Vol. 78 Wednesday, 

No. 25 February 6, 2013 

Part II 

Environmental Protection Agency 

40 CFR Part 52 

Approval and Promulgation of Air Quality Implementation Plans; States of 

Minnesota and Michigan; Regional Haze State Implementation Plan; 

Federal Implementation Plan for Regional Haze; Final Rule 


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8706 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R05–OAR–2010–0954; EPA–R05– 

OAR–2010–0037; FRL–9773–1] 

Approval and Promulgation of Air 

Quality Implementation Plans; States 

of Minnesota and Michigan; Regional 

Haze State Implementation Plan; 

Federal Implementation Plan for 

Regional Haze 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is finalizing a Federal 

Implementation Plan (FIP) to implement 

emission limits that represent Best 

Available Retrofit Technology (BART) 

for certain taconite ore processing 

facilities in Minnesota and Michigan. 

The Clean Air Act (CAA or the ‘‘Act’’) 

and the regional haze rule require 

implementation plans to contain BART 

emission limits for sources subject to 

BART in order to meet the national goal 

of preventing any future and remedying 

any existing impairment of visibility in 

mandatory class I Federal areas arising 

from manmade air pollution. 

DATES: This final rule is effective on 

March 8, 2013. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

Nos. EPA–R05–OAR–2010–0954 and 

EPA–RO5–OAR–2010–0037. All 

documents are listed on the 

www.regulations.gov Web site. Although 

listed in the index, some information is 

not publicly available, i.e., Confidential 

Business Information (CBI) or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

is not placed on the Internet and will be 

publicly available only in hard copy 

form. Publicly available docket 

materials are available either 

electronically through 

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, Environmental Engineer, 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, wherever 

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

the United States Environmental 

Protection Agency (EPA). 

Table of Contents 

I. Background Information 

A. EPA’s Regional Haze Rule and Best 

Available Retrofit Technology 

B. EPA’s Legal Authority To Promulgate a 

FIP 

C. Minnesota and Michigan’s Regional 

Haze SIP Submittals 

D. EPA’s Regional Haze FIP and Related 

Actions 

II. Comments and Responses 

III. What action is EPA taking? 

A. NOX Limits 

B. SO2 Limits 

C. CEMS 

D. Visibility Benefits and Cost 

Effectiveness 

E. Proposed Disapproval of the States’ 

BART Determinations for Taconite 

Facilities 

IV. Statutory and Executive Order Reviews 

I. Background Information 

A. EPA’s Regional Haze Rule and Best 

Available Retrofit Technology 

The regional haze rule required states 

to submit State Implementation Plans 

(SIPs) to implement the rule’s 

requirements by no later than December 

17, 2007. Neither Minnesota nor 

Michigan submitted regional haze SIPs 

by the required date. The Act requires 

EPA to promulgate a FIP within two 

years after EPA finds that a state has 

failed to make a required SIP 

submission unless the state corrects the 

deficiency and EPA subsequently 

approves the SIP. On January 15, 2009, 

EPA formally found that both Minnesota 

and Michigan had failed to timely 

submit SIPs addressing the regional 

haze requirements. This finding 

triggered EPA’s duty to either 

promulgate a regional haze FIP for 

Minnesota and Michigan or approve 

subsequently submitted regional haze 

SIPs. 

Minnesota subsequently submitted to 

EPA a regional haze SIP on December 

30, 2009, a draft supplement to the SIP 

on January 5, 2012, and a final 

supplement to the SIP on May 8, 2012. 

Michigan submitted to EPA a regional 

haze SIP on November 5, 2010. In 

previous rulemakings, EPA approved in 

part the states’ regional haze SIPs for 

addressing most regional haze 

requirements. However, EPA deferred 

action on the states’ BART 

determinations for taconite facilities in 

order to further evaluate the sufficiency 

of those determinations. On August 15, 

2012, EPA proposed to disapprove in 

part the states’ regional haze SIPs with 

regards to their BART determinations 

for taconite facilities, while 

simultaneously proposing to promulgate 

a FIP. In response to comments received 

related to the sufficiency of EPA’s 

reasoning for proposing disapproval of 

the Michigan and Minnesota BART 

determinations, EPA is issuing a 

separate supplemental notice of 

proposed rulemaking to solicit 

additional comments on that issue. 

Nonetheless, despite the fact that EPA 

has not finalized its disapproval of the 

states’ BART determinations, EPA has 

the continuing authority and obligation 

to promulgate a FIP based on its earlier 

finding that Minnesota and Michigan 

had failed to timely submit regional 

haze SIPs. EPA’s duty to promulgate a 

FIP ends only when it has fully 

approved a state submission. EPA has 

determined that the FIP satisfies the 

requirements of the Act and the regional 

haze rule. 

As described in greater detail in the 

proposal to this rulemaking (77 FR 

49308, August 15, 2012), section 169A 

of the 1977 Amendments to the CAA 

created a program for protecting 

visibility in the nation’s national parks 

and wilderness areas. 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 

(45 FR 80084, December 2, 1980). In 

1990, Congress added section 169B to 

the Act to address regional haze issues. 

Accordingly, EPA promulgated a rule to 

address regional haze on July 1, 1999 

(64 FR 35714), which is codified at 40 

CFR part 51, subpart P (‘‘the regional 

haze rule’’). On July 6, 2005, EPA 

published guidelines to assist states, or 

EPA when 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), 

codified at 40 CFR part 51, appendix Y 

(‘‘BART Guidelines’’). 

Among other things, section 169A of 

the Act and 40 CFR 51.308 of the 

regional haze rule require that states, or 

EPA when implementing a FIP, assure 

reasonable progress toward the national 

goal of achieving natural visibility 

conditions in Class I areas by submitting 

an implementation plan that contains 

emission limits representing BART for 

certain BART-eligible sources. 40 CFR 

51.308(d) and (e). Pursuant to 40 CFR 

51.308(e), BART must be determined 

based upon an analysis of the best 


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1 It should be noted that in addition to the 

requirements of section 110(c)(1)(A) of the Act, 

section 110(c)(1)(B) of the Act requires EPA to 

promulgate a FIP where EPA has specifically 

disapproved a state’s SIP submittal. 

Correspondingly, EPA has a continuing duty to 

promulgate the FIP unless a state corrects the 

deficiency and EPA approves the plan or revision 

before EPA promulgates the FIP. Many of the 

commenters to the proposed FIP assumed that the 

statutory basis for EPA’s authority in promulgating 

this FIP is section 110(c)(1)(B) of the Act. We 

acknowledge that the proposed FIP, in identifying 

potential inadequacies in the Minnesota and 

Michigan regional haze SIPs, may have given the 

impression that the authority for promulgating the 

FIP was a specific determination by EPA that the 

States’ SIPs failed to meet the requirements of the 

Act and the regional haze rule. However, as 

clarified in this section, the authority for the 

promulgation of the FIP arises from section 

110(c)(1)(A) of the Act. 

system of continuous emission control 

technology available and associated 

emission reductions achievable for each 

BART-eligible source that is subject to 

BART. In this analysis, the state, or EPA 

when implementing a FIP, must take 

into consideration the technology 

available, the costs of compliance, the 

energy and air quality environmental 

impacts of compliance, any pollution 

control equipment in use at the source, 

the remaining useful life of the source, 

and the degree of visibility 

improvement reasonably anticipated to 

result from the use of such technology. 

CAA section 169A(g)(2); 40 CFR 

51.308(e)(1)(ii)(A). 

The process of establishing BART 

emission limits consists of three steps. 

First, states or EPA identify those 

sources that meet the definition of 

‘‘BART-eligible source’’ set forth at 40 

CFR 51.301. Second, states or EPA 

determine whether such sources ‘‘emit 

any air pollutant which may reasonably 

be anticipated to cause or contribute to 

any impairment of visibility in any such 

area,’’ and is therefore ‘‘subject to 

BART.’’ Third, for each source subject to 

BART, states or EPA then identify the 

appropriate type and level of control for 

reducing emissions by conducting a 

five-step analysis: step 1: identify all 

available retrofit control technologies; 

step 2: eliminate technically infeasible 

options; step 3: evaluate control 

effectiveness of remaining control 

technologies; step 4: evaluate impacts 

and document the results; step 5: 

evaluate visibility impacts. See BART 

Guidelines. 

The regional haze rule required all 

states to submit an implementation plan 

for regional haze meeting the 

requirements of 40 CFR 51.308(d) and 

(e) by no later than December 17, 2007. 

40 CFR 51.308(b). Neither Minnesota 

nor Michigan submitted regional haze 

SIPs to EPA by the required date. 

B. EPA’s Legal Authority To Promulgate 

a FIP 

Section 110 of the Act requires states 

to develop implementation plans with 

enforceable emission limitations and 

other control measures to meet the 

applicable requirements of the Act. A 

state submits its SIPs and SIP revisions 

to EPA for approval. Congress crafted 

the Act to provide for states to take the 

lead in developing SIPs, but balanced 

that decision by requiring EPA to review 

the plans to determine whether a SIP 

meets the requirements of the Act. EPA 

is required to determine whether the 

state’s submittal meets the requirements 

of the Act based on information and 

data available at the time of EPA’s 

review. See Sierra Club v. EPA, 671 F.3d 

955 (9th Cir. 2012). 

Pursuant to section 110(c)(1)(A) of the 

Act, if EPA finds that a state has failed 

to make a required SIP submittal or if 

EPA finds that a state’s required 

submittal is incomplete, then EPA is 

required to promulgate a FIP to fill this 

regulatory gap. Section 110(c)(1)(A) of 

the Act requires EPA to promulgate a 

FIP within two years of its finding that 

a state failed to make a required SIP 

submission. Further, EPA has a 

continuing duty to promulgate a FIP 

even where EPA fails to promulgate a 

FIP within the required two-year period. 

EPA’s duty to promulgate a FIP 

continues unless the state corrects the 

deficiency, and EPA approves the plan 

or revision before EPA promulgates the 

FIP.1

In this rulemaking action, EPA has the 

authority to promulgate a FIP 

addressing the BART determinations of 

certain taconite facilities in Minnesota 

and Michigan based upon the failure of 

both Minnesota and Michigan to timely 

submit regional haze SIPs. As discussed 

above, the regional haze rule required 

all states to submit a regional haze 

implementation plan by December 17, 

2007. 40 CFR 51.308(b). Neither 

Minnesota nor Michigan submitted 

regional haze SIPs to EPA by the 

required date. Therefore, on January 15, 

2009, EPA found that Michigan and 

Minnesota, as well as certain other 

states, had failed to submit SIPs 

addressing the regional haze 

requirements (74 FR 2392). Based upon 

that finding, pursuant to section 

110(c)(1)(A) of the Act, EPA was under 

a continuing duty to promulgate FIPs for 

Minnesota and Michigan to address the 

regional haze requirements of the Act 

and the regional haze rule. This FIP is 

promulgated pursuant to the 

requirements of section 110(c)(1)(A) of 

the Act. 

C. Minnesota and Michigan’s Regional 

Haze SIP Submittals 

Minnesota subsequently submitted to 

EPA a regional haze SIP on December 

30, 2009, a draft supplement to the SIP 

on January 5, 2012, and a final 

supplement to the SIP on May 8, 2012. 

Michigan submitted to EPA a regional 

haze SIP on November 5, 2010. In 

general, with regard to the subject-toBART taconite facilities identified in the 

respective plans, each State identified 

Good Combustion Practices (GCP) as the 

primary control method representing 

BART for NOX. 

On January 25, 2012, EPA proposed 

approval of the Minnesota regional haze 

plan in which EPA, among other things, 

proposed to approve BART for the 

subject-to-BART taconite facilities (77 

FR 3681). However, prior to EPA’s final 

action on Minnesota’s regional haze 

plan on June 12, 2012, EPA learned 

through public comment that Minnesota 

and Michigan had each failed to 

thoroughly analyze all feasible BART 

control technologies for the taconite 

facilities, and that the SO2 and NOX

emission limits set forth in each State’s 

SIP might not reflect BART. Therefore, 

in light of the uncertainty pertaining to 

the States’ BART determinations for 

taconite facilities, EPA deferred action 

on emission limits that Minnesota 

intended to represent BART for taconite 

facilities in the final rule approving the 

Minnesota regional haze SIP (77 FR 

34801, June 12, 2012). Correspondingly, 

EPA proposed approval of certain 

provisions of the Michigan regional 

haze SIP, while deferring any action on 

those provisions of the SIP that 

addressed the requirement for BART for 

the one taconite plant in Michigan to 

which BART applies (77 FR 46912, 

August 6, 2012). Pursuant to section 

110(k)(3) of the Act, EPA may approve 

a SIP revision in part when only a 

portion of a SIP revision meets all 

applicable requirements of the Act. 

D. EPA’s Regional Haze FIP and Related 

Actions 

EPA proposed a FIP on August 15, 

2012 (77 FR 49308) pursuant to section 

110(c)(1)(A) of the Act, based on EPA’s 

finding that Minnesota and Michigan 

failed to timely submit a regional haze 

SIP, and EPA’s continuing duty to 

promulgate a FIP to address such 

failure. At the same time, EPA proposed 

disapproval of the BART determinations 

for the subject-to-BART taconite 

facilities made by Minnesota and 

Michigan for failing to meet the 

requirements of the Act and the regional 

haze rule. However, in regards to the 

proposed disapproval, several 


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commenters raised concerns that EPA 

did not provide adequate notice of its 

rationale for disapproving the States’ 

BART determinations. 

Therefore, EPA is taking two separate 

but related actions. In this rulemaking 

action, EPA is finalizing the FIP for 

BART for the subject taconite plants in 

Michigan and Minnesota. Secondly, in a 

separate action, EPA is issuing and 

seeks comment on a supplemental 

notice of proposed rulemaking 

elaborating upon the Agency’s rationale 

for proposing partial disapproval of the 

Minnesota and Michigan SIPs as they 

pertain to the requirement for BART for 

taconite plants. The full basis for the 

partial disapproval is set forth in the 

separate action. 

II. Comments and Responses 

On August 15, 2012, EPA published a 

Federal Register Notice entitled 

‘‘Approval and Promulgation of 

Implementation Plans; States of 

Minnesota and Michigan; Regional Haze 

Federal Implementation Plan’’ (77 FR 

49308). In this notice, the EPA 

requested comment on EPA’s proposed 

BART determinations and FIP for 

taconite ore processing facilities located 

in Minnesota and Michigan. Public 

comments were accepted at both a 

public hearing held in St. Paul, 

Minnesota, on August 29, 2012, and in 

writing until September 28, 2012. 

EPA received comments from Cliffs 

Natural Resources Inc., ArcelorMittal 

Minorca Mine Inc., the United States 

National Park Service (NPS), the 

Michigan Department of Environmental 

Quality (MDEQ), the United States 

Forest Service, the National Parks 

Conservation Association (NPCA), the 

Fond du Lac Band of Lake Superior 

Chippewa, the Leech Lake Band of 

Ojibwe, the National Tribal Air 

Association, the Red Cliff Band of Lake 

Superior Chippewas, U.S. Steel 

Corporation, and more than 1,000 

private citizens. 

A. General Comments in Support of the 

Proposed Rule 

Commenter: National Parks 

Conservation Association. 

Comment: NPCA supports finalization 

and implementation of the proposed 

controls, which will significantly 

benefit the air quality in the parks, 

wilderness areas, and communities 

surrounding these plants. 

Commenter: 1,244 private citizens 

provided similar comments. 

Comment: As a resident of the upper 

Midwest and a national parks supporter, 

I want to see natural air quality restored 

to Voyageurs and Isle Royale National 

Parks and Boundary Waters Canoe Area 

Wilderness just as Congress intended. 

That’s why I support EPA’s proposal to 

reduce haze-causing pollution from 

taconite plants. These large industrial 

polluters should clean up their air 

pollution under the Regional Haze Rule. 

Reducing haze pollution in our parks 

will bring healthier air to surrounding 

communities as well as more visitors 

who support our local economies. 

That’s why I want EPA to require the 

most effective methods for reducing air 

pollution from taconite plants in 

Michigan and Minnesota. In addition to 

the emission reductions outlined in 

EPA’s proposed plan, I encourage EPA 

to evaluate pollution controls that 

would lead to cleaner air. 

Commenter: Fond du Lac Band of 

Lake Superior Chippewa. 

Comment: The Band strongly 

supports the FIP proposed by Region 5, 

particularly with regard to Region 5’s 

determination that low NOX burners are 

BART for taconite facilities. This option 

is technically feasible as these burners 

have already been installed on 

Minntac’s grate-kiln furnaces and are 

being installed on Essar’s straight-grate 

kiln furnaces. Low NOX burners have 

been shown to be affordable with 

control costs at roughly $500 per ton, 

which is well within the range of costs 

deemed affordable for BART by states 

and EPA. Low NOX burners are a wise 

choice because they prevent NOX from 

ever being formed. This is a key concept 

in pollution prevention. Collection and 

disposal of pollutants can lead to 

secondary environmental problems, as 

well as increased energy consumption. 

The Band contends that installation of 

these burners is an equity issue. It 

would be unfair to allow other facilities 

to operate indefinitely without having to 

install low NOX burners. 

Commenter: Red Cliff Band of Lake 

Superior Chippewa. 

Comment: Red Cliff supports EPA’s 

proposed requirement for low NOX

burners for all subject taconite furnaces 

in Michigan and Minnesota. 

Commenter: Leech Lake Band of 

Ojibwe. 

Comment: Low NOX burners have 

been installed voluntarily, previous to 

this action, by two taconite facilities 

with different furnace systems 

commonly utilized in the taconite 

industry. These system installs have 

shown substantial reductions, up to 60 

to 70 percent, can be achieved with a 

minimal cost of $500 per ton or less. 

The Band also agrees that taking a 

preemptive approach by preventing the 

formation of NOX makes sense versus an 

after-production control technology that 

is less effective and more costly, both 

economically and environmentally. 

Commenter: National Tribal Air 

Association. 

Comment: The Association agrees that 

using low NOX burners as BART for 

both straight and grate-kilns is a good 

approach. Not only is the cost to remove 

NOX inexpensive, but these burners can 

reduce NOX by up to 70 percent. 

Therefore, placing a limit on NOX of 

1.20 pounds per million British Thermal 

Units on a 30-day rolling average for 

facility lines is very reasonable. 

Commenter: National Park Service. 

Comment: NPS agrees with EPA’s 

conclusions 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 area in the 

two states; and that technically feasible 

controls are available at a reasonable 

cost for taconite plants that can be 

expected to provide a visibility benefit 

that makes those controls warranted. 

Commenter: U.S. Forest Service. 

Comment: The Forest Service 

supports the proposed FIP to require 

BART for the taconite plants in 

Minnesota and Michigan. According to 

technical analyses by the State of 

Minnesota and others, the highest 

contributors to haze in the Boundary 

Waters from all sources in the U.S. are 

the taconite industry and power plants. 

We support the emission controls that 

the taconite plants would be required to 

install under the proposed FIP. The FIP 

demonstrates that these controls are 

technically feasible and available for the 

taconite industry to reduce emissions 

and are already being used by some 

within the industry. The 

implementation of the Minnesota 

regional haze plan is nearly five years 

past due. Considerable effort and 

resources have been spent over the past 

ten years developing the technical 

information necessary to complete 

implementation. Much of the technical 

work was done by states, Tribes, and 

FLMs working together through multistate regional planning organizations. 

