gas 

Recirculation Burners from 

consideration since they were 

technically infeasible for the specific 

application to pellet furnaces due to the 

high oxygen content of the flue gas. The 

company indicated that the potential 

fuel reductions and the commensurate 

emission reductions for future Energy 

Efficiency Projects cannot accurately be 

predicted without specific details; since 

no particular project has been 

envisioned, the company did not 

evaluate this option any further. Keetac 

eliminated Alternative Fuels because 

the furnace already uses solid fuels that 

result in lower flame temperature and, 

thus, lower NOX emissions. Switching 

to another fuel such natural gas (which 

Keetac already is capable of using) 

could exchange one visibility impairing 

pollutant for another (NOX for SO2). 

Keetac also believes that this option is 

not mandated by EPA. Keetac identified 

Ported Kilns and Selective Catalytic 

Reduction with conventional Reheat as 

the only technologies that are 

technically feasible. Also, U.S. Steel 

documented the infeasibility of SCR 

controls (see section V.B.1.a., above). 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Table V–B.30 identifies the projected 

NOX emission reductions resulting from 

use of low NOX burners. 

TABLE V–B.30—PROJECTED ANNUAL NOX EMISSION REDUCTIONS

NOX control technology 

Assumed control 

efficiency 

(percent) 

Phase II furnaces 

(TPY) 

None (Baseline) ....................................................................................................................... 4,154.0 

Low NOX Burners .................................................................................................................... 70 2,908 

Ported Kiln ............................................................................................................................... 5 207.7 

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Step 4: Evaluate Impacts and Document 

Results 

TABLE V–B.30 

[COST PER TON OF POLLUTANT 

REMOVED] 

NOX control technology Phase II furnace 

Low NOX burners ............. $500 

Ported Kiln–diff. due to 

discrepancy in submittal $2,938–$6,032 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

For NOX, EPA is proposing a limit of 

1.2 lbs/MMBtu on a 30-day rolling 

average for the Phase II furnace. 

Compliance is to be achieved within 1 

year and 6 months after the effective 

date of this rule. 

b. SO2 BART Analysis 

Step 1: Identify All Available Retrofit 

Control Technologies 

Keetac identified the following SO2

retrofit control technologies as available 

and applicable to pellet furnaces: 

• Wet Walled Electrostatic 

Precipitator (WWESP), 

• Secondary Wet Scrubber, 

• Modifications to Existing Wet 

Scrubber, 

• Dry Sorbent Injection (Dry 

Scrubbing Lime/Limestone Injection), 

• Spray Dryer Absorption, 

• Energy Efficiency Projects, 

• Alternate Fuels, and 

• Coal Processing. 

Step 2: Eliminate Technically Infeasible 

Options 

In considering control options for 

sulfur dioxide, Keetac eliminated Dry 

Sorbent Injection, Spray Dryer 

Absorption, Alternative Fuels, and Coal 

Processing from consideration since 

they were technically infeasible. With 

Dry Sorbent Injection and Spray Dryer 

Absorption, the high moisture content 

of the exhaust would lead to saturation 

of the baghouse filter cake and plugging 

of the filters and the dust collection 

system. The company indicated that the 

potential fuel reductions and the 

commensurate emission reductions for 

future Energy Efficiency Projects cannot 

accurately be predicted without specific 

details; since no particular project has 

been envisioned, the company did not 

evaluate this option any further. 

Alternative Fuels were eliminated due 

to the uncertainty of alternative fuel 

costs, the potential of replacing one 

visibility pollutant for another, and 

Keetac’s belief that BART does not 

intend to mandate a fuel switch. Coal 

Processing requires a source of excess or 

of low pressure stream to remove water 

from the washed coal. There is no such 

heat source at Keetac so this option is 

technically infeasible. 

In addition, Keetac has already 

implemented a number of Energy 

Efficiency Projects. The potential fuel 

reductions and the commensurate 

emission reductions for future Energy 

Efficiency Projects cannot accurately be 

predicted without specific details; since 

no particular project has been 

envisioned, the company decided not to 

evaluate this option any further. 

Keetac evaluated modifying the 

existing scrubber to determine whether 

further SO2 removal could be achieved. 

However, Keetac has recently installed 

new wet scrubbers to control SO2

emissions. Since operation of the 

scrubber has been optimized, further 

improvement of the removal efficiency 

is not feasible and was not considered 

further in the report. 

EPA disagrees with Keetac’s 

assessment of the feasibility of Flue-gas 

desulfurization, which will be discussed 

more fully elsewhere. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Keetac evaluated WWESPs and 

Secondary Wet Scrubber as the two 

remaining retrofit technologies it 

deemed to be available and technically 

feasible. Keetac estimated the control 

efficiency of WWESPs to be 

approximately 80 percent. A secondary 

wet scrubber was estimated to control 

roughly 60 percent of the SO2 remaining 

after the existing scrubber. The 

following table illustrates the SO2

emission reductions projected by Keetac 

with the technically feasible control 

technologies. 

TABLE V–B.32—PROJECTED SO2 EMISSION REDUCTIONS

[TPY] 

SO2 Control technology Phase II 

furnace 

Baseline Emissions (existing scrubber) ............................................................................................................................................... 850.5 

WWESP (after existing scrubber) ........................................................................................................................................................ 760.4 

Secondary Wet Scrubber (after existing scrubber) ............................................................................................................................. 570.3 

Step 4: Evaluate Impacts and Document 

Results 

Keetac’s estimates of the annualized 

pollution control cost of installing and 

operating the WWESP and Secondary 

Wet Scrubber are shown in the table V– 

B.33 below. 

TABLE V–B.33—PELLET FURNACE PROJECTED SO2 CONTROL COST

[$ PER TON OF POLLUTANT REMOVED] 

SO2 Control technology Phase II 

furnace 

WWESP (after existing scrubber) ........................................................................................................................................................ $15,165 

Secondary Wet Scrubber (after existing scrubber) ............................................................................................................................. 8,870 

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Step 5: Evaluate Visibility Impacts 

Visibility impacts were not modeled 

because additional reductions were not 

determined to be cost effective. 

Step 6: Propose BART 

Keetac’s existing recirculating lime 

scrubber satisfies BART. Therefore, EPA 

is proposing that the scrubber be subject 

to a 57 percent SO2 removal efficiency 

and a limit, based on CEMS data, of 225 

lbs SO2 per hour on a 30-day rolling 

average. In addition, EPA is proposing 

to require that the scrubber be operated 

at or above a pH of 7.5. Compliance 

with all SO2 emission limits is required 

beginning 90 days from the effective 

date of this rule. 

7. Tilden Mining Company LLC (TMC) 

The BART-subject emission units 

include indurating furnace/grate-kiln 

EUKILN 1, EU PRIMARY CRUSHER, EU 

COOLER 1, EU DRYER 1, EU BOILER 1, 

and EU BOILER 2. 

a. NOX BART Analysis 

Step 1: Identify All Available and 

Technically Feasible Retrofit 

Technologies 

The following NOX retrofit control 

technologies have been identified as 

being available and applicable for 

indurating furnaces: 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• Induced Flue Gas Recirculation 

Burners, 

• Energy Efficiency Projects, 

• Ported Kilns, 

• Alternate Fuels, and 

• Selective Catalytic Reduction. 

Step 2: Eliminate Technically Infeasible 

Options 

Tilden eliminated External Flue Gas 

Recirculation and Induced Flue Gas 

Recirculation Burners from 

consideration since they were 

technically infeasible for the specific 

application to pellet furnaces due to the 

high oxygen content of the flue gas. 

Tilden eliminated Energy Efficiency 

Projects due to the difficulty of 

assigning a general potential emission 

reduction for this category. Ported Kilns 

were eliminated by Tilden because any 

reduction in NOX would be minor. 

Tilden eliminated Alternative Fuels 

because the environmental and 

economic benefits of such a change are 

uncertain and Tilden believes that this 

option is not mandated by EPA. Also, 

U.S. Steel documented the infeasibility 

of SCR controls (see section V.B.1.a., 

above). Tilden also determined that 

non-selective catalytic reduction, 

regenerative selective reduction, 

selective non-catalytic reduction and 

low temperature oxidation are 

technically infeasible. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Table V–B.34 illustrates the NOX

emission reductions resulting from use 

of low NOX burners. 

TABLE V–B.34—PROJECTED ANNUAL

NOX EMISSION REDUCTIONS

NOX Control 

Technology 

Assumed 

control 

efficiency 

(percent) 

Line 1 (tons 

per year) 

None (Baseline) ........... 4,613 

Low NOX

burners ...... 70 3,229 

Step 4: Evaluate Impacts and Document 

Results 

The annualized pollution control cost 

of installing and operating low NOX

burners is in Table V–B.35 below. 

TABLE V–B.35—PELLET FURNACE PROJECTED NOX CONTROL COST

[COST PER TON OF POLLUTANT] 

NOX Control technology Indurating furnace 

Low NOX burners $ 500/ton. 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

For Line 1, EPA is proposing a limit 

of 1.2 lbs/MMBtu on a 30-day rolling 

average to be achieved within 1 year 

and 6 months after the effective date of 

this rule. 

b. SO2 BART Analysis 

Step 1: Identify All Available Retrofit 

Control Technologies 

Tilden identified the following SO2

retrofit control technologies as available 

and applicable to pellet furnaces: 

• Wet Walled Electrostatic 

Precipitator (WWESP), 

• Wet Scrubbing, 

• Dry Sorbent Injection (Dry 

Scrubbing Lime/Limestone Injection), 

• Spray Dryer Absorption (SDA), 

• Energy Efficiency Projects, 

• Alternate Fuels, and 

• Coal Processing. 

Step 2: Eliminate Technically Infeasible 

Options 

Tilden indicated that the potential 

fuel reductions and the commensurate 

emission reductions for future Energy 

Efficiency Projects cannot accurately be 

predicted without specific details. 

Therefore, due to the uncertainty and 

generalization of this category, energy 

efficiency projects were not subject to 

further analysis. Alternative Fuels were 

eliminated due to the uncertainty of 

alternative fuel costs, the potential of 

replacing one visibility pollutant for 

another, and Tilden’s belief that BART 

does not intend to mandate a fuel 

switch. Using processed fuels at a 

taconite plant would require research, 

test burns, and extended trials to 

identify potential impacts on plant 

systems, including the furnaces, 

material handling, and emission control 

systems. Therefore, processed fuels are 

not considered commercially available 

and were not subject to further analysis 

by Tilden. 

Step 3: Evaluate Control Effectiveness of 

Remaining Control Technologies 

Tilden evaluated a WWESP and wet 

scrubber after its existing ESP, spray dry 

absorption, and dry sorbent injection as 

the remaining retrofit technologies it 

deemed to be available and technically 

feasible. Tilden estimated the control 

efficiency of WWESPs and a wet 

scrubber to be about 80 percent, dry 

sorbent injection to be 55 percent and 

spray dry absorption to be 90 percent. 

The following table illustrates the SO2

emission reductions projected by Tilden 

technologies. 

TABLE V–B.36—PROJECTED SO2

EMISSION REDUCTIONS

[TPY] 

SO2 Control technology Line 1 

Spray Dry Absorption ............... 1,037.8 

Wet Walled ESP ....................... 922.5 

Wet Scrubber ............................ 922.5 

Dry Sorbent Injection ................ 634.2 

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Step 4: Evaluate Impacts and Document 

Results 

EPA has determined the costeffectiveness of a 90 percent FGD 

scrubber to be $4500-$5500/ton using 

EPA’s Air Pollution Control Cost 

Manual. 

Step 5: Evaluate Visibility Impacts 

See section V.C. 

Step 6: Propose BART 

For Line 1, EPA is proposing a limit 

of 5 ppmv or a 95 percent emission 

reduction, on a 30-day rolling average, 

to be achieved within 2 years after the 

effective date of this rule. 

c. Non-Furnace BART Analysis 

Process Boiler #1 and Process Boiler #2 

Two natural gas and fuel oil fired 

process boilers (Process Boiler #1 and 

Process Boiler #2) require BART 

analysis. These boilers provide steam 

required to operate the taconite plant, as 

needed. The boilers are permitted to 

burn only natural gas and used oil. 

SO2 Analysis 

Step 1: Identification of Available 

Retrofit Control Technologies 

• Wet Walled Electrostatic 

Precipitator, 

• Wet Scrubber, 

• Dry Sorbent Injection (Dry 

Scrubbing Lime/Limestone Injection), 

• Spray Dryer Absorption (SDA), 

• Energy Efficiency Projects, 

• Alternate Fuels, and 

• Coal Processing. 

Step 2: Elimination of Technically 

Infeasible Options 

Tilden’s process boilers cannot burn 

solid fuel, which eliminates coal 

processing. Due to the increased price of 

fuel, Tilden has already implemented 

energy efficiency projects. Each project 

carries its own fuel usage reductions 

and potentially emission reductions. 

Due to the uncertainty and 

generalization of this category, this 

option was eliminated. Similarly, 

Tilden eliminated alternative fuels 

because the environmental and 

economic benefits of such a change are 

uncertain, the limited fuel options 

available, and the fact that natural gas 

and oil are the fuels burned in the 

boilers. 

Step 3: Evaluation of the Control 

Effectiveness of the Remaining Control 

Technologies 

The following table illustrates the SO2

emission reductions projected by Tilden 

with the technically feasible 

technologies. 

TABLE V–B.37—PROJECTED ANNUAL SO2 EMISSION REDUCTIONS

[TPY] 

Control technology 

Control 

efficiency 

(percent) 

Emissions Cost 

None (Baseline) ........................................................................................................................... ........................ 0.25 ........................