The Forest Service has monitored 

visibility in the Boundary Waters since 

1985. The results of this technical work 

and monitoring support the requirement 

for BART to reduce impacts to the 

Boundary Waters. 

Response: EPA acknowledges these 

commenters’ support of the Agency’s 

efforts in developing a FIP for the 

taconite industry and agrees. 

B. Comments Concerning the Adequacy 

of the Public Comment Period 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs stated that EPA 

provided inadequate opportunity to 


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2 In fact, Cliffs received a signed copy of the 

proposed FIP on July 17, 2012, nearly a full month 

before the formal start of the comment period. Thus, 

Cliffs had effectively 75 days to prepare its 

comments. 

comment on the proposed FIP. Cliffs 

alleged that 45 days was not a 

reasonable time period to complete the 

task of preparing an appropriate 

response to the proposed FIP given the 

highly technical concerns surrounding 

EPA’s BART determinations for the 

taconite industry. 

Response: EPA disagrees that the 

Agency did not provide an adequate 

opportunity for public comment. 

Section 307(h) of the CAA requires EPA 

to provide ‘‘a reasonable period for 

public participation of at least 30 days’’ 

when promulgating a FIP. Here, EPA 

chose to provide a significantly longer 

45-day public comment period in light 

of the many technical issues 

surrounding EPA’s proposed BART 

determinations for the taconite industry. 

EPA believes that 45 days was a 

reasonable amount of time for Cliffs and 

others to comment on EPA’s proposed 

FIP.2 Cliffs’ assertion that it should have 

been granted an extension to conduct a 

new BART analysis is without merit. 

Cliffs had several years to conduct a 

thorough BART analysis, and its failure 

to timely do so does not bear upon the 

reasonableness of the length of EPA’s 

comment period. Indeed, the fact that 

Cliffs was able to prepare an extensive 

61-page comment document within the 

allotted time supports EPA’s contention 

that 45 days was a reasonable period for 

third parties to comment on the 

proposed FIP. 

C. Comments Questioning EPA’s 

Authority To Issue a Federal 

Implementation Plan 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs stated that EPA has 

not met the threshold requirements for 

issuing a FIP. EPA’s proposed FIP did 

not provide a critique of Minnesota and 

Michigan’s BART determinations for the 

taconite industry or explain why those 

determinations were inadequate. As a 

result, Cliffs argued that EPA does not 

have the legal authority to issue a FIP. 

Response: EPA believes that it has a 

strong basis for proposing disapproval 

of Minnesota and Michigan’s BART 

determinations for the taconite industry. 

Nonetheless, EPA agrees that the 

proposed rule did not provide a 

sufficiently detailed critique of the state 

determinations’ inadequacies. As a 

result, EPA has chosen to issue a 

supplemental notice of proposed 

rulemaking providing additional 

rationale for the Agency’s proposed 

disapproval. Contrary to Cliffs’ 

assertion, however, EPA was not 

required to make a finding that 

Minnesota and Michigan’s BART 

determinations were deficient before 

issuing a FIP. Section 110(c)(1)(A) of the 

CAA provides that EPA ‘‘shall 

promulgate a [FIP] within 2 years after 

the Administrator finds that a State has 

failed to make a required submission 

* * * unless the State corrects the 

deficiency, and the Administrator 

approves the plan or plan revision, 

before the Administrator promulgates 

such Federal Implementation plan.’’ 

Pursuant to the regional haze rule, 

states were required to submit regional 

haze SIPs no later than December 17, 

2007 (64 FR 35714, July 1, 1999). 

Neither Minnesota nor Michigan made 

the required submission by this date. 

Consequently, EPA issued a finding on 

January 15, 2009 that Minnesota and 

Michigan, as well as certain other states, 

had failed to submit SIPs addressing the 

regional haze requirement (74 FR 2392). 

This finding triggered EPA’s statutory 

duty to either approve a subsequent 

state SIP submission or issue a FIP. 

While it is true that Minnesota and 

Michigan subsequently submitted 

regional haze SIPs to EPA, the Agency 

has not approved either of these plans 

with respect to the states’ BART 

determinations for the taconite industry. 

On the contrary, EPA has proposed to 

disapprove the states’ BART 

determinations for failure to meet the 

minimum requirements of the CAA. 

Thus, EPA had both the authority and 

the continuing obligation to issue a FIP 

for the taconite industry in Minnesota 

and Michigan based on the Agency’s 

January 15, 2009 finding of the states’ 

failure to submit. 

Commenter: Michigan Department of 

Environmental Quality (MDEQ). 

Comment: MDEQ commented that 

Section 110(c)(1) of the Act authorizes 

EPA to promulgate a FIP within two 

years after making a finding that a 

state’s SIP submittal does not satisfy the 

CAA. However, the CAA does not allow 

EPA to propose a FIP and 

simultaneously propose disapproval of 

the state’s SIP. 

Response: MDEQ’s interpretation of 

section 110(c)(1) is incorrect. Once EPA 

has made a finding of a state’s failure to 

submit, EPA’s authority and continuing 

obligation to issue a FIP does not end 

until the state has corrected the 

deficiency and EPA has approved a 

subsequently submitted SIP. Nowhere 

in the CAA is there language that limits 

EPA’s authority to simultaneously 

propose a FIP and propose disapproval 

of a state’s SIP where there has been a 

prior finding of a failure to submit. 

Commenter: Cliffs Natural Resources, 

ArcelorMittal Minorca Mine, and 

Michigan Department of Environmental 

Quality (MDEQ). 

Comment: Cliffs and MDEQ stated 

that EPA failed to afford the Minnesota 

and Michigan SIP proposals the 

requisite deference. Under the visibility 

program, states have the primary 

responsibility for establishing standards, 

including BART. Thus, Cliffs and 

MDEQ argued that EPA can disapprove 

a SIP only where it fails to meet 

minimum CAA requirements. 

Response: While Congress intended 

states to take the lead in developing 

regional haze SIPs, it balanced that 

decision by requiring EPA to review 

state plans to determine whether they 

meet the requirements of the CAA. 

EPA’s review is not limited to a 

ministerial type of automatic approval 

of a state’s decisions. Rather, EPA must 

consider not only whether the state 

considered the appropriate factors, but 

whether the state acted reasonably in 

doing so. In undertaking such a review, 

EPA does not ‘‘usurp’’ the state’s 

authority, but ensures that such 

authority is reasonably exercised. 

Here, EPA firmly maintains that 

neither state’s regional haze SIP met the 

minimum requirements of the CAA. 

Among other things, EPA takes issue 

with the states’ assertions that low NOX

burners are not technically feasible 

control options for indurating furnaces 

and that good combustion practices 

represent BART. Nonetheless, EPA 

acknowledges that its August 15, 2012 

proposed action (77 FR 49308) did not 

provide a sufficiently detailed analysis 

of the deficiencies of the states’ BART 

determinations for the taconite industry. 

Therefore, EPA is publishing a 

supplemental notice of proposed 

rulemaking that further addresses the 

Agency’s rational for proposing 

disapproval of the states’ choices 

regarding taconite BART. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that 

Minnesota and Michigan engaged in 

extensive and proper rulemaking efforts. 

Cliffs then proceeded to provide a 

detailed history of each state’s SIPdevelopment process. 

Response: EPA agrees that Minnesota 

and Michigan spent considerable time 

and effort preparing their regional haze 

SIPs. As stated previously, EPA intends 

to publish a supplemental notice of 

proposed rulemaking that further 

addresses the Agency’s rationale for 

proposing disapproval of Minnesota and 

Michigan’s BART determinations for 

taconite facilities. EPA reiterates, 

however, that the Agency had the 


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3The comment period for Michigan’s regional 

haze SIP closed on June 23, 2010. The comment 

period for the Minnesota’s regional haze SIP 

supplement regarding BART at taconite facilities 

closed on February 3, 2010, but EPA was granted 

an extension to submit comments. EPA’s comments 

were submitted on February 10, 2010, and were 

received and considered by MPCA. 

4See Michigan Regional Haze plan: EPA Letter to 

Michigan Department of Environmental Quality 

Regarding BART, May 24, 2012 (Docket # EPA– 

R05–OAR–2010–0954–0008). 

authority and continuing obligation to 

promulgate a FIP for the taconite 

industry based on the Agency’s earlier 

finding that Minnesota and Michigan 

had failed to submit regional haze SIPs 

in a timely manner (74 FR 2392, January 

15, 2009). 

D. Comments Supporting EPA’s 

Authority To Issue a Federal 

Implementation Plan 

Commenter: National Parks 

Conservation Association. 

Comment: At a public hearing on the 

proposed FIP, representatives for one 

taconite owner asserted that EPA lacked 

authority to issue the proposed FIP. The 

company’s assertion has no merit. In 

fact, EPA has an obligation to develop 

a FIP under the CAA. The CAA provides 

states with initial responsibility for 

identifying sources and determining 

BART for purposes of regional haze. It 

is equally clear, however, that EPA 

retains authority to approve or 

disapprove the states’ determinations 

and issue a FIP if necessary to correct 

state plan deficiencies. 

EPA is not only well within its 

authority to promulgate the proposed 

FIP; it is required to do so because the 

state plans do not meet the requirements 

of the CAA. While commenters disagree 

with some of EPA’s proposed BART 

determinations in the taconite FIP, the 

record plainly supports EPA’s finding 

that neither the Minnesota nor the 

Michigan proposal met minimum CAA 

requirements. The National Park 

Service, the National Forest Service, and 

other commenters all submitted detailed 

technical reviews establishing the many 

deficiencies in the BART analysis and 

conclusions of Minnesota and 

Michigan’s plans. 

Response: EPA agrees with the 

commenter that EPA has the authority 

and obligation to issue a FIP. 

E. Comments Concerning the Use of 

New Information To Evaluate Minnesota 

and Michigan’s BART Determinations 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

cannot use new information regarding 

the technical feasibility of low NOX

burners as a control option for 

indurating furnaces to undermine the 

states’ BART determinations. Cliffs 

argued that EPA is seeking to reject 

Minnesota and Michigan’s BART 

determinations based on information 

that was not available to either state at 

the time of their SIP submissions to EPA 

for approval. To support its position, 

Cliffs pointed to EPA’s BART 

Guidelines, which state that new 

technologies need only be considered by 

a state if they become available before 

the close of a state’s public comment 

period. Cliffs alleged that low NOX

burners were not an ‘‘available’’ 

technology because testing at Minntac 

and Essar had either not yet commenced 

or was still ongoing at the time 

Minnesota and Michigan’s periods for 

public comment had ended. 

Commenter: Michigan Department of 

Environmental Quality (MDEQ). 

Comment: MDEQ commented that 

there was not enough information 

available prior to the close of Michigan’s 

public comment period on June 23, 

2010 to indicate that low NOX burners 

had been successfully utilized on 

indurating furnaces. MDEQ also argued 

that EPA’s proposal to find that low 

NOX burners represent BART for NOX at 

Tilden was impermissibly based on 

information generated after the close of 

Michigan’s public comment period. 

Response: EPA disagrees with Cliffs 

and MDEQ’s comments for several 

reasons. First, EPA again reiterates that 

the Agency had the authority and 

responsibility to promulgate a FIP for 

the taconite industry based on the 

Agency’s earlier finding that Minnesota 

and Michigan had failed to submit 

regional haze SIPs in a timely manner 

(74 FR 2392, January 15, 2009). Thus, 

EPA was entitled to rely on whatever 

information was available regarding the 

technical feasibility of low NOX burners 

at the time the Agency performed its 

BART analysis, including results from 

the testing at Minntac and Essar. 

Nonetheless, even if EPA’s authority 

to promulgate a FIP had been based 

solely on final disapproval of the states’ 

BART determinations, the information 

regarding the technical feasibility of low 

NOX burners was not ‘‘new’’ as Cliffs 

suggests. As the BART Guidelines make 

clear, technical feasibility encompasses 

two distinct concepts, ‘‘availability’’ and 

‘‘applicability.’’ 40 CFR part 51, 

appendix Y. A technology is considered 

‘‘available’’ if the source owner may 

obtain it through commercial channels, 

while it is considered ‘‘applicable’’ if it 

can reasonably be installed and 

operated on the source type under 

consideration. As Cliffs pointed out, 

only technologies that are ‘‘available’’ at 

the close of a state’s public comment 

period need be considered as control 

options by the state. 

However, Cliffs’ argument that low 

NOX burners were not an ‘‘available’’ 

technology at the time Minnesota and 

Michigan’s periods for public comment 

had ended is incorrect. Testing at 

Minntac and Essar had nothing to do 

with the ‘‘availability’’ of low NOX

burners. Rather, the testing at those 

facilities concerned the ‘‘applicability’’ 

of low NOX burners to the source type 

in question—indurating furnaces. There 

can be no dispute that low NOX burners 

were ‘‘available’’ at the time that 

Minnesota and Michigan developed 

their regional haze SIPs because this 

technology has been obtainable through 

commercial channels as an option for 

the control of nitrogen oxide emissions 

for many years. Therefore, Minnesota 

and Michigan were required to consider 

low NOX burners in their BART 

analyses, which both states did, albeit 

dismissively. 

Consequently, the sole question 

presented to the states was one of 

‘‘applicability’’—whether low NOX

burners could be successfully installed 

on indurating furnaces. In regards to 

this question, the BART Guidelines 

make clear that ‘‘a commercially 

available control option will be 

presumed applicable if it has been used 

on the same or a similar source type.’’ 

40 CFR part 51, appendix Y. However, 

in contrast to the question of 

‘‘availability,’’ the Guidelines make no 

mention of a cut-off date after which 

states may reject information regarding 

a technology’s ‘‘applicability.’’ Even so, 

contrary to Cliffs’ assertions, both states 

were aware that low NOX burners had 

been successfully installed on two lines 

at U.S. Steel’s Minntac facility prior to 

the end of their respective periods for 

public comment.3 In a June 23, 2010 

letter to the Michigan Department of 

Natural Resources and Environment 

regarding the state’s draft regional haze 

SIP, EPA commented that ‘‘a low-NOX

main burner firing solid fuels’’ had been 

installed at Minntac and that ‘‘work 

done by other companies had 

demonstrated that burner designs that 

lower flame temperature can reduce 

NOX formation in taconite furnaces.’’ 4

Similarly, in a February 10, 2012 letter 

to the Minnesota Pollution Control 

Agency responding to the state’s draft 

regional haze SIP supplement for 

taconite facilities, EPA explained in 

detail that ‘‘U.S. Steel has demonstrated 

the development and use of low NOX

main burners that achieve 70 percent 

NOX reduction on its indurating 


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5See MI Haze FIP, EPA 6–23–10 comments to 

MDEQ on MI Haze submittal (Docket # EPA–R05– 

OAR–2010–0954–0037). 

6 Docket # EPA–R05–OAR–2010–0037–0039. 

7 Docket # EPA–R05–OAR–2010–0037–0070. 

lines.’’ 5 In addition to these comments, 

both states received comments regarding 

the technical feasibility of low NOX

burners from the Forest Service as well. 

Therefore, both Michigan and 

Minnesota were aware that low NOX

burners had been successfully applied 

to indurating furnaces, and Cliffs’ 

arguments that the results of these 

studies somehow constitute ‘‘new’’ 

information are without merit. 

Finally, even if information regarding 

the technical feasibility of installing low 

NOX burners to indurating furnaces was 

not available to Minnesota or Michigan, 

EPA nonetheless had a duty to consider 

any new information that subsequently 

arose when reviewing the states’ SIPs. 

The Ninth Circuit recently held that ‘‘if 

new information indicates to EPA that 

an existing SIP or SIP awaiting approval 

is inaccurate or not current, then, 

viewing air quality and scope of 

emissions with public interest in mind, 

EPA should properly evaluate the new 

information and may not simply ignore 

it without reasoned explanation of its 

choice.’’ Sierra Club v. EPA, 671 F.3d 

955, 967 (9th Cir. 2012). Thus, EPA is 

required, at a minimum, to take new 

information into account during the SIP 

approval process and, if necessary, alter 

its final decision accordingly. 

Commenter: Fond du Lac Band of 

Lake Superior Chippewa. 

Comment: At the public hearing held 

in Saint Paul, Minnesota, on August 29, 

2012, some commenters voiced the 

opinion that low NOX burners should 

not be considered as BART because the 

technology was brought forward after 

the comment period on the Minnesota 

regional haze SIP supplement had 

closed. This is incorrect. Low NOX

burners were in use and under 

consideration both before and during 

the comment period of December 19, 

2011 to February 3, 2012. Discussions 

concerning the installation of low NOX

burners at Minntac began in 2008, and 

the burners themselves were installed in 

2010, several months before the regional 

haze SIP supplement was proposed. 

U.S. Steel’s report to MPCA on the 

performance to-date of their low NOX

burners at Minntac was submitted in 

December of 2011, around the time that 

Minnesota’s SIP supplement went on 

public notice. Additionally, Essar Steel 

committed to the use of low NOX

burners in its new plant near Nashwauk 

in 2010. The record indicates that 

discussions took place between MPCA 

and the taconite facilities around the 

time that the SIP supplement public 

comment period was open. Because of 

the timing of U.S. Steel’s reports and the 

fact that no other economically-feasible 

technology offered more than 15 percent 

control of NOX, those discussions 

almost certainly included the possibility 

of requiring low NOX burners on 

taconite furnaces. 

In light of the emerging use of low 

NOX burners, the U.S. Steel report, and 

the discussions indicated in the record, 

there is no basis for the claim that low 

NOX burners were only brought forward 

after the comment period. Low NOX

burner technology was not a surprise 

and there is no procedural unfairness in 

the EPA considering it. Furthermore, to 

the extent that low NOX burners can 

somehow be construed as new 

information, there is precedent for 

considering new information while 

promulgating regulations. For example, 

on July 20, 2012, EPA informed 

petitioners that it would reconsider its 

Mercury and Toxics Standards based on 

the availability of new technical 

information. 

Commenter: National Parks 

Conservation Association. 

Comment: During the public hearing 

on this matter, a taconite company 

asserted that EPA’s FIP was based on 

‘‘new information’’ that is ‘‘outside the 

record’’ and that the company’s ‘‘due 

process’’ rights were somehow 

jeopardized by EPA’s proposal. As a 

legal matter, the company’s argument 

has no merit. Likewise, as a practical 

matter, the company’s complaints are 

unavailing. 

Response: EPA agrees with these 

commenters that it was appropriate for 

EPA to rely on whatever information 

was available regarding the technical 

feasibility of low NOX burners at the 

time the Agency performed its BART 

analysis. For a more detailed discussion 

of this issue, see EPA’s previous 

response to comments from Cliffs, 

ArcelorMittal, and MDEQ. 

F. Comments Concerning EPA’s Best 

Available Retrofit Technology Analysis 

Commenter: National Parks Service. 

Comment: NPS agrees with EPA and 

with Michigan and Minnesota on the 

BART-eligibility determinations with 

respect to the taconite facilities and the 

states’ determination that BART for 

direct PM is satisfied by the taconite 

MACT rule. 

Response: EPA acknowledges NPS’s 

support. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs objected to EPA’s 

reference to conversations with industry 

competitors and their vendors in 

determining the feasibility of controls 

for Cliffs’ indurating furnaces. Cliffs 

asserted that EPA ignored information 

provided by Cliffs and its process 

engineering firms. 

Response: EPA spent significant time 

with all affected sources and thoroughly 

considered all information. EPA 

acknowledges that it relied heavily 

upon documented information from 

Cliffs’ competitors in the taconite 

industry because these companies have 

experience with low NOX burner 

technology and provided data from 

actual experience with such technology. 