SDA .............................................................................................................................................. 90 0.03 $38,403,000 

Wet Scrubber ............................................................................................................................... 80 0.05 7,448,000 

WWESP ....................................................................................................................................... 80 0.05 15,733,000 

Dry Scrubber ................................................................................................................................ 55 0.11 35,381,000 

Step 4: Evaluate Impacts and Document 

Results 

The two process boilers have very 

modest SO2 emissions at 0.25 TPY. A 

wet scrubber would reduce emissions 

by 80 percent, but at an annual cost of 

about $1.5 million and a costeffectiveness of $7,448,000 per ton. 

Step 5: Evaluate Visibility Impacts 

Visibility impacts were not modeled 

because additional reductions are not 

cost-effective. 

Step 6: Propose BART 

This BART analysis shows that 

adding a control device to control SO2

emissions from the boilers would yield 

a very modest emission reduction at a 

multi-million dollar per ton cost. Thus, 

EPA is proposing retaining the 1.2% by 

weight sulfur content limit on the 

boilers when oil is burned. 

NOX Analysis 

Step 1: Identification of Available 

Retrofit Control Technologies 

• External Flue Gas Recirculation, 

• Low-NOX Burners, 

• Low-NOX Burners with Overfire 

Air, 

• Induced Flue Gas Recirculation 

Burners, 

• Low Excess Air, 

• Reburning, 

• Energy Efficiency Projects, 

• Alternate Fuels, 

• Non-Selective Catalytic Reduction, 

• Selective Catalytic Reduction (SCR), 

• Regenerative SCR, 

• Selective Non-Catalytic Reduction, 

and 

• Low Temperature Oxidation. 

Step 2: Elimination of Technically 

Infeasible Options 

External flue gas recirculation was 

eliminated as process boilers #1 and #2 

do not have the capability of control at 

the burner tip, which is needed for this 

control technology. As noted in SO2

determination, Tilden has already 

implemented energy efficiency projects. 

Each project carries its own fuel usage 

reductions and potentially emission 

reductions. Due to the uncertainty and 

generalization of this category, this 

option was eliminated. Similarly, 

Tilden eliminated alternative fuels 

because the environmental and 

economic benefits of such a change are 

uncertain and limited fuel options are 

available for the boilers. Operating a 

boiler with low excess air minimizes 

NOX production during combustion. 

Tilden already operates process boiler 

#1 and #2 with low excess air. This 

option was thus not evaluated further as 

the benefit has already been achieved. 

Reburning is infeasible as the Tilden 

boilers do not burn solid fuel. 

Regenerative SCR has only been used 

on wood-fired boilers. This technology 

has not been applied to liquid or natural 

gas fired boilers. Regenerative SCR is 

currently infeasible for the Tilden 

boilers. Low temperature oxidation is a 

post-combustion technology that uses 

an oxidant to oxide pollutants including 

NOX. A scrubbing system is then used 

to remove the nitrates. Low temperature 

oxidation is an emerging technology 

that is currently infeasible as BART 

control on the Tilden boilers. 

Step 3: Evaluation of the Control 

Effectiveness of the Remaining Control 

Technologies 

The following table illustrates the 

NOX emission reductions projected by 

Tilden with the technically feasible 

technologies. 

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TABLE V–B.38—PROJECTED ANNUAL NOX EMISSION REDUCTIONS

[TPY] 

Control technology 

Control 

efficiency 

(percent) 

Emissions Cost 

None (baseline) ........................................................................................................................... ........................ 79.23 ........................

SCR ............................................................................................................................................. 80 15.85 $39,888 

LNB/Flue Gas Recirculation ........................................................................................................ 75 19.81 5,112 

LNB/OFA ...................................................................................................................................... 67 26.15 7,361 

LNB .............................................................................................................................................. 50 36.61 7,244 

Selective Non-Catalytic Reduction .............................................................................................. 50 36.61 11,833 

Step 4: Evaluate Impacts and Document 

Results 

The two process boilers have modest 

NOX emissions at about 80 TPY each. 

The combustion control technologies 

produce good control efficiencies at a 

lower cost compared to the postcombustion options. All the combustion 

control options have similar costs. A 

low NOX burner coupled with flue gas 

recirculation produces a 59.42 TPY NOX

reduction per unit, the greatest control, 

at a cost of $5,122 per ton. 

Step 5: Evaluate Visibility Impacts 

Visibility impacts were not modeled 

because no additional reductions are 

required. 

Step 6: Propose BART 

Given that the control options are 

modest reductions in NOX emission on 

a TPY basis, that modest reduction 

would need to provide a strong 

visibility improvement or be trivial in 

cost to justify a BART limit indicative 

of additional control. That is not the 

case for the process boilers. Thus, EPA 

is proposing the current good 

combustion practice as the NOX

emission restrictions for both Process 

Boiler #1 and Process Boiler #2. 

Line 1 Dryer 

The Line 1 Dryer includes a 

combustion box in which natural gas 

and used oil is burned as fuel. The flue 

gas from the combustion box flows into 

a rotary dryer that repeatedly tumbles 

wet taconite ore concentrate through the 

flue gas stream to reduce the amount of 

entrained moisture in the taconite ore 

concentrate. The particulate emissions 

from the dryer are controlled by 

cyclones and impingement scrubbers in 

series. The dryer is only permitted to 

use natural gas and used oil for fuel. 

The Line 1 Dryer has low emissions of 

SO2 due to the low sulfur content of the 

permitted fuels. In addition, collateral 

SO2 reductions occur within the 

existing impingement scrubbers, and 

therefore the existing scrubber is 

considered a low-efficiency SO2

scrubber. 

SO2 Analysis 

Step 1: Identification of Available 

Retrofit Control Technologies 

• Wet Walled Electrostatic 

Precipitator, 

• Wet Scrubber, 

• Dry Sorbent Injection (Dry 

Scrubbing Lime/Limestone Injection), 

• Spray Dryer Absorption (SDA), 

• Energy Efficiency Projects, 

• Alternate Fuels, and 

• Coal Processing. 

Step 2: Elimination of Technically 

Infeasible Options 

The Line 1 Dryer cannot burn solid 

fuel, which eliminates coal processing. 

Tilden has already implemented energy 

efficiency projects on the dryer. Each 

project carries its own fuel usage 

reductions and potentially emission 

reductions. Due to the uncertainty and 

generalization of this category, this 

option was eliminated. Dry sorbent 

injection uses a fabric filter, 

‘‘baghouse,’’ as part of the control 

system. The Line 1 Dryer exhaust is 

saturated with moisture. Such moisture 

would foul the baghouse. The same is 

true if the baghouse is placed following 

the wet scrubber into which the dryer 

currently exhausts. The dry sorbent 

injection system is thus technically 

infeasible for the Line 1 Dryer. The SDA 

system also uses a baghouse to capture 

the dry solids. The moisture in the dryer 

exhaust similarly creates problems with 

the baghouse. Thus, SDA is infeasible 

for Tilden’s Line 1 Dryer. Alternative 

fuels are infeasible because the 

environmental and economic benefits of 

such a change are uncertain, the limited 

fuel options available, and the fact that 

natural gas and oil are the fuels used for 

the dryer. 

Step 3: Evaluation of the Control 

Effectiveness of the Remaining Control 

Technologies 

The following table illustrates the SO2

emission reductions projected by Tilden 

with the technically feasible 

technologies. 

TABLE V–B.39—PROJECTED ANNUAL SO2 EMISSION REDUCTIONS

[TPY] 

Control technology 

Control efficiency 

(percent) 

Emissions Cost 

None (baseline) ........................................................................................................................... ........................ 34.07 ........................

Wet Scrubber ............................................................................................................................... 80 6.81 $25,103 

WWESP ....................................................................................................................................... 80 6.81 52,432 

Step 4: Evaluate Impacts and Document 

Results 

The Line 1 Dryer has SO2 emissions 

of 34.07 TPY. The moisture in the dryer 

exhaust limits the control options for 

this unit. A wet scrubber would reduce 

emissions by 27.26 TPY or 80 percent at 

an annual cost of about $25,000. The 

SO2 emissions from this unit are already 

limited by fuel restrictions and the 

existing low-efficiency SO2 scrubber. 

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Step 5: Evaluate Visibility Impacts 

Visibility impacts were not modeled 

because no additional reductions are 

required. 

Step 6: Propose BART 

This BART analysis shows that 

adding a control device to control SO2

emissions from the boilers would yield 

a modest emission reduction at a cost 

that could exceed $25,000 per ton. 

Thus, EPA is proposing retaining the 

fuel restriction of 1.5% by weight sulfur 

content limit when oil is burned. 

NOX Analysis 

Step 1: Identification of Available 

Retrofit Control Technologies 

• External Flue Gas Recirculation, 

• Low-NOX Burners (LNB), 

• Low-NOX Burners with Overfire 

Air, 

• Induced Flue Gas Recirculation 

Burners, 

• Low Excess Air, 

• Reburning, 

• Energy Efficiency Projects, 

• Alternate Fuels, 

• Non-Selective Catalytic Reduction, 

• Selective Catalytic Reduction (SCR), 

• Regenerative SCR, 

• Selective Non-Catalytic Reduction, 

and 

• Low Temperature Oxidation. 

Step 2: Elimination of Technically 

Infeasible Options 

External flue gas recirculation was 

eliminated as the configuration of the 

Line 1 Dryer burner does have the 

capability of control at the burner tip, 

which is needed for this control 

technology. As noted in the SO2

determination, Tilden has already 

implemented energy efficiency projects. 

Each project carries its own fuel usage 

reductions and potentially emission 

reductions. Due to the uncertainty and 

generalization of this category, this 

option was eliminated. Similarly, 

Tilden eliminated alternative fuels 

because the environmental and 

economic benefits of such a change are 

uncertain and limited fuel options are 

available for the boilers. Induced flue 

gas recirculation burner technology is 

infeasible for the Line 1 Dryer. 

Operating a boiler with low excess air 

minimizes NOX production during 

combustion. Similar to process boiler #1 

and #2, the dryer is already operated 

with low excess air. This option was 

thus not evaluated further as the benefit 

has already been achieved. Reburning is 

infeasible as the Line 1 Dryer does not 

burn solid fuel. 

Regenerative SCR has only been used 

on wood-fired boilers. This technology 

has not been applied to liquid or natural 

gas fired burners. Regenerative SCR is 

currently infeasible for the Line 1 Dryer. 

Low temperature oxidation is a postcombustion technology that uses an 

oxidant to oxide pollutants including 

NOX. A scrubbing system is then used 

to remove the nitrates. Low temperature 

oxidation has not been applied on a 

taconite dryer. It is currently considered 

infeasible as BART control option on 

the dryer unit. 

Step 3: Evaluation of the Control 

Effectiveness of the Remaining Control 

Technologies 

The following table illustrates the 

NOX emission reductions projected by 

Tilden with the technically feasible 

technologies. 

TABLE V–B.40—PROJECTED ANNUAL NOX EMISSION REDUCTIONS

[TPY] 

Control technology 

Control 

efficiency 

percent 

Emissions Cost 

None (baseline) ........................................................................................................................... ........................ 15.1 ........................

SCR ............................................................................................................................................. 80 3.02 $83,472 

LNB/Flue Gas Recirculation ........................................................................................................ 75 3.77 11,891 

LNB/OFA ...................................................................................................................................... 67 4.98 11,535 

LNB .............................................................................................................................................. 50 7.55 8,090 

Selective Non-Catalytic Reduction .............................................................................................. 50 7.55 36,949 

Step 4: Evaluate Impacts and Document 

Results 

The Line 1 Dryer has modest NOX

emissions of 15.1 TPY. The combustion 

control technologies produce good 

control efficiencies at a lower cost 

compared to the post-combustion 

options. A low NOX burner produces a 

7.55 TPY NOX reduction at a cost of 

$8,090 per ton. 

Step 5: Evaluate Visibility Impacts 

Visibility impacts were not modeled 

because no additional reductions are 

required. 

Step 6: Propose BART 

Given that the control options are 

modest reductions in NOX emission on 

a TPY basis, that modest reduction 

would need to provide a strong 

visibility improvement or be trivial in 

cost to justify a BART limit indicative 

of additional control. That is not the 

case for the Tilden Line 1 Dryer. Thus, 

EPA is proposing the current good 

combustion practice as the NOX

emission restrictions for the Line 1 

Dryer. 

C. Bart Visibility Improvement Analysis 

1. Background 

There are five factors considered in a 

case-by-case BART analysis once a 

source has been determined to be 

subject to BART. The first four pertain 

to identifying and evaluating available 

control technologies based on technical 

feasibility, emission control levels, 

control cost effectiveness, and energy 

and non-air quality environmental 

impacts. The first four factors have been 

discussed elsewhere in this proposed 

rulemaking. The fifth factor covers the 

visibility improvements resulting from 

the BART emission controls. The ‘‘Final 

Regional Haze Regulations and 

Guidelines for Best Available Retrofit 

Technology Determinations’’ document 

discussed in EPA’s ‘‘Regional Haze 

Regulations and Guidelines for Best 

Available Retrofit Technology (BART) 

Determinations’’ final rule (70 FR 

39104) (Regional Haze Rule) addresses 

application of the fifth factor. Although 

it is a required element of a BART 

analysis, there is substantial flexibility 

allowed in determining how the 

visibility impacts factor is implemented 

and how much weight and significance 

is assigned to this factor. 

2. Visibility Improvement Modeling 

EPA is relying on visibility 

improvement modeling conducted 

previously by the MPCA and 

documented in MPCA’s document 

‘‘Visibility Improvement Analysis of 

Controls Implemented Due to BART 

Determinations on Emission Units 

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12The deciview is a visual index designed to be 

linear with respect to perceived visibility changes 

over its entire range in a way that is analogous to 

the decibel index for sound. The deciview scale is 

zero for pristine conditions and increases as 

visibility degrades. 

13All fine particulates, including sulfates, 

nitrates, and other fine particulate components. 

Subject-to-BART,’’ October 23, 2009, 

and also detailed in ‘‘Appendix 9.5: 

BART Visibility Modeling,’’ included as 

part of MPCA’s December 2009 regional 

haze SIP submittal. 