It would have been inappropriate for 

EPA to have ignored substantive 

information based upon actual 

experience. 

1. Comments Asserting That EPA’s 

BART Analysis Did Not Assess all 

Available Technologies 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs claimed that EPA’s 

BART determinations were arbitrary 

because they ignored good combustion 

practices (GCP) as a BART alternative. 

Cliffs stated at the MPCA March 

Citizens Board meeting that ‘‘GCP is 

already required under other federal 

regulations, including the taconite 

MACT rule.’’ 

Response: Cliffs’ support of GCP as 

BART lacks merit because GCP is 

neither defined by the Minnesota 

Pollution Control Agency, nor is it 

typically considered a NOX reduction 

technique. For example, the January 30, 

2009 ‘‘NOX Reduction Analysis’’ done 

by Hatch for U.S. Steel’s Minntac Iron 

Ore Pelletizing Operation did not list 

GCP as a potential NOX reduction 

technology for an indurating furnace.6

Similarly, the 2008 BACT analysis for 

JEA—Greenland Energy Center Units 1 

and 2 did not list GCP as a potential 

NOX control.7 In fact, these analyses 

state that GCP tends to increase NOX

emissions. This is because measures 

taken to minimize the formation of NOX

during combustion inhibit complete 

combustion, which increases emissions 

of carbon monoxide. Conversely, GCP 

aims to reduce carbon monoxide 

emissions. According to the September 

2010 ‘‘We Energies Biomass Energy 

Project Revised Control Technology 

Review for Carbon Monoxide Emissions 

for the Biomass-Fired Boiler,’’ there is 

an inverse relationship between NOX

emissions and carbon monoxide 

emissions, which means that improving 


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8 Docket # EPA–R05–OAR–2010–0037–0069. 

combustion efficiency can increase NOX

emissions.8

Concerning the GCP requirement in 

the taconite MACT rule, GCP for the 

MACT is not the same as GCP for NOX. 

GCP for MACT is aimed at reducing 

emissions of products of incomplete 

combustion (PIC). To minimize PICs, 

the operating conditions targeted are 

generally the opposite from those 

targeted for reducing NOX. As explained 

in the taconite MACT rule (68 FR 61883, 

October 30, 2003), ‘‘The basic method 

used in reducing NOX emissions is a 

reduction in combustion temperature, 

which is the opposite strategy needed 

for minimizing PIC (i.e., increasing 

combustion temperature).’’ In 

conclusion, GCP would be expected to 

increase NOX emissions, not decrease 

them. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

is required to consider ‘‘any existing 

pollution control technology at the 

source.’’ Cliffs argued that EPA failed to 

adequately consider or consistently 

apply this threshold factor to the BART 

determinations in its proposed rule. 

Response: To the extent that Cliffs is 

referring to its use of GCP as an existing 

pollution control technology, neither 

the operational practices that comprise 

GCP nor their impact on reducing 

emissions has been documented by 

Cliffs. As described in detail in the 

response to the previous comment, EPA 

does not consider Cliffs’ use of GCP to 

constitute ‘‘existing control technology’’ 

on these furnaces. 

Commenter: National Parks 

Conservation Association. 

Comment: NPCA commented that 

EPA failed to consider fuel-blend 

alternatives, including greater or 

exclusive use of natural gas at grate-kiln 

furnaces, as part of the Agency’s BART 

analysis for SO2 and NOX. Fuel-blend 

alternatives are a technically feasible 

control option because indurating 

furnaces can successfully be operated 

on alternative fuels, namely fuel blends 

that consist primarily of natural gas. 

Contrary to the taconite plant owners’ 

assertions, consideration of alternative 

fuels is required for BART where 

changing to cleaner fuel would not 

necessitate significant changes at any 

existing facility. There is no legal 

rationale for excluding this viable 

pollution control. Additionally, the 

assertion that alternative fuel costs are 

uncertain has no merit. There is simply 

no factual support for price uncertainty 

being a basis to reject consideration of 

natural gas as an alternative to coal. 

Even if significant uncertainty existed, it 

can be dealt with appropriately in the 

BART analysis. Finally, the assertion 

that moving towards a more natural gasbased fuel blend would mean higher 

NOX emissions in exchange for lower 

SO2 emissions is a red herring. The 

existence of such potential secondary 

impacts is not a reason to discard a 

BART option prior to analysis. It is a 

reason to perform the analysis itself. 

Response: Alternative fuels were not 

considered for the following reasons. 

The straight-grate furnaces at 

ArcelorMittal, Hibbing Taconite, and 

Northshore Mining already burn natural 

gas. Similarly, U.S. Steel’s Keetac and 

Minntac facilities already burn a fuel 

mix of natural gas and low-sulfur coal. 

While fuel-blend alternatives could 

have been considered for the grate-kiln 

furnaces at United Taconite and Tilden, 

EPA proposed to require the most 

stringent control technology, flue-gas 

desulfurization (FGD), at these facilities. 

As the BART Guidelines make clear, 

where EPA or the states choose the most 

stringent control option as BART, other 

control options need not be considered. 

Therefore, EPA was not required to 

consider fuel-blend alternatives as part 

of the Agency’s BART analysis. 

However, EPA notes that subsequent to 

the proposal, Tilden agreed to convert to 

natural gas, while United Taconite will 

be substantially reducing its emissions 

through the use of natural gas and lowsulfur coal. 

Commenter: National Parks 

Conservation Association. 

Comment: EPA’s NOX BART 

determinations conclude that significant 

reductions could be achieved costeffectively by the installation of low 

NOX burners at all taconite kilns. While 

NPCA concurred with this conclusion, 

it commented that EPA failed to fully 

consider the use of regenerative 

selective catalytic reduction (RSCR). For 

instance, although RSCR was noted as 

an available technology in Keetac’s 

BART analysis, EPA’s FIP made no note 

of it. For Tilden, on the other hand, EPA 

noted this option, but only to point out 

that the company found it to be 

infeasible. In fact, this technology 

appears to be feasible for indurating 

furnaces. At a minimum, a more 

thorough evaluation by EPA is 

necessary. In this case, EPA has not 

shown that circumstances preclude the 

application of RSCR to the units in 

question via evaluation of gas 

characteristics or demonstration of 

technical challenges. It has offered no 

evidence that RSCR is technically 

infeasible. A fuller evaluation of this 

technology is warranted as part of a 

BART determination. 

Response: EPA did evaluate postcombustion NOX-control options when 

it reviewed Minnesota’s regional haze 

plan and agreed with the state’s 

determination that post-combustion 

control of NOX emissions from taconite 

facilities are not BART. For the 

proposed and now final rule, EPA 

evaluated new data on the use of low 

NOX burners at taconite facilities and, 

after a five-factor BART analysis, 

determined that low NOX burners are 

BART for these facilities. The BART 

analyses are fully described in section V 

of the proposed rule (77 FR 49308). EPA 

also considered RSCR and related 

selective catalytic reduction 

technologies at some of the subject 

taconite units. EPA concluded in its 

BART analyses that RSCR and other 

post-combustion controls do not 

represent BART for the subject taconite 

units because, after the installation of 

low NOX burners, the incremental costs 

of installing further post-combustion 

controls are unreasonably high. 

Therefore, this final rule requires that 

taconite indurating furnaces meet NOX

emission limits consistent with low 

NOX burner technology. 

Commenter: National Parks 

Conservation Association. 

Comment: EPA’s analysis for SO2

provides evidence that dry FGD is 

feasible for taconite facilities, and the 

Agency requires the use of this 

technology at the three highest emitting 

lines (at United Taconite and Tilden). 

We support these determinations. 

However, EPA fails to fully analyze the 

use of dry FGD on the lower-emitting 

units, instead concluding, without 

support, that it would not be 

‘‘economically reasonable.’’ NPCA asks 

that EPA analyze whether dry FGD, 

clearly a feasible technology, could 

provide cost effective reductions at 

additional units. 

Response: EPA’s BART analysis 

demonstrated that dry FGD is feasible 

for the highest emitting lines when 

those lines are uncontrolled, but 

determined that the same technology 

has unreasonably high incremental costs 

for units with lower uncontrolled 

emissions. EPA notes, however, that 

while FGD was originally proposed as 

BART for the units at United Taconite 

and Tilden, those facilities have since 

agreed to operational limits on the types 

of fuels that may be burned As a result, 

FGD is no longer being required as 

BART. Additional discussion of this 

issue can be found in section III of the 

preamble. 

Commenter: National Parks Service. 

Comment: It appears that low 

temperature oxidation is technically and 

economically feasible for the entire 


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industry. In addition, tail-end SCR with 

natural gas reheat has been found 

technically feasible and borderline 

economically feasible based on a BACT 

analysis from several years ago when 

natural gas prices were much higher. 

Another form of SCR, RSCR looks 

promising, but as a new technology, 

would require trials. 

While we would normally prefer to 

see all of the technically feasible control 

options evaluated, given the time 

constraints and the success of the low 

NOX burner technology, it is likely that 

low NOX burners will reduce NOX so 

much that addition of the other 

technologies would become too 

expensive for this phase of the regional 

haze program. We therefore agree that 

low NOX burners at 1.2 lbs NOX/ 

MMBTU represent BART for the 

taconite industry. By setting such a 

uniform limit, EPA is establishing a 

‘‘level playing field’’ that is achievable 

by all of the taconite plants and will 

provide substantial (almost 16,000 TPY) 

NOX reductions. 

Response: EPA agrees with the 

commenter that post-combustion 

control technologies would likely be 

expensive for additional pollution 

reduction. EPA maintains that low NOX

burners are the appropriate control 

technology for the indurating furnaces 

at the taconite facilities. Thus, EPA is 

finalizing its determination that low 

NOX burners represent BART. 

Commenter: National Parks Service. 

Comment: EPA proposes to determine 

that BART for SO2 for straight-grate 

kilns is existing controls because these 

furnaces do not burn coal. While true, 

they burn fuel oil, which can have a 

high potential for emitting SO2

depending on the fuel’s sulfur content. 

Although the BART Guidelines do not 

mandate fuel switching, they encourage 

evaluation of lower sulfur content fuels. 

For example, limiting fuel sulfur was an 

option considered by EPA for oil-fired 

EGUs in a separate BART rule. We 

suggest that Minnesota consider use of 

lower sulfur fuels in future reasonable 

progress analyses. 

Response: EPA’s data indicate that the 

taconite facilities with straight-grate 

furnaces use natural gas as the primary 

fuel with fuel oil as a back-up fuel only. 

Given the limited use of fuel oil, 

emission reductions from using lower 

sulfur fuel would be limited. 

Nonetheless, EPA agrees with the 

commenter that the state should 

consider the impacts of using a lower 

sulfur fuel in its future reasonable 

progress analyses and is requiring that 

the taconite facilities keep records of 

any future use of fuel oil. 

Commenter: National Parks Service. 

Comment: NPS concurred with EPA’s 

statement that ‘‘[the Agency does] not 

agree that the MPCA and Minntac have 

adequately documented the infeasibility 

of all SO2 controls described.’’ This 

observation is especially pertinent with 

respect to the technical feasibility of 

spray drying absorption (SDA). 

According to the taconite industry 

consultant, SDA is not technically 

feasible because ‘‘the high moisture 

content of the exhaust would lead to 

saturation of the baghouse filter cake 

and plugging of the filters and dust 

collection system.’’ On the contrary, 

SDA requires moisture because a slurry 

of lime and water is injected into the 

spray dryer where the slurry reacts with 

SO2 to form a dry sulfate power that is 

then collected in the baghouse. As long 

as the moisture content of the gas stream 

is not excessive and the temperature is 

not too low, SDA becomes a preferred 

and highly effective SO2 control option. 

It is expected that retrofitting the 

facilities with SDA would eliminate the 

need for the existing Venturi rod 

scrubbers used to control PM on most of 

the taconite furnaces, thus reducing 

water consumption, gas stream moisture 

content, and PM emissions due to the 

higher efficiency of the baghouse. 

Response: In the proposed rule, EPA 

stated that while the state’s 

documentation for determining the 

technical feasibility of all SO2 controls 

was inadequate, EPA did agree with 

Michigan’s conclusion that additional 

SO2 controls, including SDA, were not 

cost effective and therefore not BART. 

EPA has not changed its position on this 

issue in the final rule. 

2. Comments Asserting That EPA’s 

Baseline NOX Emissions Are Arbitrary 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that 

EPA’s baseline NOX assumptions are 

arbitrary. EPA failed to even consider 

the actual emissions from each taconite 

furnace, let alone use them as the 

starting point for calculating furnacespecific baseline emissions. 

Response: EPA disagrees. In the caseby-case BART analysis for each subject 

taconite facility, EPA clearly listed the 

baseline actual annual emissions for 

each taconite furnace (see, e.g., Table 

V–B.24 for Hibbing Taconite (77 FR 

49321)). In the initial stages of the BART 

development process, there was a 

significant lack of emissions data for the 

taconite facilities, as acknowledged by 

MPCA. However, additional monitoring 

and emission reporting from the 

taconite facilities enabled EPA to 

determine baseline NOX emissions for 

each facility. 

G. Comments Concerning EPA’s 

Analysis of Low NOX Burner 

Technology as NOX BART 

1. Comments Supporting EPA’s 

Determination That Low NOX Burners 

Are Technically Feasible 

Commenter: National Parks 

Conservation Association. 

Comment: NPCA commented that 

EPA’s documentation of low NOX

burners demonstrated that significant, 

cost-effective emission reductions are 

afforded by their use on both straightgrate and grate-kiln furnaces. Despite 

this record, a taconite company raised 

several concerns about EPA’s 

determination during the public 

hearing. The concerns were that a given 

control technology will not transfer 

between indurating furnaces of the same 

type, low NOX burners will impact 

processing (product quality, fuel use, 

etc.), and there has been insufficient 

time to study various aspects or impacts 

of this technology. 

These concerns are either misplaced 

or incorrect. As to the first point, low 

NOX burners have been successfully 

applied to a wide variety of units, 

including power plants, refineries, 

chemical companies, and other 

industrial settings, which burn a wide 

variety of fuels, including gas and coal. 

There may be individual differences 

between the burners at different taconite 

units. As is always the case, 

customization to the particular unit will 

be required. However, the differences 

among taconite furnaces of the same 

type are not significant enough to 

conclude that this clearly robust 

technology could not be applied to one 

as well as the others. Indeed, technology 

transfer would be impossible without 

such basic assumptions. 

As to the impact of low NOX burners 

on operational parameters, EPA’s FIP 

includes information addressing the 

points of product quality and fuel use. 

Minntac’s experience demonstrates no 

impact to pellet quality, and after some 

adjustment, no increase in fuel use. 

Finally, far from having had 

insufficient time to analyze these 

controls, the taconite facilities have had 

years in which to contact vendors, do 

engineering studies and modeling, and 

perform testing. The regional haze 

process has been delayed by many years 

at this point. 

Response: EPA agrees with the 

commenter that low NOX burners can be 

used to control NOX emissions from 

both straight-grate and grate-kiln 

indurating furnaces used in the taconite 

processing industry. EPA also agrees 

with the commenter that based on data 

from taconite facilities where low NOX


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8714 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

9 Docket # EPA–R05–OAR–2010–0037–0039. 

10Email from U.S. Steel to EPA dated September 

19, 2012 (Docket # EPA–R05–OAR–2010–0037– 

0071). 

burners are either in use or planned 

product, quality should not be 

compromised. 

Commenter: National Park Service. 

Comment: NPS commented that it 

agreed with EPA’s proposal that BART 

for NOX for the taconite industry is low 

NOX burners achieving a 70 percent 

reduction from both straight-grate and 

grate-kiln furnaces. The proposal for 

grate-kiln lines is supported by research 

sponsored by U.S. Steel. The proposal 

for straight-grate kilns is supported by 

Essar’s testing, which demonstrated a 95 

percent reduction in NOX emissions for 

its new kiln. 

Response: As the commenter points 

out, EPA has determined that low NOX

burners represent BART. However, EPA 

is setting an emission limit for each 

indurating furnace, not a 70 percent 

control requirement. 

2. Comments Asserting That Low NOX

Burners Are Not Technically Feasibility 

on Straight-Grate Kilns 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

made an unsupported presumption that 

the low NOX burner technology tested 

in a 1⁄4-scale pilot test by Essar for a new 

source could be translated to all 

straight-grate furnaces. 

Response: As indicated in test reports, 

NOX emissions from taconite facilities 

are generated primarily by the burner. 

As burner design is the main factor 

contributing to NOX emissions, EPA 

carefully reviewed results of emission 

tests of low NOX burners for the 

different taconite furnace types and 

concluded that low NOX burners are 

technically feasible for straight-grate 

and grate-kiln furnaces. 

Supporting the feasibility of low NOX

burners on straight-grate kilns is a 

September 19, 2011 summary of 

findings presented to the Minnesota 

Pollution Control Board entitled 

‘‘Results of Testing at 1⁄4-Scale of LE 

Low NOX Burner Prototype for StraightGrate Pelletizing Furnaces’’ by Fives 

North American Combustion, Inc. 

(Fives) for Essar.9 After successful 

bench-scale testing of Fives’ low NOX

LE burners that achieved NOX

reductions greater than 70 percent in a 

straight-grate pelletizing furnace, 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 an 

emission rate of 0.25 lbs NOX/MMBTU, 

which is well below the proposed limit 

of 1.2 lbs NOX/MMBTU. Fives 

concluded that NOX emissions in the 

actual straight-grate furnace should be 

consistent with those measured in the 

1⁄4-scale test conditions. The feasibility 

of low NOX burners on straight-grate 

kilns was also confirmed during a June 

20, 2012 call between EPA and a 

national low NOX burner manufacturer, 

Fives North America. Representatives 

from the manufacturing company were 

highly confident of the technical 

feasibility and application of their 

technology in straight-grate taconite 

furnaces. EPA agrees with this 

assessment. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

failed to conduct an independent, caseby-case feasibility analysis as required 

by the Step 2 of the BART Guidelines. 

Minnesota and Michigan previously 

conducted an extensive case-by-case 

BART analysis, eliminating low NOX

burners as technically infeasible for 

every taconite indurating furnace. Cliffs 

asserted that EPA has adopted a ‘‘onesize-fits-all’’ approach that is arbitrary 

and capricious. According to Cliffs, a 

proper feasibility analysis demonstrates 

that the technologies selected by EPA 

are infeasible for Cliffs’ indurating 

furnaces because low NOX burners are 

not technically feasible for straight-grate 

furnaces and grate-kiln furnaces. Cliffs 

asserted that the Fives burner designed 

for Essar cannot be used without sourcespecific engineering and retrofit design. 

Cliffs claimed that U.S. Steel spent two 

years modifying the prototype low NOX

burners installed on Lines 6 and 7 at its 

Minntac facility in an attempt to reach 

desired emission rates while 

combusting solid fuel, such as coal and 

biomass, but were ultimately 

unsuccessful. ArcelorMittal asserted 

that a proper feasibility analysis 

demonstrated that the technologies 

selected by EPA are infeasible for 

Minorca’s indurating furnace. The 

commenters submitted information 

describing indurating furnaces, 

including the different types of 

furnaces, and explained what they 

believe are the differences between 

furnace types. 

Response: EPA believes that its 

finding that low NOX burners are 

technically feasible for both straightgrate and grate-kiln furnaces is 

supported by test results on various kiln 

configurations. Taconite furnaces are all 

based on one of two technologies. 