The visibility improvement modeling 

conducted by MPCA examined the 

degree of visibility improvement in the 

Class I areas of Voyageurs National Park 

(Voyageurs), Boundary Waters Canoe 

Area Wilderness (Boundary Waters), 

and Isle Royale National Park (Isle 

Royale), determined to be impacted by 

NOX and SO2 sources and Stateestimated BART emission reductions 

covered in MPCA’s BART analysis. The 

sources investigated by the MPCA, and 

of interest in our BART proposed rule, 

were Minnesota Power-Boswell Energy 

Center, Minnesota Power-Taconite 

Harbor, Northshore Mining-Silver Bay, 

and United Taconite-Fairlane Plant 

(now named United Taconite). These 

sources are located in the same general 

area as the sources addressed by BART 

determinations in this proposed rule. 

The discussion below uses MPCA’s 

emissions data and modeled visibility 

impact data to derive visibility impact 

ratios as a function of changes in 

emissions of NOX and SO2 at MPCAmodeled facilities. These visibilityemissions ratios were then applied to 

the BART-based emission changes for 

the sources subject to this BART rule to 

derive possible visibility impacts. 

The modeling system used by MPCA 

for BART visibility analyses is 

discussed in detail in ‘‘Technical 

Support Document of the Minnesota 

State Implementation Plan for Regional 

Haze,’’ May 2009, and in Appendix 9.5 

of MPCA’s December 2009 regional haze 

SIP submittal. The system utilizes: 

• Comprehensive Air Quality Model 

(CAMx) as the photochemical modeling 

tool, 

• The Pennsylvania State University/ 

National Center for Atmospheric 

Research (PSU/NCAR) Mesoscale 

Meteorological Model (MM5) as the 

meteorological model, 

• Emissions Modeling System (EMS– 

2003) as the emissions model. The base 

period modeling for the MPCA work 

included emissions from 2002. 

The Particulate Source Apportionment 

Technology (PSAT) tool in CAMx, along 

with the new IMPROVE visibility 

extinction formula (to calculate light 

extinction resulting from monitored or 

modeled nitrate, sulfate, and PM2.5

concentrations and assumed relative 

humidity (pH) extinction factors) was 

used to evaluate air quality/visibility 

impacts from the individual sources. 

The modeling domain featured a 36 

kilometer resolution grid extending over 

the eastern two-thirds of the United 

States, and encompassed a smaller 12 

kilometer resolution nested modeling 

domain, with Plume-in-Grid (PiG) 

concentration estimates, covering all of 

Minnesota. Visibility was assessed in 

each of the three Class I areas using 15 

modeling receptors in Voyageurs, 62 

modeling receptors in Boundary Waters, 

and 15 modeling receptors in Isle 

Royale. 

The MPCA modeling examined the 

impact of the BART controls on both the 

number of days (DDays) with a change 

(increase) in deciview 12 above 0.5 

(DDays > 0.5) and the 98th percentile 

change in deciview values (Ddv). 

Only one of the sources examined by 

MPCA and addressed here included 

emission changes from furnaces at a 

taconite facility. This facility, United 

Taconite, is located in St. Louis County, 

Minnesota, roughly 60–80 kilometers 

from the Class I areas in Northern 

Minnesota, Voyageurs and Boundary 

Waters, and approximately 120 

kilometers from Isle Royale. The MPCA 

modeling compared the 2002 actual 

emissions used in Minnesota’s regional 

haze SIP modeling to the emissions 

assumed based on the state-determined 

BART emission controls with 

corresponding modeled emission 

reductions for NOX and sulfur dioxide. 

Modeling was conducted for the 

meteorological years of 2002 and 2005. 

The results are shown in MPCA’s BART 

analysis in terms of the change in Ddv 

and DDays for PM2.5,13 sulfate (SO4), and 

nitrate (NO3). 

The MPCA visibility modeling 

documentation details visibility due to 

the implementation of BART controls 

for all of the sources considered by the 

State. However, the FIP covered by this 

proposed rule only addresses BART 

control of furnaces located at taconite 

facilities. Therefore, we have given 

special attention to the visibility 

modeling results for the one taconite 

facility addressed in detail in MPCA’s 

BART visibility modeling discussion, 

United Taconite. 

The detailed modeling information for 

United Taconite, as presented in 

MPCA’s visibility modeling 

documentation is duplicated below: 

TABLE V–C.1—EMISSIONS (UNITED TACONITE) 

[Actual 2002 Emissions in Tons Modeled] 

Description Stack ID NOX SO2 PM2.5 PM10

Facility Elevated Stack Total* 1,765 3,222 183 473. 

BART Unit Stack Total ...................... SV049 1,764 3,222 13 367. 

BART Unit Stack Percent of Facility 

Total Emissions*.

100% 100% 7% 78%. 

BART Unit Stack Total with BART 

Controls.

1,764 1,385 No BART Controls. 

BART Unit Stack Emission Reduction due to BART Controls.0% ¥57% 

* Facility total only accounts for emissions from elevated stacks. The criteria for elevated stacks is those with a plume rise of 50 meters or 

more as calculated by the emissions model. 

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TABLES V–C.2 THROUGH V–C.4—NUMBER OF DAYS WITH VISIBILITY DEGRADATION > 0.5 DV AND 98TH PERCENTILE

DECIVIEW IMPACT VALUES (UNITED TACONITE) 

Class I Area 

Parameter Met Year 

Boundary Waters Voyageurs Isle Royale 

Base BART Change Base BART Change Base BART Change 

PM2.5

Days > 0.5 dv ...................................... 2002 59 44 ¥15 32 20 ¥12 8 1 ¥7 

2005 40 24 ¥16 22 11 ¥11 3 2 ¥1 

’02 & 05 99 68 ¥31 54 31 ¥23 11 3 ¥8 

98th Percentile dv ............................... 2002 3.0 1.7 ¥1.3 1.8 0.8 ¥0.9 0.6 0.3 ¥0.3 

2005 1.5 1.1 ¥0.4 1.0 0.7 ¥0.3 0.4 0.2 ¥0.2 

’02 & 05 3.1 1.9 ¥1.2 1.9 1.1 ¥0.8 0.6 0.3 ¥0.3 

SO4

Days > 0.5 dv ...................................... 2002 47 29 ¥18 29 17 ¥12 8 0 ¥8 

2005 32 15 ¥17 20 6 ¥14 3 0 ¥3 

’02 & 05 79 44 ¥35 49 23 ¥26 11 0 ¥11 

98th Percentile dv ............................... 2002 3.0 1.6 ¥1.4 1.7 0.8 ¥0.9 0.5 0.3 ¥0.3 

2005 1.4 0.7 ¥0.7 0.9 0.5 ¥0.4 0.4 0.2 ¥0.2 

’02 & 05 3.0 1.7 ¥1.3 1.9 1.0 ¥0.9 0.6 0.3 ¥0.3 

NO3

Days > 0.5 dv 2002 5 8 3 0 1 1 0 0 0 

2005 7 11 4 1 4 3 0 1 1 

’02 & 05 12 19 7 1 5 4 0 1 1 

98th Percentile dv ............................... 2002 0.4 0.5 0.1 0.1 0.1 0.0 0.1 0.1 0.0 

2005 0.5 0.6 0.1 0.2 0.2 0.1 0.1 0.1 0.0 

’02 & 05 0.6 0.7 0.2 0.2 0.3 0.1 0.1 0.1 0.0 

As the tables indicate, while there 

were no NOX emission reductions 

associated with the State’s assessed 

BART emission controls at United 

Taconite, the SO2 emission reductions 

resulted in reductions in the number of 

days with deciview changes above 0.5 at 

all three Class I areas, including DDays 

reductions in excess of 10 at Boundary 

Waters and Voyageurs. Additionally, the 

98th percentile deciview values were 

reduced (Ddv) for each Class I area. 

These improvements were associated 

with a 1,837 tons per year reduction in 

SO2 emissions at this facility. Because 

there were no reductions in NOX at 

United Taconite associated with the 

State-determined BART emission 

controls, the improvement in visibility 

due to SO2 emission reductions are 

offset by visibility degradation resulting 

from small nitrate increases. According 

to MPCA, the reduced levels of SO2

downwind from United Taconite would 

allow more ammonia in the atmosphere 

to become available to react with NOX

to form ammonium nitrate, a compound 

that can contribute to visibility 

impairment. 

The modeled SO2 emission reduction 

and visibility impacts for PM2.5 can be 

used to derive visibility impact/ 

emission reduction ratios at each of the 

Class I areas. Table V–C.5 presents the 

modeled emission reductions and 

derived visibility impact ratios for fine 

particulates for United Taconite at each 

of the Class I areas. Note that the 

DDaysPM2.5 numbers used in this table 

(and in subsequent tables) are annual 

averages. Also note that, in this table 

and in subsequent tables, we have 

considered Ddv and DDays values for 

PM2.5, which include the visibility 

impacts of both nitrates and sulfates, as 

well as other fine particulate 

components. 

TABLE V–C.5—BART NOX AND SO2 EMISSION REDUCTIONS AND MODELED VISIBILITY IMPACT/EMISSION REDUCTION

RATIOS FOR FINE PARTICULATES AT CLASS I AREAS FOR UNITED TACONITE

Parameter Boundary Waters Voyageurs Isle Royale 

NOX Emissions Decrease .............................................. 0 tons/year 

SO2 Emissions Decrease (DSO2) ................................... 1,837 tons/year 

DdvPM2.5 .......................................................................... ¥1.2 ............................................................................... ¥0 .8 ¥0 .3 

DdvPM2.5/DSO2 ................................................................. ¥0.00065 ....................................................................... ¥0 .00043 ¥0 .000098 

DDaysPM2.5 ...................................................................... ¥10 ................................................................................ ¥8 ¥3 

DDaysPM2.5/DSO2 ............................................................ ¥0.0054 ......................................................................... ¥0 .0044 ¥0 .0016 

Other sources addressed in MPCA’s 

modeling study would reduce both NOX

and SO2 emissions through the 

implementation of BART emission 

controls. Three examples of sources 

considered for BART controls are 

located near the Class I areas of interest, 

Minnesota Power-Taconite Harbor, 

Minnesota Power-Boswell Energy 

Center, and Northshore Mining-Silver 

Bay. Both Minnesota Power-Taconite 

Harbor and Northshore Mining-Silver 

Bar are located near Lake Superior and 

east of the Minnesota taconite facilities 

considered in this FIP proposed rule. 

Minnesota Power-Boswell Energy 

Center is located in northern Minnesota 

and west of the area encompassing the 

Minnesota taconite facilities considered 

in this FIP proposed rule. All three of 

these source facilities addressed by the 

MPCA would have both NOX emission 

reductions and SO2 emission reductions 

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under MPCA’s-determined BART 

emission controls. 

We have used the State’s modeled 

BART emission reductions and 

visibility impacts for fine particulates to 

determine the sensitivity of visibility 

parameters for the Class I areas to 

changes in NOX and SO2 emissions. The 

modeled emission changes, Ddv, and 

DDays values used to calculate the 

sensitivity of visibility parameters to 

emission changes were taken from 

Appendix 9.5 of Minnesota’s December 

2009 SIP revision submittal. 

Table V–C.6 presents the modeled 

emission reductions and derived 

visibility impact ratios for Minnesota 

Power-Boswell Energy Center at each of 

the Class I areas. 

TABLE V–C.6—BART NOX AND SO2 EMISSION REDUCTIONS AND MODELED VISIBILITY IMPACT/EMISSION REDUCTION

RATIOS FOR FINE PARTICULATES AT CLASS I AREAS FOR MINNESOTA POWER-BOSWELL ENERGY CENTER

Parameter Boundary Waters Voyageur Isle Royale 

NOX Emissions Decrease (DNOX) ................................. 3,978 tons/year 

SO2 Emissions Decrease (DSO2) ................................... 11,952 tons/year 

DdvPM2.5 .......................................................................... ¥2.1 ............................................................................... ¥2 .0 ¥0 .9 

DdvPM2.5/DNOX ................................................................ ¥0.00053 ....................................................................... ¥0 .00050 ¥0 .00023 

DdvPM2.5/DSO2 ................................................................. ¥0.00018 ....................................................................... ¥0 .00017 ¥0 .000075 

DDaysPM2.5 ...................................................................... ¥30 ................................................................................ ¥21 ¥15 

DDaysPM2.5/DNOX ........................................................... ¥0.0075 ......................................................................... ¥0 .0053 ¥0 .0038 

DDaysPM2.5/DSO2 ............................................................ ¥0.0025 ......................................................................... ¥0 .0018 ¥0 .0013 

Table V–C.7 presents the modeled 

emission reductions and derived 

visibility impact ratios for fine 

particulates for Minnesota PowerTaconite Harbor at each of the Class I areas. 

TABLE V–C.7—BART NOX AND SO2 EMISSION REDUCTIONS AND MODELED VISIBILITY IMPACT/EMISSION REDUCTION

RATIOS FOR FINE PARTICULATES AT CLASS I AREAS FOR MINNESOTA POWER-TACONITE HARBOR

Parameter Boundary Waters Voyageur Isle Royale 

NOX Emissions Decrease (DNOX) ................................. 399 tons/year 

SO2 Emissions Decrease (DSO2) ................................... 566 tons/year 

DdvPM2.5 .......................................................................... ¥0.4 ............................................................................... ¥0 .1 ¥0 .3 

DdvPM2.5/DNOX ................................................................ ¥0.0010 ......................................................................... ¥0 .00025 ¥0 .00075 

DdvPM2.5/DSO2 ................................................................. ¥0.00071 ....................................................................... ¥0 .00018 ¥0 .00053 

DDaysPM2.5 ...................................................................... ¥4 .................................................................................. ¥2 ¥3 

DDaysPM2.5/DNOX ........................................................... ¥0.010 ........................................................................... ¥0 .0050 ¥0 .0075 

DDaysPM2.5/DSO2 ............................................................ ¥0.0071 ......................................................................... ¥0 .0035 ¥0 .0053 

Table V–C.8 presents the modeled 

emission reductions and derived 

visibility impact ratios for fine 

particulates for Northshore MiningSilver Bay at each of the Class I areas. 