Straight-grate kilns are based on a 

Dravo-Lurgi design system, while gratekiln furnaces are based on an AllisChalmers design system. EPA 

understands that each specific taconite 

furnace has unique operating 

requirements and specialized 

equipment. However, all furnaces share 

the same fundamental design style, 

either grate-kiln or straight-grate. 

In assessing control technologies for a 

source category, EPA’s BART 

Guidelines state that ‘‘control 

alternatives can include not only 

existing controls for the source category 

in question but also take into account 

technology transfer of controls that have 

been applied to similar source 

categories and gas streams.’’ 40 CFR part 

51, appendix Y. The Guidelines go on 

to explain that ‘‘[c]ontrol technologies 

are technically feasible if either (1) they 

have been installed and operated 

successfully for the type of source under 

review under similar conditions, or (2) 

the technology could be applied to the 

source under review.’’ Id. 

EPA has concluded that there is a 

clear case for technology transfer of low 

NOX burner technology from grate-kiln 

furnaces to straight-grate furnaces. First, 

low NOX burner technology has been 

clearly and successfully demonstrated 

and applied across various industries 

for decades. Second, EPA does not 

consider taconite furnaces to be 

particularly unique given their similar 

fundamental designs. In the case of 

taconite applications, the Fives’ testing 

of a low NOX burner prototype on a 

straight-grate furnace test rig provides 

reasonable assurance that full-scale 

applications, given the appropriate time 

for engineering and shakedown, will be 

both feasible and effective. In addition, 

U.S. Steel has already installed and is 

successfully operating multi-fuel low 

NOX burners on two unique grate-kiln 

indurating furnaces at their Minntac 

facility. Prior to the proposed rule, U.S. 

Steel had already submitted permit 

applications to install low NOX burner 

technologies on two additional furnaces 

at Minntac as well. U.S Steel has not 

indicated any issues with technical 

feasibility that will prevent the 

company from applying low NOX

burners at either its Keetac facility or 

the remaining furnaces at Minntac. In 

response to questions from EPA 

concerning the installation at Minntac, 

U.S. Steel described the modifications it 

made allowing for the successful use of 

low NOX burners when burning either 

coal or natural gas.10 In EPA’s view, this 

information obtained directly from U.S. 

Steel rebuts Cliffs’ claim that the 


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Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 8715 

11For example, during the Society of Mining 

Engineers’ Annual Meeting in New Orleans, 

Louisiana from March 2–6, 1986, a presentation was 

given titled ‘‘Design and Performance of the 

National Steel Pellet Plant High Temperature Heat 

Recuperation System’’ (Docket # EPA–R05–OAR– 

2010–0037–0077). The presentation discussed a 

high temperature heat recuperation system that was 

installed at the National Steel Pellet Company 

facility in Keewatin, Minnesota. The system was 

similar to those installed at Cliffs’ Empire facility 

and U.S. Steel’s Minntac facility. 

12 Docket # EPA–R05–OAR–2010–0037–0037. 

13Essar and Barr Presentation for Society for 

Mining, Metallurgy and Exploration, Duluth, 

Minnesota, April 2012 (Docket # EPA–R05–OAR– 

2010–0037–0039). 

prototype low NOX burner tests were 

unsuccessful. 

Nor is EPA persuaded by Cliffs and 

ArcelorMittal’s arguments that the 

taconite furnaces at their facilities are 

unique to the extent that low NOX

burner technology cannot be applied. 

While EPA understands that a complete 

engineering analysis will be required to 

design furnace-specific low NOX

burners and that a shakedown period 

will be required to understand and 

optimize operations, EPA does not 

believe that the uniqueness of each 

individual taconite furnace proves 

technical infeasibility. The compliance 

times being finalized for each facility in 

this action account for engineering and 

shakedown time. 

Over the years, the taconite industry 

has demonstrated that it can re-engineer 

furnaces to adapt to market changes 

(such as fuel prices), process changes (to 

accommodate variation in the type of 

ore being mined), and new technologies 

(such as heat recuperation systems).11 It 

is clear that depending on the needs and 

priorities of each company, changes to 

the furnaces have and can be made. 

With respect to ArcelorMittal’s 

comment that a proper feasibility 

analysis would demonstrate that the 

technologies selected by EPA are 

infeasible for Minorca’s indurating 

furnace, EPA relies on a September 27, 

2012 report submitted by the 

commenter and authored by Fives North 

American titled ‘‘Retrofitting Low NOX

Burners on the ArcelorMittal Minorca 

Straight-Grate Pelletizing Furnaces.’’ 12

After review, EPA concludes that this 

report supports the Agency’s conclusion 

that low NOX burners are feasible at the 

Minorca facility. EPA therefore 

disagrees with ArcelorMittal’s assertion 

that such technology is infeasible. Fives 

North American was engaged to perform 

an engineering study and recommend 

best options for retrofitting low NOX

burners at the pelletizing furnace at the 

Minorca plant in order to achieve NOX

emission rates below 1.2 lbs NOX/ 

MMBtu under expected operating 

conditions. Fives expressed confidence 

that the company’s experience in 

manufacturing low NOX burners, 

coupled with the successful results of 

the 1⁄4-scale test at Essar, provided 

sufficient assurance that the technology 

could be applied at Minorca while 

preserving pellet quality and energy 

efficiency. 

3. Comments Concerning EPA’s Cost 

Analysis for Low NOX Burners 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

presumed that low NOX burners will 

cost $500/ton at every Cliffs facility 

despite the fact that none of these 

facilities identified low NOX burners as 

technically feasible. EPA’s $500/ton 

across-the-board cost estimate for NOX

control was neither explained in the 

proposed rule nor supported by the 

record. 

Response: EPA did not presume that 

low NOX burners will cost $500/ton at 

every Cliffs facility. EPA’s proposed rule 

stated that ‘‘[b]ased on the range of costeffectiveness values provided, a 

conservative value of $500/ton will be 

used as the cost-effectiveness value for 

low NOX burners’’ (77 FR 49308, 

49312). Data made available by U.S. 

Steel indicate the cost-effectiveness of 

low NOX burners on Minntac’s Line 6 

indurating furnace was $441/ton of NOX

reduced with burning a 60 percent coal/ 

40 percent natural gas fuel mix and 

$221/ton of NOX reduced when burning 

100 percent natural gas. Barr 

Engineering and Essar Steel Minnesota 

have estimated a cost-effectiveness of 

$370/ton of NOX reduced for low NOX

burner technology on a planned 

straight-grate natural gas-fired furnace.13

This furnace is being designed to meet 

a much more stringent emission limit of 

0.25 lbs NOX/MMBtu, compared to 

EPA’s proposed limit of 1.2 lbs NOX/ 

MMBtu. Thus, EPA’s value of $500/ton 

represents a high-end estimate of 

expected cost-effectiveness of the 

selected NOX BART controls and is 

based on itemized costs and annual 

NOX emissions reductions. 

4. Comments Concerning the 

Effectiveness of Low NOX Burners 

Commenter: U.S. Steel. 

Comment: U.S. Steel commented that, 

based upon its experience, the 

appropriate emission factor when 

burning solid fuels is 1.5 lbs NOX/ 

MMBtu, as opposed to the proposed 

NOX limit of 1.2 lbs NOX/MMBtu. U.S. 

Steel supplemented its comment on 

October 15, 2012 with data that support 

a limit of 1.2 lbs NOX/MMBtu while 

burning natural gas and 1.5 lbs NOX/ 

MMBtu while burning solid fuels. U.S. 

Steel proposed that it be subject to the 

solid fuel limit, unless it utilizes 100 

percent natural gas as a fuel for 30 

consecutive days. The natural gas limit 

would then apply and it would remain 

subject to that limit until such time that 

solid fuels were utilized. 

Response: Based on a review of the 

data submitted by U.S. Steel, EPA agrees 

to revise the NOX limits in the final rule 

to 1.2 lbs NOX/MMBtu while an 

indurating furnace is burning 100 

percent natural gas and 1.5 lbs NOX/ 

MMBtu when fuels other than natural 

gas are being used. This revision 

primarily affects U.S. Steel Keetac, U.S. 

Steel Minntac, and United Taconite. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

made an unsupported presumption that 

an emission limit of 1.2 lbs NOX/ 

MMBtu is equivalent to a 70 percent 

NOX reduction at every Cliffs facility 

and that all taconite furnaces emit NOX

at an uncontrolled baseline rate of 4.0 

lbs NOX/mmBTU in disregard of furnace 

variability. 

Response: The NOX emission limit 

that EPA proposed was 1.2 lbs NOX/ 

MMBtu on a 30-day rolling average. 

This emission limit was not based on a 

percent reduction requirement, but 

rather was based on a demonstration by 

U.S. Steel that low NOX burners 

installed at the Minntac facility could 

achieve this emission limit. This limit is 

further supported for straight-grate kilns 

by successful testing of a low NOX

burner prototype at a 1/4-scale test rig 

at Essar. It is standard industry practice 

to perform pilot tests, in which the 

results of a smaller unit are scaled up to 

a full production unit. Furthermore, in 

this case the company was extremely 

confident that, based upon the results 

with the 1/4-scale test rig, a limit much 

lower than 1.2 lbs NOX/MMBtu could 

be achieved on the full production unit. 

However, based on additional test data 

of operational low NOX burners 

submitted by U.S. Steel for Lines 6 and 

7 at Minntac, EPA is revising its 

proposed limit of 1.2 lbs NOX/MMBtu 

on a 30-day rolling average. In the final 

rule, taconite indurating furnaces are 

subject to a limit of 1.2 lbs NOX/MMBtu 

when only natural gas is burned and 1.5 

lbs NOX/MMBtu when fuels other than 

natural gas are used. Both of these limits 

are based on a 30-day rolling average. 

H. Comments Concerning Non-Air 

Quality Impacts of Low NOX Burners 

1. Effect on Pellet Quality 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 


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8716 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

14 Docket # EPA–R05–OAR–2010–0037–0071. 15 Docket # EPA–R05–OAR–2010–0037–0039. 16U.S. Steel email to EPA dated September 19, 

2012 (Docket # EPA–R05–OAR–2010–0037–0071). 

17 Docket # EPA–R05–OAR–2010–0037–0071. 

Comment: Cliffs commented that 

pellet quality cannot be maintained after 

the installation of low NOX burner 

technology. 

Response: EPA disagrees. Based on 

data supplied by U.S. Steel, EPA has 

concluded that there will be no pellet 

quality challenges resulting from the 

installation and operation of low NOX

burner technology. In an email sent by 

U.S. Steel to EPA on September 19, 

2012, U.S. Steel indicated that pellet 

quality specifications have not changed 

since the installation of low NOX

burners, with zero off-spec shipments to 

date.14 There have been no adverse 

pellet quality issues related to the 

installation and operation of the low 

NOX burners. 

U.S. Steel is required to maintain four 

pellet quality parameters, after tumble, 

compressions, reducibility, and low 

temperature disintegration (LTD), to 

meet customer specifications. U.S. Steel 

supplied EPA with data confirming that 

pellet quality parameters were 

acceptable after the installation of the 

Line 6 low NOX burner (Table 1). U.S. 

Steel also included more recent quality 

parameter data to show that quality 

continues to remain acceptable. U.S. 

Steel noted that while compressions 

have decreased, this has been observed 

on all process lines, including those 

without low NOX burners, thus 

indicating an issue with the feed 

material and not the burners. As also 

shown, U.S. Steel saw an improvement 

in reducibility for their pellets after the 

installation, which U.S. Steel attributes 

to improved heat distribution in the kiln 

from the low NOX burner. 

TABLE 1—LINE 6 PELLET QUALITY BEFORE AND AFTER THE LOW NOX BURNER INSTALLATION

(Higher values represent better quality) 

After tumble Compression Reducibility LTD 

Before (11/1/10–4/3/11) ................................................................................... 96.0 416 1.15 87.30 

After (4/20/11–10/31/11) .................................................................................. 96.0 417 1.22 85.58 

1/1/12–9/1/12 ................................................................................................... 96.2 410 1.22 86.11 

2. Fuel Penalty and Energy Penalty 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that a 

fuel penalty and an energy penalty will 

result from the operation of low NOX

burner technology at its facilities. 

Additional fans will be required to 

increase primary air flow through the 

furnaces because the cooler air that is 

injected into the burner to control peak 

flame temperature must be heated. EPA 

made an unsupported presumption that 

low NOX burners will cause no fuel or 

energy penalties or other emissions 

increases at any of the facilities. 

Response: EPA disagrees. The 

installation and use of low NOX burners 

is not generally considered to result in 

an energy penalty because one burner is 

merely being replaced by another. EPA 

recognizes that there is an increase in 

electricity needed for the operation of 

low NOX burner fans to assist in 

movement of air through the system or 

to heat cooler air that is injected into the 

burner. These costs can in most cases 

simply be factored into the cost impacts 

analysis as they were in this case for 

both NOX and SO2 controls. 

EPA believes that a low NOX burner 

installation that is properly engineered 

and optimized for a given process will 

not result in a fuel or energy penalty. 

EPA’s conclusion is based on the U.S. 

Steel Minntac Line 6 Low NOX Main 

Burner & Facility NOX Management 

Final Report (December 1, 2011),15

which documented that low NOX

burners did not cause fuel penalties or 

other emission impacts. In addition, 

EPA consulted with a burner 

manufacturer and reviewed information 

provided by U.S. Steel regarding 

potential fuel impacts potentially 

associated with the operation of low 

NOX burners at a taconite facility.16 In 

this correspondence, U.S. Steel Minntac 

stated that there was a temporary 10.5 

percent fuel increase after initial 

installation of the low NOX burner on 

Line 7. However, during the shakedown 

period, the fuel increase was alleviated 

by process optimization (there was a 

learning curve due to the fact that this 

was the first low NOX burner installed 

on an iron ore processing line) and 

balancing the process airflow. The waste 

gas fan on Line 7 was running at 

maximum before the burner installation 

and with the addition of combustion air, 

the process efficiency decreased and 

safety issues were created. To alleviate 

this condition, the waste gas fan airflow 

capacity was increased in February 2011 

on Line 7 to balance the airflow out of 

the process. In April 2011, the Line 6 

low NOX burner was installed at U.S. 

Steel’s Minntac facility. After applying 

what was learned during the shakedown 

period on Line 7, no increase in process 

fuel occurred after the installation. U.S. 

Steel clearly states in its September 19, 

2012 email to EPA, ‘‘The end result is 

there is no increase in process fuel due 

to the installation of the Line 7 low NOX

burner.’’ 17

In summary, based on available data, 

EPA believes that with process 

optimization, proper balancing of 

process air flows, and proper 

engineering, Cliffs and ArcelorMittal 

will be able to achieve similar fuel usage 

to U.S. Steel and will not incur either 

a fuel or energy penalty. EPA 

understands that each company will 

require a shakedown period similar to 

that experienced at U.S. Steel and has 

set the compliance schedules each 

facility accordingly. 

3. Increases in the Emission of Other 

Pollutants 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that 

emissions of other pollutants will 

increase due to the installation of low 

NOX burner technology. 

Response: EPA has determined that 

there will be no increases in collateral 

pollutants due to the installation of low 

NOX burner technology. In making this 

determination, EPA relied on the 

information supplied by MPCA, U.S. 

Steel, Coen Company, Inc., and Hatch, 

as described below. 

In a letter dated November 3, 2009 

from Coen Company, Inc., Coen stated: 

As we have indicated, the kiln burner that 

we proposed to supply for the above 

referenced project will not produce more CO 

as compared with what is being produced by 

the existing burner. The reason is: carbon 

monoxide (CO) is formed from lack of fast 

mixing of NO and oxidant (O2) and chemical 

kinetics of the reaction that is highly 

dependent on temperature and O2

concentration. The Coen multi-fuel burner is 

being designed for higher stoichiometric air 

(1.00) as compared with the existing burner 

which has a stoichiometric air of about 0.3 

only. Hence, the Coen burner design 


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18 Docket # EPA–R05–OAR–2010–0037–0071. 19 Docket # EPA–R05–OAR–2010–0037–0071. 20 Docket # EPA–R05–OAR–2010–0037–0071. 

promotes a higher amount of premixing of O2

(oxidant) with fuel to reduce CO production. 

The flame temperature in both cases is high 

enough so the oxidation of CO is not 

kinetically limited. So the new burner design 

is not kinetically-limited for CO oxidation 

and the increased premixing in the primary 

zone will reduce CO emissions.18

Similarly, in a letter dated November 

6, 2009 from Hatch to U.S. Steel, Hatch 

stated: ‘‘Since USS Minntac plans to 

continue using their current fuels, fuel 

mixes, and fuel firing rates in 

conjunction with the low NOX burners, 

with the exception of NOX, Hatch does 

not anticipate any change in the 

emissions of applicable pollutants. 

Substantial reduction of NOX emissions 

is also anticipated.’’19

Finally, in a letter to U.S. Steel dated 

November 20, 2009, Owen Seltz, 

Engineer, Metallic Mining Section, 

Industrial Division, MPCA, stated: 

Generally, when a reduction in NOX

emissions from fuel combustion is proposed, 

the pollutant of concern for potential 

increase is carbon monoxide (CO). However, 

due to the design of the proposed low NOX

main burner, CO emissions are not 

anticipated to increase. Furthermore, as 

explained in the manufacturers’ letters dated 

November 3, 2009, and November 6, 2009 

and submitted to the MPCA in Minntac’s 

November 12, 2009 letter, due to the design 

and operation of the proposed burner, CO 

emissions are expected to decrease.20

Based on these assurances, EPA is 

confident that there will be no increases 

in other pollutants as a result of the 

installation of low NOX burner 

technology as Cliffs claims. 

I. Comments Concerning Sulfur Dioxide 

(SO2) BART Emission Limits 

Commenter: National Parks 

Conservation Association. 

Comment: NPCA commented that the 

proposed limits for six of the units (at 

Northshore, ArcelorMittal, and Hibbing) 

specifically do not apply when burning 

fuel oil. This loophole undermines the 

purpose of a BART analysis and 

contradicts the CAA requirement for 

BART to be met on a continuous basis. 

The final determination must include a 

limit that encompasses the burning of 

fuel oil at these facilities. 

Response: Northshore, ArcelorMittal, 

and Hibbing are straight-grate 

indurating furnaces and do not burn 

coal. The primary fuel at these facilities 

is natural gas. As a result, these facilities 

have inherently low SO2 emissions. 

Fuel oil is used only as a backup fuel. 

Due to its limited use, there was 

insufficient test data to set a 

corresponding SO2 emission limit for 

periods when fuel oil is being burned. 

EPA set the SO2 emission limits based 

on available data. For the straight-grate 

facilities, data was only available for 

periods in which the furnaces were 

combusting natural gas. In order to 

address this issue, EPA has added a 

regulatory requirement for affected 

sources to track their use of fuel oil and 

the resulting SO2 emissions. This 

information will be used as the basis for 

any restrictions that will need to be 

added, e.g. sulfur content, on the use of 

fuel oil. These requirements are 

contained in §§ 52.1183(k)(4) and 

52.1235(b)(2)(7). 

Commenter: Michigan Department of 

Environmental Quality (MDEQ). 

Comment: MDEQ commented that it 

had based its acceptance of Tilden’s 

BART submittal for SO2 on the lack of 

visibility impairment due to SO2

emissions. 

Response: In the final rule, EPA is no 

longer requiring add-on controls at the 

Tilden facility because Tilden has 

agreed to switch fuels to natural gas 

within one year of the effective date of 

this rule. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

should use the methods proposed by 

Minnesota to set emission limits, citing 

the limits the state set for the Hibbing 

Taconite and ArcelorMittal facilities. 

Cliffs contended that EPA’s proposed 

SO2 emission limits are unsupported 

and arbitrary. Cliffs objected to the 

limits set by EPA because they appear 

to be based on results from a single 

stack test, which represents a snapshot 

in time. Further, the limits ignore a 

significant amount of available data and 

bypass the statistical analysis conducted 

by MPCA. 

Response: In the Agency’s review of 

Minnesota’s regional haze SIP 

supplement, EPA concluded that the 

limits for taconite facilities proposed by 

Minnesota do not accurately represent 

the current level of controls at the 

facilities. For ArcelorMittal and Hibbing 

Taconite, Minnesota appears to have set 

the limit in pounds of SO2 per long ton 

(LT) of pellets produced based on a 30- 

day rolling average, using the Upper 

Predictive Limit (UPL) approach for 

normally distributed data. Minnesota 

did not demonstrate an accurate method 

to track or record LT of pellets 

produced. Therefore, the limits 

proposed by Minnesota are 

unenforceable. EPA also concluded that 

the annual testing requirement proposed 

by the state is insufficient to determine 

compliance with a limit based on a 30- 

day rolling average. In this action, EPA 

is finalizing SO2 limits for taconite 

facilities in terms of lbs SO2/hr based on 

a 30-day rolling average, which can be 

easily and accurately measured using 

the continuous emissions monitoring 

system (CEMS) required by this rule. 

EPA does agree that the UPL approach 

is an appropriate method for setting the 

SO2 limits. However, the available SO2

emissions data for the taconite sources 

generally do not follow a normal, 

logarithmic, or gamma distribution. For 

this reason, the UPL should be 

determined using a nonparametric 

method, as set forth below. EPA used 

available stack test and CEMS data from 

1990 to the present to recalculate the 

SO2 limits for ArcelorMittal and 

Hibbing, based on the appropriate UPL 

equation for nonparametric data, in 

terms of lbs SO2/hr on a 30-day rolling 

average as follows: 

UPL = xm and m = (n + 1)*(1 ¥ a) 

Where: 

xm = value of the mth data point, when the 

data is sorted smallest to largest 

m = the rank of the ordered data point, when 

data is sorted smallest to largest 

n = number of data points 

a = 95th percentile or 0.95 

If m is not a whole number, a linear 

interpolation is calculated from the 

following equation: 

Where: 

mi = the integer portion of m, i.e., m 

truncated at zero decimal places, and 

md = the decimal portion of m 

In this final rule, EPA is setting a limit 

of 38.16 lbs SO2/hr for indurating 

furnace EU026 at ArcelorMittal. This 

limit must be measured on a 30-day 

rolling average and does not apply when 

the subject unit is burning fuel oil. For 

Hibbing, EPA is finalizing an aggregate 

limit of 247.8 lbs SO2/hr based on a 

limit of 82.60 lbs SO2/hr for each of the 

three affected lines: EU020, EU021, and 


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21 Docket # EPA–R05–OAR–2010–0037–0034 (p. 

24). 

EU022. This limit is also measured on 

a 30-day rolling average and does not 

apply when the subject unit is burning 

fuel oil. 

Because of limited stack test data for 

Hibbing and ArcelorMittal, these 

sources may, within 20 months of the 

effective date of this rule, calculate a 

revised SO2 limit based on one year of 

hourly CEMS data, reported in lbs SO2/ 

hr, and submit such limit, calculations, 

and CEMS data to EPA. This limit shall 

be set in terms of lbs SO2/hr, based on 

the non-parametric UPL equations set 

forth above, with compliance to be 

determined on a 30-day rolling average. 

Commenter: Cliffs Natural Resources. 

Comment: Cliffs submitted alternate 

SO2 limits for Hibbing based on the UPL 

equation for normally distributed data. 

Response: While EPA agrees that the 

UPL approach is the appropriate 

method for setting the SO2 limits, EPA 

disagrees with the alternate SO2 limits 

submitted by the Cliffs for the Hibbing 

facility. Cliffs did not specify whether 

its suggested limit was daily, 

instantaneous, or on a 30-day rolling 

average. But in any case, the limit 

submitted by Cliffs for Hibbing appears 

to be calculated using the UPL equation 

for normally distributed data, a p-value 

of 0.01 (which would represent a 99.5 

percent confidence interval) and m = 1. 

This is incorrect. According to the UPL 

method, m represents the number of 

future runs (i.e., the number of future 

data points). As the data sets being used 

in the analyses are one-hour CEMS 

averages, the value of m should be 720 

(30 days times 24 hours) if the limit 

being set is a 30-day rolling average. 

Even if compliance is based on the 

average value of an annual performance 

test rather than a 30-day rolling average, 

Minnesota’s annual performance testing 

requires 30 hourly data points, which 

would result in a value of 30 for m. 

Cliffs also appears to have combined all 

stacks for each line and averaged all test 

runs for each set of test data to arrive at 

one data point for each set of test data, 

resulting in only 10 data points rather 

than 720 to calculate the UPL. 

In addition, although the raw test data 

provided SO2 emissions levels in terms 

of lbs SO2/hr, Cliffs calculated the UPL 

in terms of lbs SO2/LT pellets and then 

converted the SO2 limit back into lbs 

SO2/hr by using the maximum design 

capacity of each line rather than the 

actual production data collected during 

testing. 

Thus, EPA disagrees with this 

methodology. The alternate emission 

limit proposed by Cliffs is significantly 

higher than the limit that would result 

from the correct application of the UPL 

equation for normally distributed data. 

Further, some of the available data for 

the Hibbing facility are normally 

distributed, while other data are not. As 

noted previously, the available SO2

emissions data for the taconite industry 

in general do not follow a normal, 

logarithmic, or gamma distribution. For 

this reason, EPA is using the 

nonparametric UPL equation to 

calculate the SO2 emission limits. 

Commenter: Cliffs Natural Resources. 

Comment: Cliffs objected to the 

proposed 80 percent SO2 reduction 

requirement for Northshore, noting that 

an SO2 emission limit was also set for 

the facility. Cliffs contended that EPA 

failed to cite any justification for the 

requirement and failed to explain why 

an 80 percent reduction in SO2

emissions should be required for 

Northshore when a similar reduction 

was not required for any other facility. 

Cliffs asserted that Northshore’s SO2

emissions have a de minimis impact on 

visibility, so imposing multiple layers of 

control requirements would be arbitrary 

and unnecessary. 

Response: Northshore is subject to 

BART based on the visibility impacts 

that were described in the proposal rule. 

The document entitled ‘‘Northshore 

Mining Company Analysis of Best 

Available Retrofit Technology (BART)’’ 

submitted to MPCA on behalf of 

Northshore Mining states that 

‘‘WWESPs are currently in place on the 

furnace exhausts and are believed to 

remove 80 to 95 percent of the SO2 in 

the exhaust.’’ 21 Thus, 80 percent is on 

the low end of the removal efficiency 

range estimated by Northshore, not an 

arbitrary number selected by EPA. 

Further, in a CAA section 114 request to 

Cliffs and Northshore Mining, EPA 

requested copies of all stack tests 

conducted on any emissions unit for 

any reason, including all test runs, even 

if a full test series was not completed. 

In its response to EPA, Cliffs did not 

provide any SO2 test data for the 

subject-to-BART furnaces at Northshore. 

Without this emissions data, EPA 

believes using Northshore Mining’s 

prior estimate of 80 to 95 percent 

control efficiency on its furnace 

exhausts EPA to impose an 80 percent 

emissions reduction requirement on 

stacks SV101, SV102, SV103, SV104, 

SV105, SV111, SV112, SV113, SV114, 

and SV115 was appropriate. 

Subsequent to the public comment 

period, Cliffs provided EPA with 

limited SO2 emissions data for 

Northshore and proposed an aggregate 

limit of 39.0 lbs SO2/hr based on a limit 

of 19.5 lbs SO2/hr per line. Cliffs’ 

proposed limit is slightly higher than 

the limit EPA calculated using the new 

data and the UPL equation for 

nonparametric data. However, EPA 

believes it is reasonable to set an 

aggregate limit of 39.0 lbs SO2/hr, 

measured on a 30-day rolling average, 

and to require the source to recalculate 

this limit when CEMS data are 

available. 

As stated previously, this limit does 

not apply when the facility is burning 

fuel oil. In order to address this issue, 

EPA has added a regulatory requirement 

for affected sources to track their use of 

fuel oil and the resulting SO2 emissions. 

This information will be used as the 

basis for any restrictions that will need 

to be added, e.g. sulfur content, on the 

use of fuel oil. These requirements are 

contained in sections 52.1183(k)(4) and 

52.1235(b)(2)(7). 

In summary, this final rule establishes 

an aggregate SO2 emission limit of 39.0 

lbs SO2/hour, measured on a 30-day 

rolling average, for Furnace 11 and 

Furnace 12 at Northshore. Within 20 

months of the effective date of this rule, 

the owner or operator must calculate a 

revised SO2 limit based on one year of 

hourly CEMS emissions data reported in 

lbs SO2/hr and submit such limit, 

calculations, and data to EPA. This limit 

shall be set in terms of lbs SO2/hr, based 

on the non-parametric UPL equations 

previously set forth by EPA, with 

compliance to be determined on a 30- 

day rolling average. EPA agrees with the 

commenter that an 80 percent reduction 

requirement is no longer needed 

because it is redundant in light of the 

final lbs SO2/hr emission limit. 

Consequently, this final rule does not 

require an additional 80 percent 

emissions reduction requirement at 

Northshore. 

Commenter: National Park Service 

and Cliffs Natural Resources. 

Comment: NPS supported EPA’s 

proposal to require FGD as BART for 

SO2 at the United Taconite and Tilden 

facilities, agreeing with EPA’s costeffectiveness calculations. 

Cliffs, on the other hand, disagreed 

with EPA’s cost-effectiveness 

calculations for the United Taconite and 

Tilden facilities. Subsequent to the 

public comment period, Cliffs proposed 

switching fuels as an alternative to 

installing FGD scrubbers. Cliffs 

proposed a combined limit of 529 lbs 

SO2/hr for Lines 1 and 2 at the United 

Taconite facility, with compliance to be 

determined on a 30-day rolling average, 

beginning in 54 months. To meet this 

limit, the United Taconite furnaces will 

burn low-sulfur fuels, including 

increased use of natural gas. For Tilden, 

Cliffs proposed switching operation to 


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100 percent natural gas within 12 

months with an emissions limit to be set 

after a year of CEMS data become 

available. 

Response: Subsequent to the proposed 

rule, Cliffs has agreed to a federally 

enforceable aggregate emission limit of 

529 lbs SO2/hr, based on a 30-day 

rolling average, at United Taconite, 

based on the use of low-sulfur fuels. 

Cliffs has also agreed to convert to the 

use of 100 percent natural gas at Tilden. 

Because Tilden will now be restricted to 

the use of 100 percent natural gas, 

requiring the installation of SO2 controls 

is no longer economically feasible or 

necessary. Similarly, in light of the 

reduction in SO2 emissions that will 

result from the use of low-sulfur fuels at 

United Taconite, the cost effectiveness 

of additional controls has increased to 

$12,021 per ton for Line 1 and $7,680 

per ton for Line 2. Thus, EPA believes 

that the installation of such controls is 

no longer economically feasible. In 

addition to the emission limit proposed 

by Cliffs, to ensure the use of low-sulfur 

fuels and SO2 reductions resulting from 

the use of low-sulfur fuels at United 

Taconite, EPA is also requiring that the 

facility burn either natural gas or a 

blend of natural gas and coal. EPA is 

also establishing a limitation on the coal 

to be used by requiring the coal have a 

sulfur content no greater than 0.60 

percent sulfur by weight based on a 

monthly block average. The requirement 

for a sampling and calculation 

methodology for determining this value 

is contained within the monitoring plan 

as required in section 52.1235(e)(8)(x). 

In summary, EPA is no longer requiring 

FGD at United Taconite and Tilden as 

BART for SO2 in this final rule. 

Commenter: U.S. Steel. 

Comment: U.S. Steel proposed several 

alternate lbs SO2/hr limits for its 

Minntac facility. These limits were 

calculated by applying a 99 percent 

confidence interval utilizing three years 

of CEMS data. U.S. Steel also proposed 

alternate limits for producing flux 

versus acid pellets due to scrubber 

inefficiencies during acid pellet 

production. 

U.S. Steel proposed, as its first choice, 

an aggregate limit of 498 lbs SO2/hr, on 

a 30-day rolling average, when all five 

lines are producing flux pellets; an 

aggregate limit of 630 lbs SO2/hr, on a 

30-day rolling average, when Lines 3–5 

are producing acid pellets and Lines 6 

and 7 are producing flux pellets; and an 

aggregate limit of 800 lbs SO2/hr, on a 

30-day rolling average, when all five 

lines are producing acid pellets. U.S. 

steel also proposed partially aggregated 

limits and line-by-line limits for acid 

pellets and flux pellets. Finally, U.S. 

Steel proposed that the limit for acid 

pellets be in effect during acid 

production and for 30 days thereafter 

due to the 30-day rolling average. 

Response: EPA compared the limits 

proposed by U.S. Steel to the limit EPA 

calculated with the non-parametric UPL 

method and found them to be 

comparable. EPA also agrees with the 

need for a higher limit for acid pellet 

production. 

Therefore, in this final rule, the SO2

emission limits for U.S. Steel’s Minntac 

facility are 498 lbs SO2/hr on Lines 3– 

7 when all lines are producing flux 

pellets; 630 lbs SO2/hr when Lines 3–5 

are producing acid pellets and Lines 6 

and 7 are producing flux pellets; and 

800 lbs SO2/hr on Lines 3–7 when all 

lines are producing acid pellets. All 

limits are calculated on a 30-day rolling 

average. 

However, EPA does not agree that the 

limit for acid pellets should apply 

during acid production and for 30 days 

thereafter and thus has not made this 

change in the final rule. The emission 

limit for a given 30-day rolling average 

period will be calculated using a 

weighted average as follows: 

Where: 

L30 = the limit for a given 30-day averaging 

period 

nf = the number of days in the 30-day period 

that the facility is producing flux pellets 

on Lines 3–7 

naf = the number of days in the 30-day period 

that the facility is producing acid pellets 

on Lines 3–5 and flux pellets on Lines 

6 and 7 

na = the number of days in the 30-day period 

that the facility is producing acid pellets 

on Lines 3–7 

Commenter: U.S. Steel and Cliffs 

Natural Resources. 

Comment: Cliffs and U.S. Steel 

commented that it is inappropriate to 

use a seven percent oxygen correction 

for emission limits that are not 

concentration based. 

Response: EPA agrees with the 

commenters that the use of a seven 

percent oxygen correction is not 

necessary when the subject-to-BART 

facilities elect to comply with an 

emission limit measured in pounds of 

pollutant per million British thermal 

units or pounds of pollutant per hour. 

Commenter: U.S. Steel. 

Comment: U.S. Steel requested that 

the pH and SO2 removal efficiency 

limits for its Keetac facility be deleted 

because they are redundant with the lbs 

SO2/hr limit. 

Response: EPA agrees with U.S. Steel 

and has deleted the pH and SO2 removal 

efficiency limits from the final rule. 

Commenter: Leech Lake Band of 

Ojibwe. 

Comment: At United Taconite and 

Tilden, limiting SO2 to 5 parts per 

million by volume or requiring the 

facilities to meet a 95 percent reduction 

requirement, on a 30-day rolling 

average, using dry FGD is achievable 

and cost-effective. 

Commenter: Red Cliff Band of Lake 

Superior Chippewas. 

Comment: The Red Cliff Band 

supported EPA’s proposed requirement 

for additional SO2 controls in select 

facilities. 

Commenter: National Tribal Air 

Association. 

Comment: The Association agreed 

with using existing SO2 controls for 

those taconite facilities where it would 

be cost prohibitive to convert to a 

different technology that would only 

achieve nominal SO2 reductions. 

However, in the case of the United 

Taconite and Tilden facilities, the 

Association found it relatively 

inexpensive to use dry FGD to limit SO2

to 5 parts per million by volume or to 

meet a 95 percent reduction 

requirement on a 30-day rolling average. 

Commenter: National Park Service. 

Comment: NPS supported EPA’s 

proposal to require FGD as BART for 

SO2 at the United Taconite and Tilden 

facilities, agreeing with EPA’s cost 

effectiveness calculations and 

compliance schedule. 

Response: EPA agrees with the 

commenters that under current 

operating conditions, FGD is a costeffective control option for the grate-kiln 

furnaces at United Taconite and Tilden 

and represents BART. However, 

subsequent to the public comment 

period, Cliffs proposed switching fuels 

as an alternative to installing FGD 

scrubbers. Cliffs has since agreed to 

federally enforceable limits on the types 

of fuels that may be burned at these 

facilities. In this final rule, the United 

Taconite furnaces must burn a 

combination of natural gas and lowsulfur coal and Tilden will now burn 

100 percent natural gas. Given these 

changes, EPA has determined that 

requiring the installation of SO2 controls 

is no longer economically feasible or 

necessary. 

J. Comments Concerning the Visibility 

Analysis and Visibility Impacts 

Commenter: Fond du Lac Band of 

Lake Superior Chippewa. 

Comment: Tables V–C.l0 to V–C.l5 of 

the FIP demonstrate the changes in 

visibility that could be expected from 

the use of low NOX burners. While these 

are only predictions, the expected 

improvements in visibility in the 


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Boundary Waters Canoe and Wilderness 

Area, Voyageurs National Park, and Isle 

Royale National Park strongly support 

the use of this technology at the subjectto-BART taconite plants. 

Response: EPA agrees that the BART 

emission limits have the potential to 

result in significant improvement in 

visibility at the affected Class I areas. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

did not conduct a proper analysis of 

visibility impacts. 

Response: EPA disagrees. EPA’s 

visibility estimates provide ample 

evidence that the visibility impacts of 

each subject-to-BART taconite facility 

are substantial enough to warrant the 

selected BART controls. EPA’s 

responses to the individual criticisms 

raised by the commenters on our 

visibility analysis are discussed in 

further detail below. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that the 

proposed rule directly contravened the 

instructions given to EPA in American 

Corn Growers v. EPA. In particular, 

Cliffs asserted that EPA’s method is a 

‘‘bifurcated’’ approach to visibility that 

was rejected in that decision. In Cliffs’ 

view, the American Corn Growers court 

rejected a bifurcated approach in which 

visibility impacts are treated differently 

than the other four BART factors. Cliffs 

noted that for each taconite source, EPA 

separated its analysis into two distinct 

sections. Section V.B. of the proposed 

rule analyzed the first four factors, 

while EPA separately analyzed visibility 

improvement in Section V.C. for 

whichever technology emerged from the 

four-factor analysis in Section V.B. 

Thus, in Cliffs’ view, the real-world 

visibility impacts were, at most, a 

secondary consideration that could not 

have influenced the evaluation of BART 

alternatives. 