TABLE V–C.8. BART NOX AND SO2 EMISSION REDUCTIONS AND MODELED VISIBILITY IMPACT/EMISSION REDUCTION

RATIOS FOR FINE PARTICULATES AT CLASS I AREAS FOR NORTHSHORE MINING-SILVER BAY

Parameter Boundary Waters Voyageur Isle Royale 

NOX Emissions Decrease (DNOX) ................................. 678 tons/year 

SO2 Emissions Decrease (DSO2) ................................... 444 tons/year 

DdvPM2.5 .......................................................................... ¥0.2 ............................................................................... ¥0 .1 ¥0 .2 

DdvPM2.5/DNOX ................................................................ ¥0.00029 ....................................................................... ¥0 .00023 ¥0 .00029 

DdvPM2.5/DSO2 ................................................................. ¥0.00045 ....................................................................... ¥0 .00023 ¥0 .00045 

DDaysPM2.5 ...................................................................... ¥5 .................................................................................. ¥1 ¥3 

DDaysPM2.5/DNOX ........................................................... ¥0.0074 ......................................................................... ¥0 .0015 ¥0 .0044 

DDaysPM2.5/DSO2 ............................................................ ¥0.011 ........................................................................... ¥0 .0023 ¥0 .0068 

The above visibility factor/emission 

change ratio data show significant 

variation from source-to-source and 

between impacted Class I areas. This 

variation is caused by differences in the 

relative locations of the sources (relative 

to the locations of the Class I areas), 

variations in background sources, 

variations in transport patterns on high 

haze factors, and other factors that we 

cannot assess without detailed modeling 

of the visibility impacts for the sources 

as a function of pollutant emission type. 

The above data, however, can be used 

to approximate possible visibility 

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49332 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

impacts due to the production of fine 

particulates downwind of the taconite 

facilities addressed in this FIP proposed 

rule. To estimate the visibility impacts, 

we have averaged the fine particulate 

Ddv and DDays emission change ratios 

for NOX and SO2 for the four sources 

documented in Tables V–C.5 through 

V–C.8 above for each of the Class I 

areas. These averaged visibility factor/ 

emission change ratios are summarized 

in Table V–C.9. 

TABLE V–C.9—AVERAGED VISIBILITY IMPACT/EMISSION CHANGE RATIOS FOR ANALYZED/IMPACTED CLASS I AREAS

Parameter ratio Boundary 

Waters Voyageurs Isle Royale 

DdvPM2.5/DNOX ................................................................................................................................... ¥0 .00061 ¥0 .00033 ¥0 .00040 

DdvPM2.5/DSO2 .................................................................................................................................... ¥0 .00050 ¥0 .00025 ¥0 .00029 

DDays/DNOX ...................................................................................................................................... ¥0 .0083 ¥0 .004 ¥0 .005 

DDays/DSO2 ....................................................................................................................................... ¥0 .0067 ¥0 .0030 ¥0 .0033 

To calculate the visibility impacts for 

the Minnesota source facilities covered 

by this FIP proposed rule, we multiplied 

the total estimated BART NOX and SO2

emission reductions for each subject 

facility by the appropriate visibility 

factor/emission change ratios in Table 

V–C.9 and combined the results to 

estimate the total visibility impacts that 

would result from the reduction of PM2.5

concentrations. The estimated visibility 

factor changes by Class I area for each 

of the subject taconite facilities in 

Minnesota are given in Tables V–C.10 

through V–C.15. 

TABLE V–C.10—ESTIMATED EMISSION REDUCTIONS AND RESULTING CHANGES IN VISIBILITY FACTORS FOR

ARCELORMITTAL

Visibility factor or pollutant emissions reduction Boundary Waters Voyageur Isle Royale 

NOX Emissions Reduction ................................................ 2,859 tons/year 

Ddv .................................................................................... ¥1.7 ................................................................................. ¥0.9 ¥1.1 

DDays > 0.5 dv ................................................................. ¥24 .................................................................................. ¥11 ¥18 

TABLE V–C.11—ESTIMATED EMISSION REDUCTIONS AND RESULTING CHANGES IN VISIBILITY FACTORS FOR HIBBING

TACONITE

Visibility factor or pollutant emissions reduction Boundary Waters Voyageur Isle Royale 

NOX Emissions Reduction ................................................ 5,259 tons/year 

Ddv .................................................................................... ¥3.2 ................................................................................. ¥1.7 ¥2.1 

DDays > 0.5 dv ................................................................. ¥44 .................................................................................. ¥21 ¥26 

TABLE V–C.12—ESTIMATED EMISSION REDUCTIONS AND RESULTING CHANGES IN VISIBILITY FACTORS FOR NORTHSHORE

MINING

Visibility factor or pollutant emissions reduction Boundary Waters Voyageur Isle Royale 

NOX Emissions Reduction ................................................ 926 tons/year 

Ddv .................................................................................... ¥0.6 ................................................................................. ¥0.3 ¥0.4 

DDays > 0.5 dv ................................................................. ¥8 .................................................................................... ¥4 ¥5 

TABLE V–C.13—ESTIMATED EMISSION REDUCTIONS AND RESULTING CHANGES IN VISIBILITY FACTORS FOR UNITED

TACONITE

Visibility factor or pollutant emissions reduction Boundary Waters Voyageur Isle Royale 

NOX Emissions Reduction ................................................ 3,208 tons/year 

SO2 Emissions Reduction ................................................. 3,639 tons/year 

Ddv .................................................................................... ¥1.9 ................................................................................. ¥0.99 ¥1.16 

DDays > 0.5 dv ................................................................. ¥29 .................................................................................. ¥12 ¥14 

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TABLE V–C.14—ESTIMATED EMISSION REDUCTIONS AND RESULTING CHANGES IN VISIBILITY FACTORS FOR U.S. STEELKEETAC

Visibility factor or pollutant emissions reduction Boundary Waters Voyageur Isle Royale 

NOX Emissions Reduction ................................................ 2,908 tons/year 

Ddv .................................................................................... ¥1.8 ................................................................................. ¥1.0 ¥1.2 

DDays > 0.5 dv ................................................................. ¥28 .................................................................................. ¥12 ¥15 

TABLE V–C.15—ESTIMATED EMISSION REDUCTIONS AND RESULTING CHANGES IN VISIBILITY FACTORS FOR U.S. STEELMINNTAC

Visibility factor or pollutant emissions reduction Boundary Waters Voyageur Isle Royale 

NOX Emissions Reduction ................................................ 6,077 tons/year 

SO2 Emissions Reduction ................................................. 980 tons/year 

Ddv .................................................................................... ¥3.3 ................................................................................. ¥1.7 ¥2.1 

DDays > 0.5 dv ................................................................. ¥45 .................................................................................. ¥21 ¥26 

From Tables V–C.10 through V–C.15, 

it can be seen that the BART emission 

controls determined for the Minnesota 

taconite facilities have the potential to 

produce significant improvements in 

visibility at all three Class I areas. 

The State of Michigan has provided 

some emissions, air quality, and 

visibility modeling data for Tilden that 

may be used to provide an estimate of 

the visibility impact for the 

implementation of BART emission 

controls at Tilden. The Michigan SIP 

submittal for regional haze, dated 

October 2010, does include BART 

assessment data for Tilden, and Tilden 

NOX and SO2 emissions have been 

modeled, along with the emissions for 

many other source facilities to derive 

visibility impacts at two Class I areas, 

Isle Royale National Park and Seney 

National Wildlife Refuge (Seney). 

Maximum visibility impacts have been 

determined for each modeled source 

facility at the two Class I areas. To 

model the visibility impacts, air quality 

impacts were estimated for each 

pollutant emitted using the CALPUFF 

model for 2000–2004 emissions. The 

modeled air quality impacts were 

entered through the IMPROVE visible 

extinction equation to calculate the 

visual extinction coefficient for each 

modeled facility. The facility-specific 

visual extinction coefficients were used 

to calculate the facility-specific 

visibility impact in deciviews. The 

modeling results for Tilden are 

discussed in Appendices 9H: ‘‘Tilden 

Mining Company BART Technical 

Analysis,’’ 10E: ‘‘Calpuff Modeling, Q/D 

And Visibility For Seney,’’ and 10D: 

‘‘Calpuff Modeling, Q/D And Visibility 

For Isle Royale’’ for Michigan’s October 

2010 haze SIP submittal. 

The visibility modeling for Tilden 

shows that it contributed 0.674 

deciviews, with 41 days exceeding 0.5 

deciviews from 2002–2004, at Isle 

Royale National Park. Over 96 percent 

of the modeled SO2 and NOX emissions 

from Tilden were from its indurating 

furnace. Michigan’s post control 

modeling scenario no. 3 reflects both 80 

percent NOX and SO2 emission 

reductions, which are similar to the 

controls being proposed as BART and 

these reductions result in a 0.501 

deciview improvement at IRNP. The 

visibility impact resulting from 70 

percent reduction for both SO2 and NOX

can be approximated by taking 7⁄8 of 

0.501, which results in an improvement 

of 0.438 deciviews. 

In conclusion, the available 

information indicates that control of 

emissions from taconite plants in 

Minnesota and Michigan can be 

expected to yield significant benefits in 

reducing visibility impairment in the 

Class I areas in the two states. 

Extrapolating from modeling results 

provided by the two states, the impacts 

of candidate control options range from 

about 0.5 deciviews to 3.3 deciviews, 

with between about 10 and about 130 

fewer days over three years with 

impacts above 0.5 deciviews. While 

these estimates are not based on direct 

modeling of the scenarios of interest, the 

scenarios being addressed here are 

sufficiently similar to the scenarios 

addressed in state modeling that EPA 

considers these estimates to provide 

adequate indication of the benefits of 

these controls. Each BART 

determination is a function of 

consideration of visibility 

improvements and other factors for the 

individual unit, but in general EPA’s 

assessment of visibility impacts finds 

that technically feasible controls that are 

available at a reasonable cost for 

taconite plants can be expected to 

provide a visibility benefit that makes 

those controls warranted. 

D. Testing and Monitoring, 

Recordkeeping, and Reporting 

Requirements. 

To ensure compliance with the 

proposed BART limits, EPA has 

proposed testing and monitoring 

requirements for the taconite plants 

subject to this rule. The proposed FIP 

also includes recordkeeping and 

reporting requirements for these 

sources. 

VI. Proposed Action 

We are proposing to approve the 

following NOX and SO2 BART limits for 

the taconite plants in Minnesota and 

Michigan that are subject to BART. 

U.S. Steel Minntac 

NOX—A limit of 1.2 lbs/MMBtu on a 

30-day rolling average for all lines to be 

achieved as follows: 1 Year after the 

effective date of this rule for line 6, 2 

years after the effective date for Line 7, 

3 years after the effective date for Line 

4, 4 years after the effective date for Line 

5, and 4 years and 11 months after the 

effective date for Line 3. 

SO2—71.3 lbs SO2/hr for Line 3, 56.1 

lbs SO2/hr for Line 4, 67.9 lbs SO2/hr for 

Line 5, 64.5 lbs SO2/hr for Line 6, and 

67.1 lbs SO2/hr for Line 7. Compliance 

is to be achieved with these limits 

within three months after the effective 

date of this rule. These limits are 

measured on a 30-day rolling average. 

Northshore Mining 

NOX—A limit of 1.2 lbs/MMBtu on a 

30-day rolling average for all lines to be 

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49334 Federal Register / Vol. 77, No. 158 / Wednesday, August 15, 2012 / Proposed Rules 

achieved as follows: 1 Year and 6 

months after the effective date for Line 

11 and 2 years and 6 months after the 

effective date for Line 12. An emission 

limit of 0.085 lb/hr as a 30-day rolling 

average shall apply to each of the 

boilers, Process Boiler #1 and Process 

Boiler #2, beginning no later than 5 

years from the effective date of this rule. 

The process boiler limits shall apply at 

all times a unit is operating. 

SO2—A limit of 16.3 lbs SO2/hr for 

Furnace 11 and 17.1 lbs SO2/hr for 

Furnace 12, measured on a 30-day 

rolling average. These limits do not 

apply when the subject emissions unit 

is burning fuel oil. An 80.0 percent SO2

reduction requirement is also required 

for the stacks serving Furnaces 11 and 

12. Compliance is to be achieved with 

these limits within 6 months after the 

effective date of this rule. 

United Taconite 

NOX—A limit of 1.2 lbs/MMBtu on a 

30-day rolling average for all lines to be 

achieved as follows: 1 Year and 6 

months after the effective date of this 

rule for Line 2 and 2 years and 6 months 

after the effective date for Line 1. 

SO2—A limit of 5 ppmv, on a 30-day 

rolling average, to be achieved within 2 

years after the effective date of this rule 

for Line 2 and 4 years after the effective 

date of this rule for Line 1. As an 

alternative, the owner or operator may 

meet a 95 percent SO2 removal 

efficiency limit, on a 30-day rolling 

average, for Line 1, Line 2, or both lines 

instead of complying with the 5 ppmv 

limit. The owner or operator shall 

comply with the limit within 2 years 

after the effective date of this rule for 

Line 2 and within 4 years after the 

effective date of this rule for Line 1. 

ArcelorMittal 

NOX—A limit of 1.2 lbs/MMBtu on a 

30-day rolling average to be achieved 

within 1 year and 6 months after the 

effective date of this rule for its 

indurating furnace. 

SO2—23.0 lbs SO2/hr, on a 30-day 

rolling average, for its indurating 

furnace. This limit does not apply when 

the subject source is burning fuel oil. 

Compliance is to be achieved with this 

limit within three months after the 

effective date of this rule. 