Response: EPA disagrees. The 

‘‘bifurcation’’ referred to in the 

American Corn Growers decision related 

to EPA’s use of a regional, multi-source, 

group approach to determining the 

degree of visibility improvement, while 

analyzing the other four statutory factors 

on a source-specific basis. The 

American Corn Growers court held that 

the visibility analysis must not be 

treated differently and must be a sourcespecific analysis. Since that decision, 

EPA and states have consistently 

conducted the visibility prong of the 

five-factor analysis on a source-specific 

basis. In this instance, although EPA 

presented its visibility analysis in a 

separate section of the proposed rule, 

the Agency conducted the analysis on a 

source-specific basis consistent with the 

holding in American Corn Growers. 

EPA also disagrees that visibility was 

a secondary consideration in its 

analysis. EPA’s analysis shows that 

based on the all of the BART factors, 

including visibility, the selected 

controls are warranted. If highly 

reasonable and cost-effective controls 

had been available but visibility benefits 

were slight, EPA would have rejected 

those controls. Section V.B. of the 

proposed rule demonstrated that 

reasonable and cost-effective controls 

were available. Section V.C. then 

showed that the visibility benefits to be 

obtained by requiring controls at each 

source were significant. Site-specific 

visibility improvement estimates for 

each source, derived from regional 

modeling conducted by the state of 

Minnesota on a variety of sources in the 

area, demonstrated that the significant 

reductions EPA proposed will produce 

significant visibility improvement in 

affected Class I areas. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that the 

approach EPA used in the proposed rule 

to estimate visibility impacts was 

arbitrary because it was not site-specific. 

Rather than extrapolating results from 

other facilities, EPA should have 

conducted modeling for the specific 

sources being regulated. The BART 

Guidelines instruct EPA to conduct 

modeling using CALPUFF or other 

appropriate dispersion models for each 

source and highlight the importance of 

source-specific features, such as stack 

flow rate and release height. EPA’s use 

of ‘‘visibility impact ratios’’ derived 

from other sources is not consistent 

with EPA’s own guidelines and 

provides results that are too unreliable 

for the purpose of a BART visibility 

analysis. In using the visibility impact 

ratio approach, EPA is holding itself to 

a lower standard than it would expect 

from a state air quality agency 

conducting a similar BART review. 

Response: EPA’s proposed rule 

acknowledged that there is greater 

uncertainty associated with the 

visibility impact ratio approach. 

Nonetheless, EPA finds this approach to 

be consistent the BART Guidelines 

allowance for ‘‘appropriate’’ models and 

believes the approach provides adequate 

indication of the visibility benefits of 

the evaluated controls. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that 

EPA’s visibility analysis was 

inconsistent with the statutory 

obligation to consider the degree of 

visibility improvement that is 

‘‘reasonably anticipated.’’ In Cliffs’ 

view, the use of ‘‘possible’’ impacts 

from an approach extrapolated from 

other facilities does not satisfy this 

statutory requirement to consider 

‘‘reasonably anticipated’’ visibility 

impacts. In support of this view, Cliffs 

noted that EPA extrapolated visibility 

results from facilities other than taconite 

plants, such as an electric generating 

unit. Moreover, Cliffs found EPA’s use 

of sources in the ‘‘general area’’ as 

unacceptable for the visibility analysis 

given that wind conditions would affect 

the taconite facilities differently than 

the facilities EPA relied upon. 

Additionally, the commenter noted 

differences in stack conditions between 

the taconite facilities being regulated 

and the sources that EPA relied upon. 

Response: EPA’s proposed rule 

acknowledged the uncertainty 

associated with the visibility impact 

ratio approach, but noted that despite 

the uncertainties, the Agency was 

confident that the information was 

adequate to assess potential visibility 

improvements due to emissions 

reductions at the specific facilities. 

While the results obtained from this 

approach are not expected to be as 

precise as source-specific CALPUFF 

modeling, they are based on visibility 

improvements derived from existing 

regional scale modeling that was 

conducted on sources in and around the 

northern Minnesota area. Given the 

geographic proximity of the taconite 

facilities to those that were modeled, 

EPA believes that the ratio approach 

provided adequate assurance of the 

visibility improvements that can be 

expected from the proposed emission 

reductions. 

The results EPA obtained from its 

analysis are presented in terms of 

deciview (DV) change and change in the 

number of days above the 0.5 DV 

threshold. In the proposed rule’s 

summary of the impacts at Boundary 

Waters, Voyageurs, and Isle Royale, 

these values ranged from 1.3 to 7.1 DVs 

of improvement with between 17 and 93 

fewer days above the 0.5 DV threshold. 

Therefore, even if the ratio approach 

was over-estimating visibility 

improvements by a factor of two or 

three, the expected benefits would still 

be significant. 

For example, Cliffs submitted 

CALPUFF modeling that showed the 

visibility improvements expected from 

the proposed rule for two of the seven 

facilities—United Taconite and Tilden. 

This modeling was only performed at 

the most impacted of the four affected 

Class I areas. EPA also notes that these 

were the only facilities for which new 


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22This 50 percent discrepancy applies to United 

Taconite. 

23EPA notes that the control emissions for SO2

at United Taconite differ between those modeled 

and those that will be achieved based on the final 

rule because EPA is no longer requiring FGD as a 

result of the switch to low-sulfur fuels at the 

facility. This change will result in higher controlled 

emissions and would be expected to lower the 

visibility improvements demonstrated in the model 

slightly. 

scrubbers were proposed as BART for 

SO2. 

The results of the Cliffs’ modeling for 

United Taconite and Tilden are 

presented below. The first delta DV 

value is the subtraction of the two 98th 

percentile impacts (base minus FIP). 

TABLE 2—UNITED TACONITE PREDICTED VISIBILITY RESULTS FOR THE MOST IMPACTED AREAS

Scenario/year 

Boundary 

Waters days 

over 0.5 DV 

Boundary 

waters 98th 

percentile 

delta DV 

Voyageurs 

days over 0.5 

DV 

Voyageurs 

98th percentile 

delta DV 

Difference/2002 ................................................................................................ 36 0.594 17 0.454 

Difference/2003 ................................................................................................ 39 0.579 14 0.649 

Difference/2004 ................................................................................................ 33 0.545 17 0.439 

TABLE 3—TILDEN PREDICTED VISIBILITY RESULTS FOR THE MOST IMPACTED AREAS

Scenario/year Isle Days over 

0.5 DV 

Isle 98th percentile 

delta DV 

Seney days 

over 0.5 DV 

Seney 98th 

percentile 

delta DV 

Difference/2002 ................................................................................................ 2 0.099 3 0.146 

Difference/2003 ................................................................................................ 8 0.160 3 0.099 

Difference/2004 ................................................................................................ 2 0.112 2 0.125 

The baseline emissions associated 

with the runs above totaled 

approximately 3,344 tons per year of 

SO2 and 3,129 tons per year of NOX for 

United Taconite, and approximately 

1,563 tons per year of SO2 and 2928 tons 

per year of NOX for Tilden. The postcontrol emissions totaled approximately 

233 tons per year of SO2 and 2,435 tons 

per year of NOX for United Taconite, 

and approximately 174 tons per year of 

SO2 and 2,414 tons per year of NOX for 

Tilden. The United Taconite emissions 

were based on CEMS data collected 

under a 100-percent coal-firing scenario, 

while Tilden emissions were based on 

stack test information collected under a 

primarily coal-firing scenario. 

EPA believes that Cliffs’ modeled 

baseline emission rates are low based on 

previous BART modeling and figures 

from the proposed rule. Expected postcontrol emissions reductions also 

appear to be underestimated. The 

proposed rule identified baseline 

emissions of approximately 5,330 tons 

per year for NOX and 4,043 tons per year 

for SO2 for United Taconite, and 

approximately 1,153 tons per year of 

SO2 and 4,613 tons per year of NOX for 

Tilden. The BART Guidelines 

recommend that sources use the highest 

24-hour average actual emission rate, for 

the most recent three or five year period 

of meteorological data, to characterize 

the maximum potential benefit. By 

using a low baseline emission rate, 

Cliffs’ modeling underestimates the 

emissions reductions that will be 

achieved by the installation of BART 

controls and the resulting visibility 

improvements. However, even though 

the overall SO2 and NOX reductions 

modeled by Cliffs were over 50 percent 

lower than the reductions projected in 

the proposed rule,22 the results still 

showed significant visibility 

improvement at the Boundary Waters. 

Consequently, EPA believes that Cliffs’ 

modeling provides further evidence that 

the visibility improvements predicted 

by the ratio approach are reasonable. 

Using the CALPUFF model input and 

meteorological data files submitted by 

Cliffs, EPA, with substantial assistance 

from the National Park Service, re-ran 

the baseline and control-case scenarios 

for United Taconite and Tilden with 

data from the proposed rule. For United 

Taconite, the baseline emissions of SO2

and NOX reflect the emissions presented 

in the proposed rule. The United 

Taconite control emissions for NOX

were based on a 1.2 lbs NOX/MMBtu 

emission limit and heat inputs of 200 

MMBtu/hr for line 1 and 260 MMBtu/ 

hr for line 2. The United Taconite 

control emissions for SO2 were based on 

an approximate 94-percent reduction 

from the base case.23 For Tilden, the 

baseline emissions for both visibility 

pollutants were also based on those 

contained in the proposed rule. The 

Tilden control emissions for NOX were 

based on a conversion to 100 percent 

natural gas, with an 80 percent 

reduction from the baseline for SO2 and 

a 65 percent reduction for NOX. The 

results of this modeling are shown 

below, but only for the most impacted 

Class I area. 

TABLE 4—EPA MODELING—UNITED

TACONITE PREDICTED VISIBILITY RESULTS FOR THE MOST IMPACTED

AREA

Scenario/year 

Boundary 

Waters days 

over 0.5 DV 

Boundary 

Waters 98th 

percentile 

delta DV 

Difference/2002 80 1.316 

Difference/2003 71 1.223 

Difference/2004 62 1.358 

TABLE 5—EPA MODELING—TILDEN

PREDICTED VISIBILITY RESULTS FOR

THE MOST IMPACTED AREA

Scenario/year Seney days 

over 0.5 DV 

Seney 98th 

percentile 

delta DV 

Difference/2002 0 0.320 

Difference/2003 0 0.206 

Difference/2004 1 0.165 

Again, EPA’s CALPUFF modeling 

shows significant visibility 

improvement can be expected due to the 

installation of BART controls at United 

Taconite and Tilden. EPA believes that 

these results lend additional support to 

the accuracy of the visibility analysis 

that was performed for all facilities in 

the proposed rule. EPA stands by the 

results of its ratio approach and believes 

that it produced reasonable results for 

the sources examined. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 


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8722 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

24 Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Rule, U.S. 

Environmental Protection Agency (September 

2003), available at http://www.epa.gov/ttncaaa1/t1/ 

memoranda/rh_envcurhr_gd.pdf. ‘‘Natural visibility 

conditions represent the long-term degree of 

visibility that is estimated to exist in a given 

mandatory Federal Class I area in the absence of 

human-caused impairment. It is recognized that 

natural visibility conditions are not constant, but 

rather they vary with changing natural processes 

(e.g., windblown dust, fire, volcanic activity, 

biogenic emissions). Specific natural events can 

lead to high short-term concentrations of particulate 

matter and its precursors. However, for the purpose 

of this guidance and implementation of the regional 

haze program, natural visibility conditions 

represents a long-term average condition analogous 

to the 5-year average best- and worst-day conditions 

that are tracked under the regional haze program.’’ 

Guidance at 1–1. 

Comment: Cliffs commented that the 

proposed rule failed to properly 

integrate the visibility analysis with cost 

considerations and that EPA should 

have identified the costs of controls 

relative to the visibility improvement 

using a $/DV metric. In support of this 

view, Cliffs provided data showing that 

the costs per DV improvement are very 

high at two of its facilities: $65 million 

per DV at United Taconite and $140 

million per DV at Tilden. Finally, Cliffs 

noted that FLMs have cited a threshold 

of $20 million per DV in 

correspondence with states, and that 

any figure beyond this threshold 

constitutes excessively high costs for the 

degree of visibility improvement 

achieved. 

Response: EPA disagrees that a cost 

per DV analysis was required. The 

BART Guidelines do not require EPA or 

the states to conduct such an analysis 

when evaluating the visibility 

improvement factor. While the BART 

Guidelines suggest cost per DV as a 

possible parameter for consideration, its 

use is entirely discretionary. There are 

numerous examples of BART analyses 

conducted by states and EPA that have 

not calculated this metric. 

Moreover, EPA believes that Cliffs’ 

comment underestimates the visibility 

impacts from the two facilities that were 

modeled, leading to erroneous cost per 

DV figures. As was explained in detail 

in the response to the previous 

comment, Cliffs substantially 

underestimated the baseline emission 

rates at United Taconite and Tilden, 

which in turn resulted in emissions 

reduction estimates that are also too 

low. The BART Guidelines recommend 

that the highest 24-hour average actual 

emission rate, for the most recent three 

or five-year period of meteorological 

data, be used to calculate the maximum 

potential benefit. Overall, the emissions 

reductions predicted by Cliffs’ modeling 

analysis were less than 50 percent of the 

emissions reductions projected by EPA 

for United Taconite. 

Finally, Cliffs’ reference to the $20 

million per DV threshold is misleading. 

The FLMs recommend that cost per DV 

be calculated cumulatively to include 

improvements at all affected Class I 

areas. Cliffs’ analysis, on the other hand, 

only included visibility improvement at 

a single Class I area, thereby inflating its 

total cost per DV figures. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that 

NOX-related visibility improvements 

should be discounted because nitrate 

visibility impacts peak in the winter and 

winter-time visitation at the affected 

Class I areas is significantly less than 

during other times of the year. Cliffs 

noted that the BART Guidelines allow 

for consideration as to whether impacts 

occur ‘‘during the tourist season.’’ 

Response: EPA agrees that nitrate 

impacts are more dominant in the 

winter. Nonetheless, daily nitrate 

impacts from April through October are 

not trivial. EPA also agrees that the 

BART Guidelines allow states to 

consider the timing of impacts in 

addition to other factors related to 

visibility impairment. However, states 

are not required to do so, and to our 

knowledge, neither Michigan nor 

Minnesota did so in their visibility 

analyses. EPA is not required to 

substitute a source’s desired exercise of 

discretion for that of the states. 

Furthermore, when promulgating a FIP, 

EPA stands in the shoes of the state. In 

that capacity, EPA is not required to 

consider the seasonality of impacts and 

has chosen not to do so here. Taking 

into account visitation contradicts the 

goal of the regional haze rule of 

improving visibility on the 20 percent 

best and worst days. Indeed, EPA 

believes that the experiences of visitors 

who come to Class I areas during 

periods other than the peak visitation 

season are important and should not be 

discounted. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs cited a number of 

other flaws in EPA’s overall approach to 

visibility that it believed led to 

unreliable or overstated impacts from 

the taconite facilities. First, Cliffs 

asserted that EPA used natural visibility 

conditions that were ‘‘too clear, 

excluding conditions such as fires, 

which had the effect of overstating the 

impacts of the facilities modeled 

relative to natural conditions. Second, 

Cliffs asserted that the chemistry in the 

current EPA-approved version of 

CALPUFF, as well as regional 

photochemical models such as CAMx, 

overestimates the impact of NOX

emissions on visibility impairment. 

Cliffs argued that this is especially true 

for winter nitrate haze due to the 

models’ static predictions of ammonia 

background concentrations that should 

vary seasonally to be in line with 

monitored observations. As a result, 

Cliffs concluded that the NOX emission 

reductions that will accompany the 

installation of BART are being 

improperly credited with visibility 

improvements that will not occur in the 

Minnesota and Michigan Class I areas. 

Finally, Cliffs cited real-world monitor 

studies as evidence that large sources 

that curtailed or shut down operations 

had little effect on visibility monitors. 

The first of these studies evaluated the 

changes in visibility monitoring at the 

Boundary Waters during periods of low 

operation at the taconite facilities 

during 2009. The second study 

evaluated changes in visibility 

monitoring at the Grand Canyon after 

shutdown of the Mohave Power Plant. 

Response: EPA disagrees with these 

purported flaws in our approach, many 

of which have been raised in the context 

of other states’ BART determinations. 

Regarding the issue of natural 

background conditions, similar issues 

were addressed in EPA’s action on the 

North Dakota regional haze SIP (77 FR 

20909, April 6, 2012). EPA recognizes 

that variability in natural sources of 

visibility impairment cause variability 

in natural haze levels as described in 

the Agency’s ‘‘Guidance for Estimating 

Natural Visibility Conditions under the 

Regional Haze Rule.’’ 24 Progress toward 

natural visibility in Class I areas 

includes improvement toward natural 

conditions for the 20 percent worst days 

and no degradation of visibility on the 

20 percent best days. The use of the 20 

percent worst days in the calculation of 

the uniform rate of progress takes into 

consideration visibility impairment 

from wild fires, windblown dust, and 

other natural sources of haze. For the 

evaluation of visibility impacts for 

BART sources, however, EPA 

recommends using the natural visibility 

baseline for the 20 percent best days for 

comparison to the ‘‘cause or contribute’’ 

applicability thresholds. This estimated 

baseline is reasonably conservative and 

consistent with the goal of attaining 

natural visibility conditions. While EPA 

recognizes that there are natural sources 

of haze, the use of the 20 percent worst 

days is inappropriate for the ‘‘cause or 

contribute’’ applicability thresholds. For 

example, if visibility impacts were 

evaluated in comparison to days with 

very poor natural visibility resulting 

from nearby wild fires or dust storms, 

the impacts of BART sources would be 

significantly reduced relative to these 


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Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 8723 

25As part of the settlement of a case brought by 

the Utility Air Regulatory Group challenging the 

BART Guidelines, EPA agreed to issue guidance 

clarifying that states may use either the 20 percent 

best days or the annual average in estimating 

natural visibility in the evaluation of a BART 

source’s impacts. This guidance makes clear that 

states have the flexibility to use either approach in 

estimating natural background conditions. Here, the 

states were not required to use the annual average 

and did not. Similarly, in issuing a FIP, EPA is not 

required to use the annual average either and chose 

not to in this case. 

26National Atmospheric Deposition Program, 

http://nadp.sws.uiuc.edu/AMoN/sites/data/. 

27Source: Minnesota Department of Revenue, 

Minerals Tax Division, Eveleth, MN. 

28There, EPA stated: ‘‘In addition, the study by 

Terhorst and Berkman does not convince us that 

use of CALPUFF modeling is inappropriate for this 

action or that the CALPUFF modeling results 

should be ignored. A model such as CALPUFF 

essentially holds constant a number of factors in 

order to isolate the impacts of a single source. As 

acknowledged by the study’s authors, it is 

extremely difficult in observational analyses to 

sufficiently control for all factors, including 

emissions from other sources, to be able to isolate 

the impacts of closure of a facility, especially one 

located over 100 km from the Class I area at issue. 