Hibbing Taconite 

NOX—A limit of 1.2 lbs/MMBtu on a 

30-day rolling average for all lines to be 

achieved as follows: 1 Year and 6 

months after the effective date for Line 

1, 2 years and 6 months after the 

effective date for Line 3, and 3 years and 

6 months for Line 2. 

SO2—A limit of 56.0 lbs SO2/hr for 

Line 1, 63.0 lbs SO2/hr for Line 2, and 

64.0 lbs/hr for Line 3, measured on a 30- 

day rolling average. These limits do not 

apply when the subject source is 

burning fuel oil. Compliance is to be 

achieved with these limits within 3 

months after the effective date of this 

rule. 

U.S. Steel Keewatin 

NOX—A limit of 1.2 lbs/MMBtu on a 

30-day rolling average to be achieved 

within 1 year and 6 months after the 

effective date of this rule for its Phase 

II furnace. 

SO2—Keetac’s existing recirculating 

lime scrubber satisfies BART. This 

scrubber is subject to a 57 percent SO2

removal efficiency and a limit, based on 

CEMS data, of 225 lbs SO2 per hour on 

a 30-day rolling average. This scrubber 

is also required to operate at or above 

a pH of 7.5. Compliance is to be 

achieved with these limits within 90 

days after the effective date of this rule. 

Tilden 

NOX—A limit of 1.2 lbs/MMBtu on a 

30-day rolling average to be achieved 

within 1 year and 6 months after the 

effective date of this rule for its Line 1. 

SO2—A limit of 5 ppmv, on a 30-day 

rolling average, to be achieved within 2 

years after the effective date of this rule 

for Line 1. As an alternative, the owner 

or operator may meet a 95 percent SO2

removal efficiency limit, on a 30-day 

rolling average, for Line 1 instead of 

complying with the 5 ppmv limit. The 

owner or operator shall comply with the 

limit within 2 years after the effective 

date of this rule. An emission limit of 

1.20 percent sulfur content by weight 

shall apply to fuel combusted in Process 

Boiler #1 (EUBOILER1) and Process 

Boiler #2 (EUBOILER2) beginning 3 

months from the effective date of this 

rule. An emission limit of 1.50 percent 

sulfur content by weight shall apply to 

fuel combusted in the Line 1 Dryer 

(EUDRYER1) beginning 3 months from 

the effective date of this rule. 

VII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

This proposed action is not a 

‘‘significant regulatory action’’ under 

the terms of Executive Order 12866 (58 

FR 51735, October 4, 1993) and is 

therefore not subject to review under 

Executive Orders 12866 and 13563 (76 

FR 3821, January 21, 2011). As 

discussed in detail in section C below, 

the proposed FIP applies to only six 

sources. It is therefore not a rule of 

general applicability. 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

Reduction Act, 44 U.S.C. 3501 et seq. 

Under the Paperwork Reduction Act, a 

‘‘collection of information’’ is defined as 

a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

persons * * * .’’ 44 U.S.C. 3502(3)(A). 

Because the proposed FIP applies to just 

six facilities, the Paperwork Reduction 

Act does not apply. See 5 CFR 1320(c). 

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a federal 

agency. This includes the time needed 

to review instructions; develop, acquire, 

install, and utilize technology and 

systems for the purposes of collecting, 

validating, and verifying information, 

processing and maintaining 

information, and disclosing and 

providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to a collection of information 

unless it displays a currently valid 

Office of Management and Budget 

(OMB) control number. The OMB 

control numbers for our regulations in 

40 CFR are listed in 40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. 

For purposes of assessing the impacts 

of today’s proposed rule on small 

entities, small entity is defined as: (1) A 

small business as defined by the Small 

Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

population of less than 50,000; and (3) 

a small organization that is any not-formstockstill on DSK4VPTVN1PROD with PROPOSALS5

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profit enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this proposed action on small 

entities, I certify that this proposed 

action will not have a significant 

economic impact on a substantial 

number of small entities. EPA’s 

proposal adds additional controls to 

certain sources. The Regional Haze FIP 

that EPA is proposing for purposes of 

the regional haze program consists of 

imposing Federal control requirements 

to meet the BART requirement for NOX

and SO2 emissions on specific units at 

six sources in Minnesota and one in 

Michigan. The net result of the FIP 

action is that EPA is proposing emission 

controls on the indurating furnaces at 

seven taconite facilities and none of 

these sources are owned by small 

entities, and therefore are not small 

entities. 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

federal agencies to assess the effects of 

their regulatory actions on State, local, 

and Tribal governments and the private 

sector. Under section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to State, local, 

and Tribal governments, in the 

aggregate, or to the private sector, of 

$100 million or more (adjusted for 

inflation) in any one year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Under Title II of UMRA, EPA has 

determined that this proposed rule does 

not contain a federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million by State, local, or Tribal 

governments or the private sector in any 

one year. In addition, this proposed rule 

does not contain a significant federal 

intergovernmental mandate as described 

by section 203 of UMRA nor does it 

contain any regulatory requirements 

that might significantly or uniquely 

affect small governments. 

E. Executive Order 13132: Federalism 

Federalism (64 FR 43255, August 10, 

1999) revokes and replaces Executive 

Orders 12612 (Federalism) and 12875 

(Enhancing the Intergovernmental 

Partnership). Executive Order 13132 

requires EPA to develop an accountable 

process to ensure ‘‘meaningful and 

timely input by State and local officials 

in the development of regulatory 

policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial direct 

effects on the States, on the relationship 

between the national government and 

the States, or on the distribution of 

power and responsibilities among the 

various levels of government.’’ Under 

Executive Order 13132, EPA may not 

issue a regulation that has federalism 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by State and local 

governments, or EPA consults with 

State and local officials early in the 

process of developing the proposed 

regulation. EPA also may not issue a 

regulation that has federalism 

implications and that preempts State 

law unless the Agency consults with 

State and local officials early in the 

process of developing the proposed 

regulation. 

This rule will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132, because it 

merely addresses the State not fully 

meeting its obligation to prohibit 

emissions from interfering with other 

states measures to protect visibility 

established in the CAA. Thus, Executive 

Order 13132 does not apply to this 

action. In the spirit of Executive Order 

13132, and consistent with EPA policy 

to promote communications between 

EPA and State and local governments, 

EPA specifically solicits comment on 

this proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, entitled 

Consultation and Coordination with 

Indian Tribal Governments (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This proposed rule does 

not have tribal implications, as specified 

in Executive Order 13175. It will not 

have substantial direct effects on tribal 

governments. Thus, Executive Order 

13175 does not apply to this rule. 

However, EPA did discuss this action in 

a June 28 conference call with the 

Michigan and Minnesota Tribes. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children from Environmental Health 

Risks and Safety Risks (62 FR 19885, 

April 23, 1997), applies to any rule that: 

(1) Is determined to be economically 

significant as defined under Executive 

Order 12866; and (2) concerns an 

environmental health or safety risk that 

we have reason to believe may have a 

disproportionate effect on children. EPA 

interprets EO 13045 as applying only to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this proposed rule will limit 

emissions of NOX, SO2, and PM, the rule 

will have a beneficial effect on 

children’s health by reducing air 

pollution. 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

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2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12 of the National Technology 

Transfer and Advancement Act 

(NTTAA) of 1995 requires federal 

agencies to evaluate existing technical 

standards when developing a new 

regulation. To comply with NTTAA, 

EPA must consider and use ‘‘voluntary 

consensus standards’’ (VCS) if available 

and applicable when developing 

programs and policies unless doing so 

would be inconsistent with applicable 

law or otherwise impractical. 

The EPA believes that VCS are 

inapplicable to this action. Today’s 

action does not require the public to 

perform activities conducive to the use 

of VCS. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

We have determined that this 

proposed rule, if finalized, will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low-income population. 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Intergovernmental 

relations, Nitrogen dioxide, Particulate 

matter, Reporting and recordkeeping 

requirements, Sulfur oxides, Volatile 

organic compounds. 

Dated: July 13, 2012. 

Susan Hedman, 

Regional Administrator, Region 5. 

40 CFR part 52, as proposed to be 

amended at 77 FR 46912, August 6, 

2012, is proposed to be amended as 

follows: 

PART 52—[AMENDED] 

1. The authority citation for part 52 

continues to read as follows: 

Authority: 42 U.S.C. 7401 et seq. 

2. Section 52.1183 is amended by 

adding paragraphs (j), (k), (l), (m), and 

(n) to read as follows: 

§ 52.1183 Visibility protection. 

* * * 

(j) The requirements of section 169A 

of the Clean Air Act are not met because 

the regional haze plan submitted by the 

state on November 5, 2010, does not 

meet the requirements of 40 CFR 

51.308(e) with respect to NOX and SO2

emissions from Tilden Mining Company 

L.C. of Ishpeming, Michigan. The 

requirements for this facility are 

satisfied by complying with 

§ 52.1183(k–n). 

(k)(1) NOX Emission Limits. An 

emission limit of 1.20 lb NOX/MMBtu at 

7 percent oxygen, based on a 30-day 

rolling average, shall apply to the 

indurating furnace, Grate Kiln Line 1 

(EUKILN1), beginning 1 year and 6 

months from the effective date of this 

rule. 

(2) SO2 Emission Limits. A fuel sulfur 

content limit of no greater than 1.20 

percent sulfur content by weight shall 

apply to fuel combusted in Process 

Boiler #1 (EUBOILER1) and Process 

Boiler #2 (EUBOILER2) beginning 3 

months from the effective date of this 

rule. A fuel sulfur content limit of no 

greater than 1.50 percent sulfur content 

by weight shall apply to fuel combusted 

in the Line 1 Dryer (EUDRYER1) 

beginning 3 months from the effective 

date of this rule. 

(3) The owner or operator of the 

facility must comply with either (3)(i) or 

(3)(ii) for the Grate Kiln Line 1 

(EUKILN1) beginning 2 years from the 

effective date of this rule. The selection 

must be identified in the initial 

notification of compliance required by 

this rule. 

(i) An emission limit of 5 ppmv SO2

at 7 percent oxygen, based on a 30-day 

rolling average, shall apply to the Grate 

Kiln Line 1 (EUKILN1). 

(ii) A 95.0 percent or greater SO2

removal efficiency by the wet/dry FGD, 

based on a 30-day rolling average, shall 

apply to the Grate Kiln Line 1 

(EUKILN1). 

(l) Testing and Monitoring. 

(1) No later than the compliance date 

of this regulation, the owner or operator 

shall install, certify, calibrate, maintain 

and operate a Continuous Emissions 

Monitoring System (CEMS) for NOX on 

Tilden Mining Company unit EUKILN1 

in accordance with 40 CFR63.8, and 

Appendices B and F of Part 60. The 

owner or operator shall install, certify, 

calibrate, maintain and operate a 

continuous diluent monitor (O2 or CO2) 

and continuous flow rate monitor on 

Tilden Mining Company unit EUKILN1 

to allow conversion of the NOX

concentration to units of the standard 

(lbs/MMBtu). Compliance with the 

emission limits for NOX shall be 

determined using data from the CEMS 

corrected to 7 percent oxygen. 

(2) No later than the compliance date 

of this regulation, the owner or operator 

shall install, certify, calibrate, maintain 

and operate one or more CEMS for SO2

on Tilden Mining Company unit 

EUKILN1 in accordance with 40 CFR 

63.8, and Appendices B and F of Part 

60. The owner or operator shall install, 

certify, calibrate, maintain and operate 

one or more continuous diluent 

monitor(s) (O2 or CO2) and continuous 

flow rate monitor(s) on Tilden Mining 

Company unit EUKILN1 to allow 

conversion of the SO2 concentration to 

units of the standard (ppmv). The 

number of monitors is dependent on the 

emission standard selected (5 ppmv or 

a minimum of 95 percent removal 

efficiency). Compliance with the 

emission standard selected for SO2 shall 

be determined using data from the 

CEMS corrected to 7 percent oxygen. 

(3) Except for CEMS breakdowns, outof-control periods, repairs, maintenance 

periods, calibration checks, and zero 

and high-level drift adjustments, all 

CEMS required by this rule shall be in 

continuous operation and meet 

minimum frequency of operation 

requirements at (l)(3)(i–viii) during all 

periods of process operation of the 

indurating furnaces, including periods 

of process unit startup, shutdown, and 

malfunction. 

(i) Continuous monitoring systems for 

measuring the pollutant, NOX or SO2, 

and diluent gas shall complete a 

minimum of one cycle of operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. 

(ii) Hourly averages shall be 

computed using at least one data point 

in each fifteen-minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. 

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(iii) When valid pollutant emission 

data in pounds per hour or pounds per 

million BTU are not obtained because of 

continuous monitoring system 

breakdowns, repairs, calibration checks, 

or zero and span adjustments, emission 

data must be obtained by using other 

monitoring systems approved by the 

EPA, and incorporated into the 

monitoring plan, to provide emission 

data for a minimum of 18 hours in each 

24 hour period and at least 22 out of 30 

successive unit operating days. 

(iv) Data substitution must not be 

used for purposes of determining 

compliance under this regulation. 

(v) All CEMS (and emission testing) 

data shall be reduced and reported in 

units of the applicable standard. 

(vi) A Quality Control Program Plan 

must be developed and implemented for 

all CEMS required by this rule. The plan 

will include, at a minimum, the 

information described at 40 CFR 63.8(d), 

including calibration checks, calibration 

drift adjustments, preventative 

maintenance, data collection, recording 

and reporting, accuracy audits/ 

procedures, periodic performance 

evaluations, and a corrective action 

program for CEMS problems and excess 

emission events. 

(vii) The owner or operator must 

develop and implement a written 

startup, shutdown, and malfunction 

plan for NOX and SO2 according to the 

provisions in § 63.6(e)(3). 