In fact, the paper notes that coarse soil mass 

impacts are an omitted variable in the analytical 

analysis and that changes in those emissions may 

have counteracted the visibility improvements 

expected from the source shutdown’’ (77 FR 20894, 

20910). 

poor natural visibility conditions and 

would not be protective of natural 

visibility on the 20 percent best days.25

In regards to Cliffs’ comment on 

atmospheric chemistry, the approach 

used by EPA in the proposed rule relied 

on regional-scale modeling conducted 

by MPCA where ammonia values varied 

temporally and spatially. This is in 

contrast to the approach used in the 

CALPUFF modeling submitted by Cliffs 

where a constant 1 ppb monthly average 

ammonia value was used. While 

ammonia data is not available for the 

vicinity of the sources of interest, data 

is available for sites located in the Class 

I areas (Fernberg, MN) as well as for 

sites to the south more representative of 

northern Wisconsin and southern 

Minnesota.26 The available Fernberg 

ammonia data includes several years of 

information and has an overall twoweek average value of about 0.5 ppb 

with several two-week periods over 1 

ppb. The Perkinstown site located in 

northern Wisconsin is in an area 

combining forest, grassland, and 

agricultural uses and has an overall twoweek average ammonia concentration of 

about 1.5 ppb with several two-week 

periods over 1.5 ppb. Consequently, the 

value of 1 ppb used in the modeling 

submitted by Cliffs is most likely 

representative of the ammonia 

concentration in the vicinity of the 

sources of interest. However, EPA again 

reiterates that Cliffs’ largely baseless 

criticism of CALPUFF does not apply to 

the Agency’s ratio approach, which 

relied on regional-scale modeling 

conducted by the states that included 

temporal and spatial variations in 

ammonia concentrations. 

Finally, regarding Cliffs’ comment 

concerning the two monitoring studies, 

EPA does not find either of the studies 

to be persuasive with respect to the 

impacts of taconite sources on visibility. 

The first study asserts that the 2009 

decline in taconite production and a 

negligible change in visibility are 

evidence that further controls are not 

warranted. EPA believes that that it is 

very difficult to discern any effect from 

a one-year study and points out that the 

production decline (as shown in Table 

6 below) occurred during the spring and 

summer, seasons for which Cliffs 

recognized that nitrate formation is less 

important. 

TABLE 6—MINNESOTA 2009 PELLET

PRODUCTION BY MONTH

[Tons] 27

Month 

Pellet 

production 

(tons) 

January ................................. 2,205,578 

February ............................... 1,900,003 

March .................................... 1,620,343 

April ....................................... 958,479 

May ....................................... 181,739 

June ...................................... 340,707 

July ....................................... 849,363 

August ................................... 1,158,447 

September ............................ 1,723,336 

October ................................. 2,008,864 

November ............................. 2,038,844 

December ............................. 2,093,403 

The second study Cliffs cited, which 

reviewed visibility monitoring before 

and after the shutdown of the Mohave 

Power Plant in Nevada, is a paper by 

Terhorst and Berkman (Atmospheric 

Environment, 2010). This paper was 

subsequently examined and commented 

on in a paper by White et al. 

(Atmospheric Environment, January 

2012). There, White et al. state: 

‘‘[Terhorst and Berkman]’s technical 

analysis is thoughtfully conceived and 

executed, but is misleadingly presented 

as discrediting previous studies and 

their interpretation by regulators. In 

reality the Terhorste Berkman analysis 

validates a consensus on MPP’s 

(Mohave Power Project) visibility 

impact that was established years before 

its closure, in a collaborative assessment 

undertaken jointly by Federal regulators 

and MPP’s owners.’’ Additionally, EPA 

has responded to similar comments 

regarding the Mohave Power Project 

study and EPA’s visibility modeling in 

our action on the North Dakota regional 

haze SIP (77 FR 20894, April 6, 2012).28

Finally, EPA believes that Cliffs, 

while identifying purported areas where 

EPA’s models exaggerate visibility 

impacts, overlooks that there are aspects 

of the models that have been suggested 

by commenters on our regional haze 

actions as under-predicting impacts. 

Some examples include use of 24-hour 

average emissions impacts. Some 

examples include use of 24-hour 

average emissions rather than hourly 

emissions, use of monthly average 

relative humidity rather than daily 

humidity, and use of 98th percentile 

results to compare to the threshold 

instead of the highest day. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that 

certain control options should be 

rejected because visibility modeling 

does not indicate the installation of 

controls will result in a perceptible 

visibility improvement. 

Response: EPA’s disagrees. As 

explained in the proposed rule, EPA 

believes that the application of BART 

will result in perceptible improvements 

in visibility. Nonetheless, the 

perceptibility of visibility improvement 

is not a prerequisite to the selection of 

a control option as BART. The preamble 

to the BART Guidelines state, ‘‘Even 

though the visibility improvement from 

an individual source may not be 

perceptible, it should still be considered 

in setting BART because the 

contribution to haze may be significant 

relative to other source contributions in 

the Class I area. Thus, we disagree that 

the degree of improvement should be 

contingent upon perceptibility’’ (70 FR 

39104, 39129, July 6, 2005). 

Minnesota’s regional haze SIP 

described the importance of the 

contribution of sources in northeastern 

Minnesota to visibility impairment in 

the Boundary Waters and Voyageurs 

national parks. Accordingly, Minnesota 

developed a special plan for the 

northeast region of the state. Minnesota 

explained: 

This area was targeted for controls under 

the long-term strategy for several reasons. 

First, the MPCA’s analysis of 2002 emissions 

from the top 18 emitting point sources within 

Minnesota show that sources from this region 

make up just 1⁄3 of the total emissions but 

provide 2⁄3 of the total visibility impact. (See 

Chapter 8, on modeling.) Therefore, they 

have a much larger impact on the Class I 

areas than emissions from farther away. In 

addition, the taconite facilities may be 

currently uncontrolled or under-controlled 

for SO2 or NOX, and on the books control 

strategies are projected to cause fewer 


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8724 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

29Minnesota’s 2009 regional haze SIP submittal at 

96 (Docket # EPA–R05–OAR–2010–0037–0002). 

emission decreases in this region than in the 

remainder of the state.29

Thus, Minnesota’s assessment supports 

the determination that taconite facilities 

contribute to regional haze even if 

individual impacts are modeled below 

thresholds for human perceptibility. 

K. Comments Concerning Requirements 

for Continuous Emissions Monitoring 

1. Comments in Support of Continuous 

Emissions Monitoring Requirements 

Commenter: National Parks 

Conservation Association. 

Comment: EPA’s proposed rule 

includes the use of CEMS as a part of 

the monitoring, recordkeeping, and 

reporting necessary to ensure the 

continuous application of BART. Such 

monitors provide more accurate data 

about the emissions from taconite 

facilities than previous methods. As 

such, they are essential for tracking 

emissions and determining their impact 

on the surrounding communities. 

Moreover, CEMS can be used as 

pollution control tools by helping to 

fine-tune combustion and process 

controls in a way that periodic stack 

tests and predictive monitoring cannot. 

As such, we fully support the required 

application of CEMS on these sources. 

Commenter: National Park Service. 

Comment: NPS is especially pleased 

that EPA has proposed testing and 

CEMS requirements for the subject 

taconite plants. Our discussions with 

U.S. Steel, which has led the way in 

installation and operation of CEMS on 

indurating furnaces, have led to the 

mutual agreement that CEMS data is 

essential for the proper tuning and 

operation of combustion controls to 

reduce NOX emissions. Minnesota’s 

regional haze SIP discussed the need for 

requiring CEMS for the taconite 

industry to monitor NOX for a number 

of reasons. These included setting BART 

limits, allowing facilities to efficiently 

manage combustion, resulting in less 

fuel use and fewer emissions, and 

tracking progress under the Northeast 

Minnesota Plan. CEMS data is also 

essential for assessing the effectiveness 

of SO2 controls and should provide an 

indication of changes in fuel use or 

sulfur content for use in future regional 

haze planning. 

Commenter: Leech Lake Band of 

Ojibwe. 

Comment: The Band agreed with the 

implementation of CEMS. CEMS will 

provide the facility and regulators with 

real time data to ensure that the controls 

in place are operating at optimum 

levels, thus saving money for the facility 

and achieving the required control 

requirements. 

Commenter: National Tribal Air 

Association. 

Comment: The Association found 

requiring CEMS to be a good 

complement to the NOX and SO2

controls at taconite ore processing 

facilities. CEMS will provide these 

facilities with an accurate and timely 

emissions count of NOX and SO2 and 

will immediately alert owners to any 

deviations from such emissions that 

might require correction. 

Response: EPA acknowledges the 

comments in support of the proposed 

CEMS requirements. EPA is finalizing 

the CEMS requirements as proposed. 

2. Comments Questioning EPA’s 

Continuous Emissions Monitoring 

Requirements 

Commenter: U.S. Forest Service. 

Comment: In the Minnesota regional 

haze SIP, a statement is made that 

CEMS ‘‘would apply to NOX emissions 

at the facilities burning natural gas and 

to SO2 emissions at facilities burning 

high sulfur fuels.’’ We do not 

understand why the NOX CEMs are only 

being required at natural gas-fired 

furnaces. Those furnaces burning fuels 

other than natural gas will also 

investigate NOX control strategies and 

therefore will need the CEMs. 

Response: EPA is requiring CEMS for 

all seven subject-to-BART taconite 

facilities. Each taconite facility must 

monitor its NOX and SO2 emissions 

with CEMS. 

Commenter: U. S. Steel and Cliffs 

Natural Resources. 

Comment: Cliffs and U.S. Steel stated 

that it is inappropriate to require the use 

of a diluent monitor as part of the 

monitoring requirements under the 

proposed rule. 

Response: The need to install a 

diluent monitor is source-specific and 

depends on a variety of factors, 

including the choice of monitors 

installed. While some subject-to-BART 

facilities may not need to install a 

diluent monitor, other facilities may 

because of their stack characteristics, 

operating conditions, and monitors 

chosen. Because the final rule covers a 

variety of facilities, EPA feels it is 

appropriate to require a diluent monitor 

only for those facilities needing such a 

unit. Therefore, the final rule has been 

revised to provide the facilities with an 

option to demonstrate in their 

monitoring plans whether a diluent 

monitor is needed or not. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that EPA 

failed to adequately support its CEMS 

requirements and that EPA should allow 

flexibility in the monitoring 

requirements. More specifically, EPA 

should require ‘‘a comparable method of 

emission estimation,’’ such as 

parametric emissions monitors, for each 

subject-to-BART source. Cliffs stated 

that EPA’s unsupported generalized 

statements do not provide adequate 

justification for the Agency’s 

burdensome monitoring determination. 

Response: EPA clearly states in its 

technical support for the proposed rule 

that CEMS are the best method for 

demonstrating compliance because of 

the variability in furnace operations and 

variable fuel usage across the furnaces. 

The variable fuel feeds and feed 

material content can impact overall 

emissions from the process and thereby 

create the need for continuous 

monitoring of emissions that impact 

visibility. Parametric emissions monitor 

systems are an option for processes that 

operate at stable, non-variable 

conditions, but are not appropriate for 

taconite units. CEMS provide a 

continuous record of data that can also 

be used by the facility owner or operator 

to monitor emissions on a real-time 

basis. The installation and operation of 

CEMS and the real-time evaluation of 

the CEMS data provide several benefits 

to a facility that can directly lead to 

practices that reduce emissions during 

all periods of operation. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that 

CEMS do not constitute proven 

monitoring technology with respect to 

taconite furnaces. 

Response: EPA disagrees. CEMS 

technology for NOX and SO2 is proven 

in multiple industries, including the 

taconite industry. U.S. Steel is 

successfully using CEMS at its Minntac 

and Keetac facilities currently, and any 

problems experienced with the initial 

installation of CEMS have been 

resolved. EPA expects facilities will 

need some time to learn CEMS 

operation and how it impacts process 

operations. EPA has incorporated 

additional time into the final rule before 

certification is required to allow each 

facility to learn how CEMS operates. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs asserted that the 

requirement to install CEMS should be 

limited to waste stacks. Cliffs proposed 

to use stack testing data to determine 

the percent distribution of NOX between 

the hood-exhaust header and the wastegas header to determine compliance. 

Cliffs also stated that the use of a single 


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Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 8725 

CEMS per furnace is consistent with 

Minntac, which currently utilizes NOX

and SO2 CEMS only. 

Response: EPA disagrees with Cliffs 

that the use of CEMS should be limited 

to waste stacks only. Available 

information shows that emissions from 

hood-exhaust stacks can equal about 29 

percent of total furnace emissions. 

Given that nearly one-third of the 

furnace emissions are from hood 

exhausts (and can vary), EPA believes 

that it is appropriate to require CEMS on 

both waste stacks and hood-exhaust 

stacks. 

Cliffs incorrectly assumed that CEMS 

are required at each stack venting to the 

atmosphere. EPA feels it is important to 

obtain continuous and representative 

measurements of emissions from 

subject-to-BART units. If representative 

measurements of total emissions from 

subject-to-BART units can be obtained 

by installing CEMS in a single vent just 

prior to the common header for the 

waste-gas stacks and hood-exhaust 

stacks, then this final rule requires only 

two CEMS on each stack (one NOX

CEMS and one SO2 CEMS) for a total of 

four CEMS, not ten. The initial 

monitoring plans required by this final 

rule will be prepared by the facilities 

and will provide a means through 

which an effective monitoring program 

will be put into place. These plans 

should include proposals for CEMS 

types, CEMS numbers, CEMS 

installation locations, QA/QC 

procedures, and any other topics and 

are submitted to EPA for review and 

approval or disapproval. The 

installation locations provided in these 

plans shall be determined based on the 

requirements of 40 CFR part 60, 

appendices B and F. 

Commenters: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that 

requiring CEMS on emergency stacks is 

inappropriate. 

Response: The requirement to install 

CEMS on emergency stacks depends on 

the frequency and duration of the use of 

the emergency stacks during emergency 

events. If emergency stacks are used on 

a daily or weekly basis, then emissions 

from those stacks could have an impact 

on annual emissions (and visibility) and 

should be tracked and recorded. If 

emergency stacks are truly used 

infrequently for quick releases, then a 

CEMS may not be necessary. This can 

be addressed by each facility on a caseby-case basis in its monitoring plan. 

Commenters: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine 

Comment: Cliffs stated that the 

subject-to-BART facilities should be 

exempt from the applicable emission 

limits during startup, shutdown and 

malfunction events. 

Response: EPA disagrees. The CAA 

requires sources to comply with 

applicable emission limits at all times, 

including during startup, shutdown and 

malfunction. See, e.g., Sierra Club v. 

EPA, 551 F.3d 1019, 1021 (DC Cir. 

2008); US Magnesium, LLC v. EPA, 690 

F.3d 1157, 1170 (10th Cir. 2012). 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine and 

U.S. Steel. 

Comment: Cliffs commented that the 

requirement to develop and implement 

a corrective action program for excess 

emission events should be directed 

toward the emissions unit and not be 

part of the CEMS requirement. 

Response: EPA agrees that the 

corrective action plan for excess 

emission events should be directed 

toward the emissions unit. The 

corrective action plan should establish 

procedures that operators will follow 

each time an excess emission event 

occurs (as identified through the use of 

real-time CEMS data). These procedures 

should outline steps to adequately 

identify causes of excess emissions, 

actions to be taken to minimize or 

eliminate those emissions, and evaluate 

and implement practices to prevent the 

causes of such excess emissions from 

reoccurring. The corrective action plan 

can be an independently developed 

plan or the procedures can be 

incorporated into an existing Quality 

Control Program Plan, corrective action 

plan, or other existing standard 

operating plan. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that the 

dates proposed for installing CEMS are 

infeasible and suggested an alternative 

compliance period of 18 months. 

Response: EPA disagrees with the 

length of time Cliffs asserted is needed 

to design and install CEMS. EPA 

recognizes that a certain period of time 

will be needed if significant upgrades to 

stacks are necessary. However, the 

design and installation of a CEMS can 

be completed far more rapidly than the 

18-month period suggested by Cliffs. 

EPA also believes it is inappropriate to 

consider the time needed for CEMS 

installation in a cumulative sequential 

manner as suggested by Cliffs. Design, 

engineering requirements, and upgrades 

to data acquisition systems can be 

performed at the same time as other 

activities required by the proposed rule. 

EPA also recognizes that once CEMS 

are installed and operating, there will be 

a short period of time needed to 

optimize and become familiar with the 

system in order to certify the units. EPA 

believes that the entire process for 

CEMS installation can be successfully 

met within the time periods outlined in 

the proposed rule. However, in response 

to the comments received, the final rule 

provides an additional 30 days to certify 

the CEMS and perform the initial 

Relative Accuracy Test Audit of the 

CEMS. The anticipated dates for initial 

certification and the Relative Accuracy 

Test Audit must be included in the 

monitoring plan required by the rule. 

Commenter: U.S. Steel. 

Comment: U.S. Steel commented that 

it is overly burdensome to require 

redundant or backup monitoring 

systems to obtain emissions data during 

periods of primary CEMS breakdown, 

repair, calibration check, or zero span 

adjustment. U.S. Steel proposed to use 

data gap-filling procedures during those 

periods when data are not available 

from the CEMS due to these types of 

events. 

Response: The purpose of including 

the requirement to use ‘‘other 

monitoring systems approved by EPA’’ 

is to obtain real-time emissions data 

during periods of primary CEMS 

breakdown, repair, calibration check, or 

zero span adjustment. The secondary 

data can be used to assure data 

availability and compliance on a 

continuous basis. However, the 

requirement for ‘‘other monitoring 

systems’’ does not mean that a second 

CEMS system is necessarily needed. 

Because the duration of these CEMS 

downtime events is typically short, each 

subject-to-BART facility can submit 

proposals for using parametric 

monitoring or engineering estimates as a 

surrogate for actual emissions 

monitoring during these CEMS events. 

EPA expects that CEMS will be operated 

at all times, including periods of process 

unit startup, shutdown and 

malfunction, except during the events 

identified above as described at 40 CFR 

60.13(e). 

EPA also disagrees with the 

suggestion that gap-filling procedures 

(i.e., data substitution) should be used 

for periods of CEMS downtime. Gapfilling procedures are appropriate under 

40 CFR part 75 because it is a cap-andtrade program. This final rule is more 

appropriately related to regulations at 

40 CFR part 60, where compliance with 

an emission limit (rather than annual 

caps) is required. 40 CFR part 60 

prohibits the use of ‘‘data substitution’’ 

(i.e., gap-filling) because it does not 

provide accurate emission rates during 

the CEMS downtime. 

Commenter: U.S. Steel. 

Comment: U.S. Steel commented that 

it is not appropriate to require initial 

performance testing of subject-to-BART 


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facilities or units if the facility is 

operating a certified CEMS system on 

the affected units. 

Response: EPA has re-evaluated the 

need for initial performance testing and 

agrees with U.S. Steel that it is not 

necessary to require such testing, for 

purposes of this rule, at facilities that 

are or will be operating CEMS when 

those CEMS will be used to determine 

compliance. The requirement for initial 

performance testing has been removed 

from the final rule. It is important to 

note that while initial performance 

testing is being removed for purposes of 

demonstrating compliance, subject-toBART units must still be tested as part 

of the CEMS certification process, 

although this the certification process 

will typically not require a 30-day test. 

L. Comments Concerning Compliance 

Schedules 

Commenter: Leech Lake Band of 

Ojibwe. 

Comment: The Band supported the 

installation of low NOX burners and felt 

that the 1.5 years allowed for the initial 

installation, with additional burner 

installations to follow one year later, is 

a fair and progressive approach to 

control NOX emissions. 

Response: EPA agrees with the 

commenter that installing low NOX

burners is the appropriate approach. In 

response to additional information 

submitted by other commenters, 

however, EPA reviewed the proposed 

installation schedule has extended it by 

a number of months in the final rule, as 

discussed in more detail below. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs commented that the 

BART Guidelines require the states, or 

EPA when promulgating a FIP, to 

establish deadlines for compliance with 

BART emission limits no later than five 

years from the date of approval or 

promulgation. EPA’s proposed rule, 

however, contains arbitrary compliance 

deadlines that are unreasonably short. 