(viii) Performance evaluation of 

continuous monitoring systems. When 

required by a relevant standard the 

owner or operator of an affected source 

being monitored with continuous 

emission monitoring equipment shall 

conduct a performance evaluation of the 

CEMS. Such performance evaluation 

shall be conducted according to the 

applicable specifications and 

procedures described in 40 CFR 63.8(e) 

and incorporated into the Quality 

Control Program Plan. 

(4) No later than the compliance date 

of this regulation, the owner or operator 

of EUKILN1 shall conduct initial 

performance testing for NOX and SO2, in 

accordance with the requirements of 40 

CFR 63.7 and Appendix A of Part 60 to 

determine compliance with applicable 

emission limits/standards. Specific 

testing shall be described in the intent 

to test form submitted in accordance 

with the rule. The general reference 

methods to be used for initial testing 

will include: Methods 1–4, 6–6C, and 7– 

7E. Performance testing for 

demonstrating compliance with NOX

and SO2 emission limits (if the 5 ppmv 

emission standard is selected) shall 

include testing emissions after exiting 

the control device. Performance testing 

for demonstrating compliance with the 

SO2 removal efficiency standard shall 

include measurement of SO2

concentrations at the inlet to the control 

device and in the duct/stack after 

emissions exit the control device. 

(m) Recordkeeping Requirements 

(1)(i) Records must be in a form 

suitable and readily available for 

expeditious review, according to 

§ 63.10(b)(1). 

(ii) As specified in § 63.10(b)(1), 

records must be kept for 5 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(iii) Records must be kept on site for 

at least 2 years after the date of each 

occurrence, measurement, maintenance, 

report, or record according to 

§ 63.10(b)(1). Records may be kept 

offsite for the remaining 3 years. 

(2) Records listed in paragraphs (2)(i) 

through (iv) of this section must be kept 

for a period of five years. 

(i) A copy of each notification and 

report submitted to comply with this 

subpart, including all documentation 

supporting any initial notification or 

notification of compliance status 

submitted, according to the 

requirements in 40 CFR 63.10(b)(2)(xiv). 

(ii) The records in 40 CFR 

63.6(e)(3)(iii) through (v) related to 

startup, shutdown, and malfunction. 

(iii) Records of performance tests and 

performance evaluations as required in 

40 CFR 63.10(b)(2)(viii). 

(iv) Records of all major maintenance 

conducted on emission units, pollution 

control equipment, and CEMS. 

(3) For each CEMS, the records 

specified in paragraphs (3)(i) through 

(vii) of this section must be kept. 

(i) Records described in 40 CFR 

63.10(b)(2)(vi) through (xi). 

(ii) Previous (that is, superceded) 

versions of the performance evaluation 

plan as required in § 63.8(d)(3). 

(iii) Records of the date and time that 

each deviation started and stopped, and 

whether the deviation occurred during a 

period of startup, shutdown, or 

malfunction or during another period. 

(iv) All CEMS data including the date, 

place, and time of sampling or 

measurement, parameters sampled or 

measured, and results. 

(v) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 60, appendix B, Performance 

Specification 2, Procedure 1 or 40 CFR 

part 75. 

(vi) All records required by 40 CFR 

part 60, appendix F, Procedure 1 or 40 

CFR part 75. 

(vii) Records of the NOX emissions in 

the units of the standard. The owner or 

operator shall convert the monitored 

data into the appropriate unit of the 

emission limitation using an 

appropriate conversion factors and Ffactors. F-factors used for purposes of 

this rule shall be documented in the 

monitoring plan and developed in 

accordance with 40 CFR part 60, 

appendix A, Method 19. The owner or 

operator may use an alternate method to 

calculate the NOX emissions upon 

written approval from EPA. 

(n) Reporting Requirements 

(1) Unless otherwise stated all 

requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

by this section shall be submitted, 

unless instructed otherwise, to the 

Office of Enforcement and Compliance 

Assurance, U.S. Environmental 

Protection Agency, Region 5 (E–19J), at 

77 West Jackson Boulevard, Chicago, 

Illinois 60604. 

(2)(i) If the owner or operator is 

required to conduct a performance test, 

a notification of intent to conduct a 

performance test must be submitted at 

least 60 calendar days before the 

performance test is scheduled to begin, 

as required in 40 CFR 63.7(b)(1). 

(ii) If the owner or operator is 

required to conduct a performance test 

or other initial compliance 

demonstration, a notification of 

compliance status must be submitted 

according to 40 CFR 63.9(h)(2)(ii). The 

initial notification of compliance status 

must be submitted by the dates 

specified in paragraphs (2)(ii)(A) 

through (B) of this section. 

(A) For each initial compliance 

demonstration that does not include a 

performance test, notification of 

compliance status must be submitted 

before the close of business on the 30th 

calendar day following completion of 

the initial compliance demonstration. 

(B) For each initial compliance 

demonstration that does include a 

performance test, notification of 

compliance status, including the 

performance test results, must be 

submitted before the close of business 

on the 60th calendar day following the 

completion of the performance test 

according to § 63.10(d)(2). 

(3) The recordkeeping requirements 

for CEMS performance testing are found 

in 40 CFR 60.7(c) and (d). All emission 

data shall be reported in the units of the 

standard. 

(4) The recordkeeping requirements 

for non-continuous performance testing 

are found in 40 CFR 60.7(b). The owner 

or operator shall submit a written report 

of the results from all required nonCEMS performance tests to EPA within 

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90 calendar days of the completion of 

the performance test. 

(5) Compliance Reports. Unless the 

Administrator has approved a different 

schedule, a semiannual compliance 

report must be submitted, according to 

the paragraphs (5)(i) through (iv) of this 

section. 

(i) The first compliance report must 

cover the beginning period on the 

compliance date that is specified for the 

affected source and ended on June 30 or 

December 31, whichever date comes 

first after the compliance date that is 

specified for the affected source. 

(ii) The first compliance report must 

be postmarked or delivered no later than 

July 31 or January 31, whichever comes 

first after the first compliance report is 

due. 

(iii) Each subsequent compliance 

report must cover the semiannual 

reporting period from January 1 through 

June 30 or the semiannual reporting 

period from July 1 through December 

31. 

(iv) Each subsequent compliance 

report must be postmarked or delivered 

no later than July 31 or January 31, 

whichever date comes first after the end 

of the semiannual reporting period. 

(6) Compliance report contents. Each 

compliance report must include the 

information in paragraphs (6)(i) through 

(iii) of this section and, as applicable, in 

paragraphs (6)(iv) through (viii) of this 

section. 

(i) Company name and address. 

(ii) Statement by a responsible 

official, with the official’s name, title, 

and signature, certifying the truth, 

accuracy, and completeness of the 

content of the report. 

(iii) Date of report and beginning and 

ending dates of the reporting period. 

(iv) If the source had a startup, 

shutdown, or malfunction during the 

reporting period and the owner or 

operator took actions consistent with 

the source’s startup, shutdown, and 

malfunction plan, the compliance report 

must include the information in 

§ 63.10(d)(5)(i). 

(v) If there were no deviations from 

the continuous NOX and SO2

compliance requirements that apply to 

the affected source, then a statement 

that there were no deviations from the 

emission limitations during the 

reporting period must be provided. 

(vi) If there were no periods during 

which a continuous monitoring system 

was out-of-control as specified in 

§ 63.8(c)(7), then a statement that there 

were no periods during which a 

continuous monitoring system was outof-control during the reporting period 

must be provided. 

(vii) For each deviation from a NOX

and SO2 emission limitation occurring 

at an affected source where a 

continuous monitoring system is being 

used to comply with the emission 

limitation in this subpart, the 

information in paragraphs (6)(i) through 

(iv) of this section and the information 

in paragraphs (6)(vii)(A) through (K) of 

this section must be included. This 

includes periods of startup, shutdown, 

and malfunction. 

(A) The date and time that each 

malfunction started and stopped. 

(B) The date and time that each 

continuous monitoring system was 

inoperative, except for zero (low-level) 

and high-level checks. 

(C) The date, time, and duration that 

each continuous monitoring system was 

out-of-control, including the 

information in § 63.8(c)(8). 

(D) The date and time that each 

deviation started and stopped, and 

whether each deviation occurred during 

a period of startup, shutdown, or 

malfunction or during another period. 

(E) A summary of the total duration of 

the deviation during the reporting 

period and the total duration as a 

percent of the total source operating 

time during that reporting period. 

(F) A breakdown of the total duration 

of the deviations during the reporting 

period including those that are due to 

startup, shutdown, control equipment 

problems, process problems, other 

known causes, and other unknown 

causes. 

(G) A summary of the total duration 

of continuous monitoring system 

downtime during the reporting period 

and the total duration of continuous 

monitoring system downtime as a 

percent of the total source operating 

time during the reporting period. 

(H) A brief description of the process 

units. 

(I) A brief description of the 

continuous monitoring system. 

(J) The date of the latest continuous 

monitoring system certification or audit. 

(K) A description of any changes in 

continuous monitoring systems, 

processes, or controls since the last 

reporting period. 

(7) Immediate startup, shutdown, and 

malfunction report. If the affected 

source had a startup, shutdown, or 

malfunction during the semiannual 

reporting period that was not consistent 

with the startup, shutdown, and 

malfunction plan, an immediate startup, 

shutdown, and malfunction report must 

be submitted according to the 

requirements in § 63.10(d)(5)(ii). 

(8) Notification of performance 

evaluation. (i) The owner or operator 

shall notify the Administrator in writing 

of the date of the performance 

evaluation simultaneously with the 

notification of the performance test date 

required under § 63.7(b) or at least 60 

days prior to the date the performance 

evaluation is scheduled to begin if no 

performance test is required. 

(ii)(A) Submission of site-specific 

performance evaluation test plan. Before 

conducting a required CEMS 

performance evaluation, the owner or 

operator of an affected source shall 

develop and submit a site-specific 

performance evaluation test plan to the 

Administrator for approval upon 

request. The performance evaluation 

test plan shall include the evaluation 

program objectives, an evaluation 

program summary, the performance 

evaluation schedule, data quality 

objectives, and both an internal and 

external QA program. Data quality 

objectives are the pre-evaluation 

expectations of precision, accuracy, and 

completeness of data. 

(B) The internal QA program shall 

include, at a minimum, the activities 

planned by routine operators and 

analysts to provide an assessment of 

CEMS performance. The external QA 

program shall include, at a minimum, 

systems audits that include the 

opportunity for on-site evaluation by the 

Administrator of instrument calibration, 

data validation, sample logging, and 

documentation of quality control data 

and field maintenance activities. 

(C) The owner or operator of an 

affected source shall submit the sitespecific performance evaluation test 

plan to the Administrator (if requested) 

at least 60 days before the performance 

test or performance evaluation is 

scheduled to begin, or on a mutually 

agreed upon date, and review and 

approval of the performance evaluation 

test plan by the Administrator will 

occur with the review and approval of 

the site-specific test plan (if review of 

the site-specific test plan is requested). 

(D) The Administrator may request 

additional relevant information after the 

submittal of a site-specific performance 

evaluation test plan. 

(E) In the event that the Administrator 

fails to approve or disapprove the sitespecific performance evaluation test 

plan within the time period specified in 

§ 63.7(c)(3), the following conditions 

shall apply: 

(1) If the owner or operator intends to 

demonstrate compliance using the 

monitoring method(s) specified in the 

relevant standard, the owner or operator 

shall conduct the performance 

evaluation within the time specified in 

this subpart using the specified 

method(s); 

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(2) If the owner or operator intends to 

demonstrate compliance by using an 

alternative to a monitoring method 

specified in the relevant standard, the 

owner or operator shall refrain from 

conducting the performance evaluation 

until the Administrator approves the 

use of the alternative method. If the 

Administrator does not approve the use 

of the alternative method within 30 days 

before the performance evaluation is 

scheduled to begin, the performance 

evaluation deadlines specified in 

paragraph (5)(iv) of this section may be 

extended such that the owner or 

operator shall conduct the performance 

evaluation within 60 calendar days after 

the Administrator approves the use of 

the alternative method. Notwithstanding 

the requirements in the preceding two 

sentences, the owner or operator may 

proceed to conduct the performance 

evaluation as required in this section 

(without the Administrator’s prior 

approval of the site-specific 

performance evaluation test plan) if he/ 

she subsequently chooses to use the 

specified monitoring method(s) instead 

of an alternative. 

(F) Neither the submission of a sitespecific performance evaluation test 

plan for approval, nor the 

Administrator’s approval or disapproval 

of a plan, nor the Administrator’s failure 

to approve or disapprove a plan in a 

timely manner shall— 

(1) Relieve an owner or operator of 

legal responsibility for compliance with 

any applicable provisions of this part or 

with any other applicable Federal, State, 

or local requirement; or 

(2) Prevent the Administrator from 

implementing or enforcing this part or 

taking any other action under the Act. 

(iii) Conduct of performance 

evaluation and performance evaluation 

dates. The owner or operator of an 

affected source shall conduct a 

performance evaluation of a required 

CEMS during any performance test 

required under § 63.7 in accordance 

with the applicable performance 

specification as specified in the relevant 

standard. If a performance test is not 

required, or the requirement for a 

performance test has been waived under 

§ 63.7(h), the owner or operator of an 

affected source shall conduct the 

performance evaluation not later than 

180 days after the appropriate 

compliance date for the affected source, 

as specified in § 63.7(a), or as otherwise 

specified in the relevant standard. 

(iv) Reporting performance evaluation 

results. The owner or operator shall 

furnish the Administrator a copy of a 

written report of the results of the 

performance evaluation simultaneously 

with the results of the performance test 

required under § 63.7 or within 60 days 

of completion of the performance 

evaluation if no test is required, unless 

otherwise specified in a relevant 

standard. The Administrator may 

request that the owner or operator 

submit the raw data from a performance 

evaluation in the report of the 

performance evaluation results. 

3. Section 52.1235 is amended by 

adding paragraphs (a), (b), (c), (d) and 

(e) to read as follows: 

§ 52.1235 Regional Haze. 

(a) The requirements of section 169A 

of the Clean Air Act are not met because 

the regional haze plan submitted by the 

state on December 30, 2009, and on May 

8, 2012, does not meet the requirements 

of 40 CFR 51.308(e) with respect to NOX

and SO2 emissions from United States 

Steel Corporation, Keetac of Keewatin, 

Minnesota; Hibbing Taconite Company 

of Hibbing, Minnesota; United States 

Steel Corporation, Minntac of Mountain 

Iron, Minnesota; United Taconite, LLC 

of Forbes, Minnesota; ArcelorMittal 

Minorca Mine, Inc. near Virginia, 

Minnesota; and Northshore Mining 

Company—Silver Bay of Silver Bay, 

Minnesota. The requirements for these 

facilities are satisfied by complying with 

the requirements of § 52.1235. 

(b)(1) NOX Emission Limits. 

(i) United States Steel Corporation, 

Keetac: An emission limit of 1.2 lb NOX/ 

MMBtu at 7 percent oxygen, based on a 

30-day rolling average, shall apply to 

the Grate Kiln pelletizing furnace 

(EU030), beginning 1 year and 6 months 

from the effective date of this rule. 

(ii) Hibbing Taconite Company: An 

emission limit of 1.2 lb NOX/MMBtu at 

7 percent oxygen, based on a 30-day 

rolling average, shall apply to the Line 

1 pelletizing furnace (EU020) beginning 

1 year and 6 months from the effective 

date of this rule. An emission limit of 

1.2 lb NOX/MMBtu at 7 percent oxygen, 

based on a 30-day rolling average, shall 

apply to the Line 2 pelletizing furnace 

(EU021) beginning 3 years and 6 months 

from the effective date of this rule. An 

emission limit of 1.2 lb NOX/MMBtu at 

7 percent oxygen, based on a 30-day 

rolling average, shall apply to the Line 

3 pelletizing furnace (EU022) beginning 

2 years and 6 months from the effective 

date of this rule. 

(iii) United States Steel Corporation, 

Minntac: An emission limit of 1.2 lb 

NOX/MMBtu at 7 percent oxygen, based 

on a 30-day rolling average, shall apply 

to each of the five indurating furnaces 

(EU225, EU261, EU282, EU315, and 

EU334). The owner or operator shall 

comply with this NOX emission limits 

beginning 4 years and 11 months from 

the effective date of this rule for the 

Line 3 indurating furnace (EU225), 

beginning 3 years from the effective date 

of this rule for the Line 4 indurating 

furnace (EU261), beginning 4 years from 

the effective date of this rule for the 

Line 5 indurating furnace (EU282), 

beginning 1 year from the effective date 

of this rule for the Line 6 indurating 

furnace (EU315), and beginning 2 years 

from the effective date of this rule for 

the Line 7 indurating furnace (EU334). 

(iv) United Taconite: An emission 

limit of 1.2 lb NOX/MMBtu at 7 percent 

oxygen, based on a 30-day rolling 

average, shall apply to the Line 1 pellet 

furnace (EU040) beginning 2 years and 

6 months from the effective date of this 

rule. An emission limit of 1.2 lb NOX/ 

MMBtu at 7 percent oxygen, based on a 

30-day rolling average, shall apply to 

the Line 2 pellet furnace (EU046) 

beginning 1 year and 6 months from the 

effective date of this rule. 

(v) ArcelorMittal Minorca Mine: An 

emission limit of 1.2 lb NOX/MMBtu at 

7 percent oxygen, based on a 30-day 

rolling average, shall apply to the 

indurating furnace (EU026) beginning 1 

year and 6 months from the effective 

date of this rule. 

(vi) Northshore Mining Company— 

Silver Bay: An emission limit of 1.2 lb 

NOX/MMBtu at 7 percent oxygen, based 

on a 30-day rolling average, shall apply 

to Furnace 11 (EU100/EU104) beginning 

1 year and 6 months from the effective 

date of this rule. An emission limit of 

1.2 lb NOX/MMBtu at 7 percent oxygen, 

based on a 30-day rolling average, shall 

apply to Furnace 12 (EU110/114) 

beginning 2 years and 6 months from 

the effective date of this rule. An 

emission limit of 0.085 lb/hr at 7 

percent oxygen, based on a 30-day 

rolling average, shall apply to Process 

Boiler #1 (EU003) and Process Boiler #2 

(EU004) beginning 5 years from the 

effective date of this rule. The 0.085 

lb/hr emission limit for each process 

boiler applies at all times a unit is 

operating, including periods of start-up, 

shut-down and malfunction. 

(2) SO2 Emission Limits. 

(i) United States Steel Corporation, 

Keetac: An emission limit of 225 lb 

SO2/hr at 7 percent oxygen, based on a 

30-day rolling average, shall apply to 

the Grate Kiln pelletizing furnace 

(EU030). The owner or operator shall 

also operate its wet scrubber for EU030 

to achieve a minimum SO2 control 

efficiency of 57.0 percent and to achieve 

a hydrogen ion concentration (pH) in 

the scrubber liquid at or above 7.5. 

Compliance with all SO2 emission 

limits, control efficiency and pH 

standards for EU030 is required 

beginning 90 days from the effective 

date of this rule. 

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(ii) Hibbing Taconite Company: 

Emission limits of 56.0 lb SO2/hr at 7 

percent oxygen shall apply to Line 1 

(EU020), 63.0 lb SO2/hr at 7 percent 

oxygen shall apply to Line 2 (EU021), 

and 64.0 lb SO2/hr at 7 percent oxygen 

shall apply to Line 3 (EU022). The SO2

emission limits for these three 

pelletizing furnaces are based on a 30- 

day rolling average and do not apply 

when a unit is combusting fuel oil. 

Compliance with the emission limits is 

required beginning 3 months from the 

effective date of this rule. 

(iii) United States Steel Corporation, 

Minntac: The emission limits for the 

five indurating furnaces are 71.3 lb 

SO2/hr at 7 percent oxygen for Line 3 

(EU225), 56.1 lb SO2/hr at 7 percent 

oxygen for Line 4 (EU261), 67.9 lb 

SO2/hr at 7 percent oxygen for Line 5 

(EU282), 64.5 lb SO2/hr at 7 percent 

oxygen for Line 6 (EU315), and 67.1 lb 

SO2/hr at 7 percent oxygen for Line 7 

(EU334). The SO2 emission limits are 

based on a 30-day rolling average and 

apply to each of the five indurating 

furnaces, beginning 3 months from the 

effective date of this rule. 

(iv) United Taconite: An emission 

limit of 5 ppmv SO2 at 7 percent oxygen 

shall apply to the Line 1 pellet furnace 

(EU040) beginning 4 years from the 

effective date of this rule. As an 

alternate, the owner or operator may 

select to comply with a 95.0 percent or 

greater SO2 removal efficiency, based on 

a 30-day rolling average, on the control 

device for the Line 1 pellet furnace 

(EU040) beginning 4 years from the 

effective date of this rule. An emission 

limit of 5 ppmv SO2 at 7 percent oxygen 

shall apply to the Line 2 pellet furnace 

(EU042) beginning 2 years from the 

effective date of this rule. As an 

alternate, the owner or operator may 

select to comply with a 95.0 percent or 

greater SO2 removal efficiency, based on 

a 30-day rolling average, on the control 

device for the Line 2 pellet furnace 

(EU042) beginning 2 years from the 

effective date of this rule. 

(v) ArcelorMittal Minorca Mine: An 

emission limit of 23.0 lb SO2/hr at 7 

percent oxygen, based on a 30-day 

rolling average, shall apply to the 

indurating furnace (EU026) beginning 3 

months from the effective date of this 

rule. This limit shall not apply when the 

unit is combusting fuel oil. 

(vi) Northshore Mining Company— 

Silver Bay: An emission limit of 16.3 lb 

SO2/hr at 7 percent oxygen, based on a 

30-day rolling average, shall apply to 

Furnace 11 (EU100/EU104). An 

emission limit of 17.1 lb SO2/hr at 7 

percent oxygen, based on a 30-day 

rolling average, shall apply to Furnace 

12 (EU110/EU114). The owner or 

operator shall also operate its control 

device for EU100/EU104 and EU110/ 

EU114 to achieve a minimum SO2

control efficiency of 80.0 percent. The 

owner or operator shall comply with the 

SO2 emission limits/standards 

beginning 6 months from the effective 

date of this rule. These limits shall not 

apply when the subject unit is 

combusting fuel oil. 

(c) Testing and Monitoring. 

(1) No later than the compliance date 

of this regulation, the owner or operator 

of the respective facility shall install, 

certify, calibrate, maintain and operate 

Continuous Emissions Monitoring 

Systems (CEMS) for NOX on United 

States Steel Corporation, Keetac unit 

EU030; Hibbing Taconite Company 

units EU020, EU021, and EU022; United 

States Steel Corporation, Minntac units 

EU225, EU261, EU282, EU315, and 

EU334; United Taconite units EU040 

and EU042; ArcelorMittal Minorca Mine 

unit EU026; and Northshore Mining 

Company—Silver Bay units Furnace 11 

(EU100/EU104) and Furnace 12 (EU110/ 

EU114). All NOX CEMS must be 

installed, certified, calibrated, 

maintained and operated in accordance 

with 40 CFR 63.8, and Appendices B 

and F of Part 60. The owner or operator 

shall install, certify, calibrate, maintain 

and operate a continuous diluent 

monitor (O2 or CO2) and continuous 

flow rate monitor on each unit 

identified by this rule to allow 

conversion of the NOX concentration to 

units of the standard (lbs/MMBtu). 

Compliance with the emission limits for 

NOX shall be determined using data 

from the CEMS corrected to 7 percent 

oxygen. 

(2) No later than the compliance date 

of this regulation, the owner or operator 

shall install, certify, calibrate, maintain 

and operate one or more CEMS for SO2

on United States Steel Corporation, 

Keetac unit EU030; Hibbing Taconite 

Company units EU020, EU021, and 

EU022; United States Steel Corporation, 

Minntac units EU225, EU261, EU282, 

EU315, and EU334; United Taconite 

units EU040 and EU042; ArcelorMittal 

Minorca Mine unit EU026; and 

Northshore Mining Company—Silver 

Bay units Furnace 11 (EU100/EU104) 

and Furnace 12 (EU110/EU114). All SO2

CEMS must be installed, certified, 

calibrated, maintained and operated in 

accordance with 40 CFR 63.8, and 

Appendices B and F of Part 60. The 

owner or operator shall install, certify, 

calibrate, maintain and operate a 

continuous diluent monitor (O2 or CO2) 

and continuous flow rate monitor on 

each unit identified by this rule to allow 

conversion of the SO2 concentration to 

units of the standard (lb/hr, ppmv or a 

minimum of 95 percent removal 

efficiency). The number of monitors is 

dependent on the emission standard 

selected for purposes of demonstrating 

compliance. Compliance with the 

emission standard selected for SO2 shall 

be determined using data from the 

CEMS corrected to 7 percent oxygen. 

(3) Except for CEMS breakdowns, outof-control periods, repairs, maintenance 

periods, calibration checks, and zero 

and high-level drift adjustments, all 

CEMS required by this rule shall be in 

continuous operation and meet 

minimum frequency of operation 

requirements at (c)(3)(i–viii) during all 

periods of process unit operation, 

including periods of process unit 

startup, shutdown, and malfunction. 

(i) Continuous monitoring systems for 

measuring the pollutant, NOX or SO2, 

and diluent gas shall complete a 

minimum of one cycle of operation 

(sampling, analyzing, and data 

recording) for each successive 15- 

minute period. 

(ii) Hourly averages shall be 

computed using at least one data point 

in each fifteen-minute quadrant of an 

hour. Notwithstanding this requirement, 

an hourly average may be computed 

from at least two data points separated 

by a minimum of 15 minutes (where the 

unit operates for more than one 

quadrant in an hour) if data are 

unavailable as a result of performance of 

calibration, quality assurance, 

preventive maintenance activities, or 

backups of data from data acquisition 

and handling system, and recertification 

events. 

(iii) When valid pollutant emission 

data in pounds per hour or pounds per 

million BTU are not obtained because of 

continuous monitoring system 

breakdowns, repairs, calibration checks, 

or zero and span adjustments, emission 

data must be obtained by using other 

monitoring systems approved by the 

EPA, and incorporated into the 

monitoring plan, to provide emission 

data for a minimum of 18 hours in each 

24 hour period and at least 22 out of 30 

successive unit operating days. 

(iv) Data substitution must not be 

used for purposes of determining 

compliance under this regulation. 

(v) All CEMS (and emission testing) 

data shall be reduced and reported in 

units of the applicable standard. 

(vi) A Quality Control Program Plan 

must be developed and implemented for 

all CEMS required by this rule. The plan 

will include, at a minimum, the 

information described at 40 CFR 63.8(d), 

including calibration checks, calibration 

drift adjustments, preventative 

maintenance, data collection, recording 

and reporting, accuracy audits/ 

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procedures, periodic performance 

evaluations, and a corrective action 

program for CEMS problems and excess 

emission events. 

(vii) The owner or operator must 

develop and implement a written 

startup, shutdown, and malfunction 

plan for NOX and SO2 according to the 

provisions in § 63.6(e)(3). 

(viii) Performance evaluation of 

continuous monitoring systems. When 

required by a relevant standard the 

owner or operator of an affected source 

being monitored with continuous 

emission monitoring equipment shall 

conduct a performance evaluation of the 

CEMS. Such performance evaluation 

shall be conducted according to the 

applicable specifications and 

procedures described in 40 CFR 63.8(e) 

and incorporated into Quality Control 

Program Plan. 

(4) No later than the compliance date 

of this regulation, the owner or operator 

of each unit identified in this rule shall 

conduct initial performance testing for 

NOX and SO2, in accordance with the 

requirements of 40 CFR 63.7 and 

Appendix A of Part 60 to determine 

compliance with applicable emission 

limits/standards. Specific testing shall 

be described in the intent to test form 

submitted in accordance with the rule. 

The general reference methods to be 

used for initial testing will include: 

Methods 1–4, 6–6C, and 7–7E. 

Performance testing for demonstrating 

compliance with NOX and SO2 emission 

limits (lb/MMBtu, lb/hr, or ppmv) shall 

include testing emissions after exiting 

the control device. Performance testing 

for demonstrating compliance with the 

SO2 removal efficiency standard shall 

include measuring SO2 concentrations 

at the inlet to the control device and in 

the duct/stack after emissions exit the 

control device. 

(5) No later than the compliance date 

of this regulation, owners or operators 

utilizing a wet scrubber to control SO2

shall include in the performance testing 

an evaluation of compliance with the 

pH limits established by this rule. The 

pH evaluation shall be performed in 

accordance with the requirements of 40 

CFR 163.3 using EPA Method 150.2. 

(d) Recordkeeping Requirements. 

(1)(i) Records must be in a form 

suitable and readily available for 

expeditious review, according to 

§ 63.10(b)(1). 

(ii) As specified in § 63.10(b)(1), 

records must be kept for 5 years 

following the date of each occurrence, 

measurement, maintenance, corrective 

action, report, or record. 

(iii) Records must be kept on site for 

at least 2 years after the date of each 

occurrence, measurement, maintenance, 

report, or record according to 

§ 63.10(b)(1). Records may be kept 

offsite for the remaining 3 years. 

(2) Records listed in paragraphs (2)(i) 

through (iv) of this section must be kept 

for a period of five years. 

(i) A copy of each notification and 

report submitted to comply with this 

subpart, including all documentation 

supporting any initial notification or 

notification of compliance status 

submitted, according to the 

requirements in 40 CFR 63.10(b)(2)(xiv). 

(ii) The records in 40 CFR 

63.6(e)(3)(iii) through (v) related to 

startup, shutdown, and malfunction. 

(iii) Records of performance tests and 

performance evaluations as required in 

40 CFR 63.10(b)(2)(viii). 

(iv) Records of all major maintenance 

conducted on emission units, pollution 

control equipment, and CEMS. 

(3) For each CEMS, the records 

specified in paragraphs (3)(i) through 

(vii) of this section must be kept. 

(i) Records described in 40 CFR 

63.10(b)(2)(vi) through (xi). 

(ii) Previous (that is, superceded) 

versions of the performance evaluation 

plan as required in 63.8(d)(3). 

(iii) Records of the date and time that 

each deviation started and stopped, and 

whether the deviation occurred during a 

period of startup, shutdown, or 

malfunction or during another period. 

(iv) All CEMS data including the date, 

place, and time of sampling or 

measurement, parameters sampled or 

measured, and results. 

(v) Records of quality assurance and 

quality control activities for emissions 

measuring systems including, but not 

limited to, any records required by 40 

CFR part 60, appendix B, Performance 

Specification 2, Procedure 1 or 40 CFR 

part 75. 

(vi) All records required by 40 CFR 

part 60, appendix F, Procedure 1 or 40 

CFR part 75. 

(vii) Records of the NOX emissions in 

the units of the standard. The owner or 

operator shall convert the monitored 

data into the appropriate unit of the 

emission limitation using an 

appropriate conversion factor and Ffactors. F-factors used for purposes of 

this rule shall be documented in the 

monitoring plan and developed in 

accordance with 40 CFR part 60, 

appendix A, Method 19. The owner or 

operator may use an alternate method to 

calculate the NOX emissions upon 

written approval from EPA. 

(e) Reporting Requirements. 

(1) Unless otherwise stated all 

requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

by this section shall be submitted, 

unless instructed otherwise, to the 

Office of Enforcement and Compliance 

Assurance, U.S. Environmental 

Protection Agency, Region 5 (E–19J), at 

77 West Jackson Boulevard, Chicago, 

Illinois 60604. 

(2)(i) If the owner or operator is 

required to conduct a performance test, 

a notification of intent to conduct a 

performance test must be submitted at 

least 60 calendar days before the 

performance test is scheduled to begin, 

as required in 40 CFR 63.7(b)(1). 

(ii) If the owner or operator is 

required to conduct a performance test 

or other initial compliance 

demonstration, a notification of 

compliance status must be submitted 

according to 40 CFR 63.9(h)(2)(ii). The 

initial notification of compliance status 

must be submitted by the dates 

specified in paragraphs (2)(ii)(A) 

through (B) of this section. 

(A) For each initial compliance 

demonstration that does not include a 

performance test, notification of 

compliance status must be submitted 

before the close of business on the 30th 

calendar day following completion of 

the initial compliance demonstration. 

(B) For each initial compliance 

demonstration that does include a 

performance test, notification of 

compliance status, including the 

performance test results, must be 

submitted before the close of business 

on the 60th calendar day following the 

completion of the performance test 

according to § 63.10(d)(2). 

(3) The recordkeeping requirements 

for CEMS performance testing are found 

in 40 CFR 60.7(c) and (d). All emission 

data shall be reported in the units of the 

standard. 

(4) The recordkeeping requirements 

for non-continuous performance testing 

are found in 40 CFR 60.7(b). The owner 

or operator shall submit a written report 

of the results from all required nonCEMS performance tests to EPA within 

90 calendar days of the completion of 

the performance test. 

(5) Compliance Reports. Unless the 

Administrator has approved a different 

schedule, a semiannual compliance 

report must be submitted, according to 

the paragraphs (5)(i) through (iv) of this 

section. 

(i) The first compliance report must 

cover the beginning period on the 

compliance date that is specified for the 

affected source and ended on June 30 or 

December 31, whichever date comes 

first after the compliance date that is 

specified for the affected source. 

(ii) The first compliance report must 

be postmarked or delivered no later than 

July 31 or January 31, whichever comes 

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first after the first compliance report is 

due. 

(iii) Each subsequent compliance 

report must cover the semiannual 

reporting period from January 1 through 

June 30 or the semiannual reporting 

period from July 1 through December 

31. 

(iv) Each subsequent compliance 

report must be postmarked or delivered 

no later than July 31 or January 31, 

whichever date comes first after the end 

of the semiannual reporting period. 

(6) Compliance report contents. Each 

compliance report must include the 

information in paragraphs (6)(i) through 

(iii) of this section and, as applicable, in 

paragraphs (6)(iv) through (viii) of this 

section. 

(i) Company name and address. 

(ii) Statement by a responsible 

official, with the official’s name, title, 

and signature, certifying the truth, 

accuracy, and completeness of the 

content of the report. 

(iii) Date of report and beginning and 

ending dates of the reporting period. 

(iv) If the source had a startup, 

shutdown, or malfunction during the 

reporting period and the owner or 

operator took actions consistent with 

the source’s startup, shutdown, and 

malfunction plan, the compliance report 

must include the information in 

§ 63.10(d)(5)(i). 

(v) If there were no deviations from 

the continuous NOX and SO2

compliance requirements that apply to 

the affected source, then a statement 

that there were no deviations from the 

emission limitations during the 

reporting period must be provided. 

(vi) If there were no periods during 

which a continuous monitoring system 

was out-of-control as specified in 

§ 63.8(c)(7), then a statement that there 

were no periods during which a 

continuous monitoring system was outof-control during the reporting period 

must be provided. 

(vii) For each deviation from a NOX

and SO2 emission limitation occurring 

at an affected source where a 

continuous monitoring system is being 

used to comply with the emission 

limitation in this subpart, the 

information in paragraphs (6)(i) through 

(iv) of this section and the information 

in paragraphs (6)(vii)(A) through (K) of 

this section must be included. This 

includes periods of startup, shutdown, 

and malfunction. 

(A) The date and time that each 

malfunction started and stopped. 

(B) The date and time that each 

continuous monitoring system was 

inoperative, except for zero (low-level) 

and high-level checks. 

(C) The date, time, and duration that 

each continuous monitoring system was 

out-of-control, including the 

information in § 63.8(c)(8). 

(D) The date and time that each 

deviation started and stopped, and 

whether each deviation occurred during 

a period of startup, shutdown, or 

malfunction or during another period. 

(E) A summary of the total duration of 

the deviation during the reporting 

period and the total duration as a 

percent of the total source operating 

time during that reporting period. 

(F) A breakdown of the total duration 

of the deviations during the reporting 

period including those that are due to 

startup, shutdown, control equipment 

problems, process problems, other 

known causes, and other unknown 

causes. 

(G) A summary of the total duration 

of continuous monitoring system 

downtime during the reporting period 

and the total duration of continuous 

monitoring system downtime as a 

percent of the total source operating 

time during the reporting period. 

(H) A brief description of the process 

units. 

(I) A brief description of the 

continuous monitoring system. 

(J) The date of the latest continuous 

monitoring system certification or audit. 

(K) A description of any changes in 

continuous monitoring systems, 

processes, or controls since the last 

reporting period. 

(7) Immediate startup, shutdown, and 

malfunction report. If the affected 

source had a startup, shutdown, or 

malfunction during the semiannual 

reporting period that was not consistent 

with the startup, shutdown, and 

malfunction plan, an immediate startup, 

shutdown, and malfunction report must 

be submitted according to the 

requirements in § 63.10(d)(5)(ii). 

(8) Notification of performance 

evaluation. (i) The owner or operator 

shall notify the Administrator in writing 

of the date of the performance 

evaluation simultaneously with the 

notification of the performance test date 

required under § 63.7(b) or at least 60 

days prior to the date the performance 

evaluation is scheduled to begin if no 

performance test is required. 

(ii)(A) Submission of site-specific 

performance evaluation test plan. Before 

conducting a required CEMS 

performance evaluation, the owner or 

operator of an affected source shall 

develop and submit a site-specific 

performance evaluation test plan to the 

Administrator for approval upon 

request. The performance evaluation 

test plan shall include the evaluation 

program objectives, an evaluation 

program summary, the performance 

evaluation schedule, data quality 

objectives, and both an internal and 

external QA program. Data quality 

objectives are the pre-evaluation 

expectations of precision, accuracy, and 

completeness of data. 

(B) The internal QA program shall 

include, at a minimum, the activities 

planned by routine operators and 

analysts to provide an assessment of 

CEMS performance. The external QA 

program shall include, at a minimum, 

systems audits that include the 

opportunity for on-site evaluation by the 

Administrator of instrument calibration, 

data validation, sample logging, and 

documentation of quality control data 

and field maintenance activities. 

(C) The owner or operator of an 

affected source shall submit the sitespecific performance evaluation test 

plan to the Administrator (if requested) 

at least 60 days before the performance 

test or performance evaluation is 

scheduled to begin, or on a mutually 

agreed upon date, and review and 

approval of the performance evaluation 

test plan by the Administrator will 

occur with the review and approval of 

the site-specific test plan (if review of 

the site-specific test plan is requested). 

(D) The Administrator may request 

additional relevant information after the 

submittal of a site-specific performance 

evaluation test plan. 

(E) In the event that the Administrator 

fails to approve or disapprove the sitespecific performance evaluation test 

plan within the time period specified in 

§ 63.7(c)(3), the following conditions 

shall apply: 

(1) If the owner or operator intends to 

demonstrate compliance using the 

monitoring method(s) specified in the 

relevant standard, the owner or operator 

shall conduct the performance 

evaluation within the time specified in 

this subpart using the specified 

method(s); 

(2) If the owner or operator intends to 

demonstrate compliance by using an 

alternative to a monitoring method 

specified in the relevant standard, the 

owner or operator shall refrain from 

conducting the performance evaluation 

until the Administrator approves the 

use of the alternative method. If the 

Administrator does not approve the use 

of the alternative method within 30 days 

before the performance evaluation is 

scheduled to begin, the performance 

evaluation deadlines specified in 

paragraph (5)(iv) of this section may be 

extended such that the owner or 

operator shall conduct the performance 

evaluation within 60 calendar days after 

the Administrator approves the use of 

the alternative method. Notwithstanding 

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the requirements in the preceding two 

sentences, the owner or operator may 

proceed to conduct the performance 

evaluation as required in this section 

(without the Administrator’s prior 

approval of the site-specific 

performance evaluation test plan) if he/ 

she subsequently chooses to use the 

specified monitoring method(s) instead 

of an alternative. 

(F) Neither the submission of a sitespecific performance evaluation test 

plan for approval, nor the 

Administrator’s approval or disapproval 

of a plan, nor the Administrator’s failure 

to approve or disapprove a plan in a 

timely manner shall— 

(1) Relieve an owner or operator of 

legal responsibility for compliance with 

any applicable provisions of this part or 

with any other applicable Federal, State, 

or local requirement; or 

(2) Prevent the Administrator from 

implementing or enforcing this part or 

taking any other action under the Act. 

(iii) Conduct of performance 

evaluation and performance evaluation 

dates. The owner or operator of an 

affected source shall conduct a 

performance evaluation of a required 

CEMS during any performance test 

required under § 63.7 in accordance 

with the applicable performance 

specification as specified in the relevant 

standard. If a performance test is not 

required, or the requirement for a 

performance test has been waived under 

§ 63.7(h), the owner or operator of an 

affected source shall conduct the 

performance evaluation not later than 

180 days after the appropriate 

compliance date for the affected source, 

as specified in § 63.7(a), or as otherwise 

specified in the relevant standard. 

(iv) Reporting performance evaluation 

results. The owner or operator shall 

furnish the Administrator a copy of a 

written report of the results of the 

performance evaluation simultaneously 

with the results of the performance test 

required under § 63.7 or within 60 days 

of completion of the performance 

evaluation if no test is required, unless 

otherwise specified in a relevant 

standard. The Administrator may 

request that the owner or operator 

submit the raw data from a performance 

evaluation in the report of the 

performance evaluation results. 

[FR Doc. 2012–19789 Filed 8–14–12; 8:45 am] 

BILLING CODE 6560–50–P 

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