Cliffs stated that it would take at least 

four and a half years for it to complete 

the required engineering, installation, 

and commissioning of low NOX burners 

for a single furnace. ArcelorMittal stated 

that ‘‘a minimum of 48 months would 

be necessary to complete this onerous 

process’’ for its Minorca Mine facility. 

Response: CAA section 169A(b)(2)(A) 

requires subject-to-BART sources to 

install BART and comply with any 

applicable emission limits ‘‘as 

expeditiously as practicable.’’ The Act 

defines this term to mean ‘‘as 

expeditiously as practicable but in no 

event later than five years after * * * 

the date of promulgation.’’ CAA section 

169A(g)(4). This language does not 

indicate that a compliance schedule of 

five years is to be assumed. Rather, 

BART must be installed ‘‘as 

expeditiously as practicable,’’ meaning 

as soon as the source is capable of 

installing the controls and meeting the 

applicable emission limits. 

In response to EPA’s request for a 

detailed timeline of the steps required to 

install low NOX burners on a taconite 

furnace, U.S. Steel provided the 

following information based on its 

actual experience with a previous 

install: 

TABLE 7—U.S. STEEL’S ESTIMATE COMPLIANCE SCHEDULE

Task Time 

Detailed low NOX burner engineering ..................................................................................................................................... 6 months. 

Prepare permit applicability determination .............................................................................................................................. 2 months. 

Procure and manufacture low NOX burner ............................................................................................................................. 8 months. 

Install low NOX burner ............................................................................................................................................................. 3 weeks. 

Shakedown of low NOX burner ............................................................................................................................................... 6 months. 

Total time .......................................................................................................................................................................... 22 months, 3 weeks. 

In addition to this information, 

ArcelorMittal included an attachment to 

its comments of a September 27, 2012 

report by Fives North American titled 

‘‘Retrofitting Low NOX Burners on the 

ArcelorMittal Minorca Straight-Grate 

Pelletizing Furnace.’’ In that report, 

Fives states that to develop an 

engineering solution that complies with 

environmental requirements, it is 

important to allow sufficient time 

(approximately four to eight months) for 

engineering analysis and (possibly) 

testing. The schedule should allow for 

an additional seven months for 

fabrication and delivery, followed by an 

additional two months for installation 

and commissioning. This amounts to an 

estimated time of 17 months to achieve 

compliance. 

Based on the timeline provided by 

U.S. Steel, the vendor estimate from 

Fives, and concerns from the 

commenters, EPA is allowing 26 months 

for a company’s first indurating furnace 

to comply with the final rule. This will 

allow each source sufficient time to 

perform an engineering analysis, 

prepare a permit applicability 

determination, manufacture and install 

the low NOX burner, and allow for a 

shakedown period to achieve 

compliance after the low NOX burner 

has been installed. This is eight months 

longer than the proposed compliance 

schedule, allowing for the additional 

time needed for a shakedown period. 

The compliance schedule for 

additional indurating furnaces is being 

finalized as proposed. Specifically, a 

second line has an additional year to 

comply, for a total of 38 months from 

the effective date of the rule. A third 

line has two additional years to comply, 

for a total of 50 months from the 

effective date of the rule. This staggered 

installation schedule will minimize any 

potential impacts on production. EPA 

notes that U.S. Steel Minntac is 

following a shorter schedule consistent 

with the proposed rule. U.S. Steel 

Keetac will also follow a modified 

schedule. For more detail, see the 

comment below. 

Commenter: U.S. Steel. 

Comment: Due to the lead time 

associated with acquiring process fans 

at Keetac, which is estimated to be 52 

weeks according to a third-party 

engineering firm working on the project, 

and the timing of the major outage 

schedule, which only occurs once per 

year, the potential exists to miss the 

timing window where the two sync up 

to meet the proposed schedule. 

Therefore, U.S. Steel requests an 

additional 12 months to the proposed 

schedule for installation. In addition, 

because this will be the first installation 

of this technology at Keetac, U.S. Steel 

requests an additional 6 months prior to 

compliance with the proposed emission 

limit to allow for a shakedown period to 

optimize the burner for NOX reductions. 

Response: EPA agrees with U.S. Steel 

that additional time is needed to 

procure new pre-heat fans and to 

achieve compliance after installation. In 

the final rule, Keetac has three years (36 

months from the effective date of the 


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rule) for its single line to comply with 

the rule. 

Commenter: U.S. Steel. 

Comment: Due to timing of major 

outage schedules, U.S. Steel requests 

flexibility in the order of installation for 

Line 4 and Line 5 at Minntac. U.S. Steel 

agrees with the overall intent of the 

proposed schedule, but requests the 

option to select the order of installation 

of low NOX burners at Lines 4 and 5. 

Response: EPA agrees with the U.S. 

Steel’s request to leave to the discretion 

of U.S. Steel the order of installation of 

low NOX burners at Lines 4 and 5 at 

Minntac. 

M. Comments Asserting That EPA Must 

Conduct Government-to-Government 

Consultation With the Tribes 

Commenter: National Tribal Air 

Association (NTAA). 

Comment: The Association 

understands that at the request of the 

Fond du Lac Band, EPA held a June 28, 

2012 conference call with the region’s 

Tribes to discuss the FIP. We appreciate 

EPA for doing this and highly 

recommend that the Agency hold 

similar calls with Tribes for other such 

actions. However, EPA must also honor 

its commitment to conduct formal 

government-to-government consultation 

in accordance with Executive Order 

(EO) 13175. 

The Association disagrees with EPA’s 

statement that the FIP ‘‘does not have 

tribal implications, as specified in EO 

13175. It will not have substantial direct 

effects on tribal governments. Thus, EO 

13175 does not apply to this rule.’’ The 

application of BART to taconite ore 

processing facilities that either are in 

close proximity to Tribes and their 

communities or are within Treaty-ceded 

territory areas maintaining Tribes’ 

usufructary functions is a regulatory 

action that has Tribal implications. As 

such, EPA must conduct formal 

government-to-government consultation 

with Tribes. 

There are also clear purposes for EPA 

to conduct formal government-togovernment consultation with Tribes. 

First, it provides for more candid 

conversations between individual 

Tribes and EPA than would occur 

otherwise in a group meeting involving 

other Tribes. Second, each Tribe’s 

circumstances are unique and must be 

treated as such by EPA. Group meetings 

would only give short shrift to these 

circumstances. Third, most cultural 

resources information is protected from 

release under statutory exemptions to 

the Freedom of Information Act. 

Discussion of such information as part 

of a group meeting risks its release to 

the general public and potentially 

endangers Tribal cultural sites and 

practices. Finally, the subject matter 

may be so unique, such as a dispute 

between an individual Tribe about 

whose cultural resources might be 

located within or near a taconite ore 

processing facility, that government-togovernment consultation between the 

Tribe and EPA could provide the best 

opportunity for a resolution to the 

situation versus a group meeting where 

any number of issues might be 

discussed in a finite period of time. 

Response: EPA acknowledges that this 

action may have tribal implications. 

EPA recognizes that Tribes may have 

significant interests in regulatory 

programs even if the potential Tribal 

impacts are not the types specifically 

identified in the Executive Order. In this 

case, EPA initiated consultation with 

Tribal officials early in the process of 

developing this regulation to permit 

them to have meaningful and timely 

input into its development. While the 

Tribes ultimately chose not to engage in 

individual consultation, EPA did 

communicate with Tribal 

representatives to ensure that 

information was made available and 

that there was sufficient opportunity for 

questions and discussion. This effort is 

described in further detail in Section IV 

of this final rule. EPA appreciates the 

comments provided by the Tribes and 

NTAA on this rule, which will benefit 

Tribes through reduced pollution and 

improved visibility. 

N. Comments Concerning Non-Air 

Quality Impacts of the Proposed Rule 

Commenter: Cliffs Natural Resources. 

Comment: Cliffs commented that 

significant environmental impacts will 

result if the rule is finalized as 

proposed. Cliffs stated that increased 

fuel combustion resulting from low NOX

burner application will result in 

increased emissions of the products of 

combustion. Cliffs added that EPA’s 

proposed SO2 controls also carry 

ancillary environmental consequences. 

Response: EPA disagrees. The BART 

Guidelines recognize that 

environmental concerns become 

important when sensitive site-specific 

receptors exist and are impacted by 

byproducts of the control device. 

However, the fact that a control device 

creates liquid and solid waste that must 

be disposed of does not necessarily 

argue against that technology as BART. 

In this case, there are no such sensitive, 

site-specific issues. To avoid any such 

issues, EPA rejected the use of wet SO2

scrubbing at taconite plants in 

Minnesota because wastewater from wet 

scrubbing had the potential to interfere 

with the production of wild rice. 

Commenter: National Tribal Air 

Association. 

Comment: The Association 

commented that Tribal traditional 

practices will benefit by controlling 

NOX and SO2 emissions from taconite 

ore processing facilities. Such benefits 

specifically relate to visibility, health, 

and acid deposition. 

Not only does regional haze, which 

the FIP addresses, reduce the clarity, 

color, and visible distance that one can 

see, it marginalizes Tribal traditional 

practices that have existed since time 

immemorial. Many Tribes engage in 

traditional practices associated with 

sacred mountains, lakes, or other places 

that hold significance to them. Some of 

these practices are dependent on Tribal 

members being able to view and honor 

such icons that may be located many 

miles from a Tribe’s lands. 

A corresponding effect of NOX and 

SO2 emissions on Tribal traditional 

practices is on the health of Tribal 

members. Tribes are not immune from 

the health effects of NOX and SO2, such 

as asthma, bronchitis, and heart disease. 

In fact, they are more susceptible to 

these effects based on lifestyles. Many 

Tribes and their members spend 

considerable time outdoors engaged in 

Tribal traditional practices. Timehonored practice precludes Tribal 

members from simply moving indoors 

during high or moderate NOX or SO2

emission episodes. Hence, they 

experience increased health effects due 

to their long-term exposure to NOX and 

SO2. However, the FIP does much to 

reduce their exposures to such 

emissions from taconite ore processing 

facilities. 

Tribal traditional practices are also 

affected by acid deposition for which 

NOX and SO2 serve as precursors. Upon 

being emitted into the atmosphere, NOX

and SO2 return to the Earth’s surface is 

one of two ways. The first occurs when 

these pollutants mix with water vapor 

in the atmosphere and are subsequently 

converted into acids. This is known as 

wet deposition. The second way occurs 

when NOX and SO2 form gases and 

salts. These gases and salts can cling to 

basically anything, including the 

ground, trees, and buildings. After they 

attach to an object, they are converted 

into acids at the point where moisture 

in the air mixes with them. Tribal foods, 

such as wild rice, can be contaminated 

by acid deposition. Forest ecosystems, 

which are an integral part to Tribal life, 

are susceptible to oxidation damage due 

to acid deposition and ozone exposure. 

Acid deposition adversely affects 

everything in the forest ecosystem, and 

the plants and animals on which a 

number of Tribes subsist. The 


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petroglyphs (rock images) and other 

sacred sites of Tribes are also 

susceptible to acid deposition and 

decay. The FIP helps to control acid 

deposition that would otherwise occur 

due to the emissions of taconite ore 

processing facilities. Undeniably, this 

will benefit the region’s Tribes. 

Response: While the focus of the 

regional haze program is to improve 

visibility at Class I areas, the EPA agrees 

with the Association that emission 

reductions made to improve visibility 

have additional benefits. EPA agrees 

that Midwestern Tribes will benefit as 

the regional haze program is 

implemented and emission reductions 

occur. 

Commenter: Leech Lake Band of 

Ojibwe. 

Comment: The Band commented 

about concerns related to the damage of 

wild rice. Wild rice is extremely 

susceptible to sulfides where impacts 

from these emissions can be currently 

observed. The effects of sulfide 

degradation can have detrimental effects 

on Tribal Lifeways for this important 

cultural and subsistence food source. 

Commenter: Red Cliff Band of Lake 

Superior Chippewas. 

Comment: Sulfur dioxide is a 

pollutant of special concern to the Red 

Cliff Tribe due to its negative impacts 

on sensitive aquatic organisms such as 

wild rice and its interaction with 

atmospherically deposited mercury in 

aquatic systems. Reductions in SO2

could help to decrease the methylation 

of mercury in waters fished by Red Cliff 

and reduce limitations on how much 

locally harvested fish tribal members 

can safely consume. 

Response: EPA did consider the 

energy and non-air quality 

environmental impacts as part of its 

BART determinations. EPA is aware of 

the concerns regarding sulfur oxides in 

wastewater and the resulting effect on 

wild rice. Accordingly, EPA considered 

the significance of the potential impacts 

of wastewater releases while evaluating 

the control technology options for the 

taconite facilities. 

Commenter: National Tribal Air 

Association. 

Comment: Tribes shoulder a 

disproportionate burden of the negative 

environmental consequences caused by 

the operation of commercial and 

industrial facilities. Most of these 

facilities are not located in Tribal 

communities, but their emissions often 

find their way onto Reservations and 

Ceded Territories. Such is the case for 

the taconite ore processing facilities 

whose current emissions not only affect 

the region’s Tribes, but whose 

conversion to ozone could impact these 

Tribes even further. The Association 

finds that the NOX reductions required 

under the FIP will help address the 

problem of ozone levels rising with 

respect to the taconite ore processing 

facilities and will inhibit climate change 

albeit a small amount. 

Response: While emission reductions 

being required of the taconite industry 

are solely to improve visibility at 

mandatory Class I areas, EPA agrees that 

collateral benefits may also be achieved 

due to the emission reductions. EPA did 

not attempt to identify or quantify these 

additional potential benefits in this final 

rule. 

O. Miscellaneous Comments 

Commenter: Red Cliff Band of Lake 

Superior Chippewas. 

Comment: The Northeast Minnesota 

Plan calls for a 30 percent reduction in 

emissions of SO2 and NOX (regional 

haze causing pollutants) from large 

emitters in this region by the year 2018, 

with an interim goal of a 20 percent 

reduction by the year 2012. Minnesota’s 

regional haze SIP states that these 

facilities are well on-track for meeting 

these goals. However, over the past 

several years there have been numerous 

applications for new mining projects in 

the area. The Band is very concerned 

with maintaining the progress that has 

already been achieved, so that 

Voyageurs National Park and the 

Boundary Waters Canoe and Wilderness 

Area can meet their regional haze 

Reasonable Progress Goals, as required 

in the Regional Haze Rule. 

Response: EPA gave final approval to 

many elements of the Minnesota 

regional haze plan on June 12, 2012 (77 

FR 34801). This approval included the 

Northeast Minnesota Plan. EPA expects 

Minnesota to meet the pollution 

reductions goals in the Plan, which may 

include needing to offset any emission 

increases from new and expanding 

facilities with deeper emission 

reductions from other facilities. 

Commenter: Fond du Lac Band of 

Lake Superior Chippewa. 

Comment: The Band commented that 

it was concerned how the taconite 

facilities will meet the new hourly SO2

and NO2 National Ambient Air Quality 

Standards (NAAQS) that have recently 

been issued by EPA. It is likely that at 

least some of these facilities will need 

to install additional control equipment 

in order to be able to demonstrate 

attainment with these new standards. 

The installation of low NOX burners on 

the BART-eligible taconite sources 

promises to be a good solution, both for 

achieving the one-hour NO2 NAAQS 

and for reducing regional haze. Given 

the current state of uncertainty as to 

how modeling for this one-hour 

standard should be approached, it may 

be years before controls are required on 

taconite furnaces as a solution to any 

modeled exceedances of the NAAQS. 

The Band is concerned that this will 

cause delay in achieving regional haze 

goals in this area. It is also possible that 

litigation against or revocation of the 

NAAQS could further delay the area in 

achieving these goals. 

Response: EPA agrees that control 

technology installed to meet BART 

requirements for regional haze may also 

contribute to improvements in ambient 

air quality. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs noted that it could 

not duplicate some of the delta DV and 

delta days values listed in Tables V– 

C.10, V–C.11, and V–C.14 of the 

proposed FIP. 

Response: Upon review of the values, 

EPA agrees with the Cliffs that some of 

the delta DV and delta days values were 

incorrect in the proposed rule. 

Specifically, some of the values listed in 

Tables V–C.5, V–C.8, and V.C.9 were 

incorrect. Cliffs also noted that it could 

not reproduce values in Tables V–C.10, 

V–C.11, and V–C.14. These values were 

linked to values in the previous tables 

and also were listed incorrectly. EPA 

regrets the errors, but overall, the 

corrections were minor and did not 

change the conclusions reached. 

Corrected tables are listed below. 

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 (D NOX) ............................................................................................. 0 tons/year 


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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—Continued 

Parameter Boundary 

waters Voyageurs Isle Royale 

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

D dv PM2.5 .................................................................................................................................... ¥1.2 ¥0.8 ¥0.3 

D dv PM2.5/D SO2 ......................................................................................................................... ¥0.00065 ¥0.00043 ¥0.000016 

D Days PM2.5 ............................................................................................................................... ¥10 ¥8 ¥3 

D Days PM2.5/D SO2 .................................................................................................................... ¥0.0054 ¥0.0044 ¥0.0016 

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 Voyageurs Isle Royale 

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

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

D dv PM2.5 .................................................................................................................................... ¥0.2 ¥0.1 ¥0.2 

D dv PM2.5/D NOX ........................................................................................................................ ¥0.00029 ¥0.00015 ¥0.00029 

D DV PM2.5/D SO2 ........................................................................................................................ ¥0.00045 ¥0.00023 ¥0.00045 

D Days PM2.5 ............................................................................................................................... ¥5 ¥1 ¥3 

D Days PM2.5/D NOX .................................................................................................................... ¥0.0074 ¥0.0015 ¥0.0044 

D Days PM2.5/D SO2 .................................................................................................................... ¥0.011 ¥0.0023 ¥0.0068 

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

Parameter ratio Boundary 

waters Voyageurs Isle Royale 

D DV PM2.5/D NOX ....................................................................................................................... ¥0.00061 ¥0.00030 ¥0.00042 

D DV PM2.5/D SO2 ........................................................................................................................ ¥0.00050 ¥0.00025 ¥0.00030 

D Days/D NOX .............................................................................................................................. ¥0.0083 ¥0.004 ¥0.00524 

D Days/D SO2 .............................................................................................................................. ¥0.0067 ¥0.0030 ¥0.0037 

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

ARCELORMITTAL

Visibility factor or pollutant emissions reduction Boundary 

waters Voyageurs Isle Royale 

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

D DV ............................................................................................................................................. ¥1.7 ¥0.9 ¥1.2 

D Days > 0.5 DV .......................................................................................................................... ¥24 ¥11 ¥15 

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

TACONITE

Visibility factor or pollutant emissions reduction Boundary 

waters Voyageurs Isle Royale 

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

D DV ............................................................................................................................................. ¥3.2 ¥1.6 ¥2.2 

D Days > 0.5 DV .......................................................................................................................... ¥44 ¥21 ¥28 

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

Visibility factor or pollutant emissions reduction Boundary 

waters Voyageurs Isle Royale 

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

D DV ............................................................................................................................................. ¥1.8 ¥0.9 ¥1.2 


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TABLE V–C.12—ESTIMATED EMISSION REDUCTIONS AND RESULTING CHANGES IN VISIBILITY FACTORS FOR U.S. STEELKEETAC—Continued 

Visibility factor or pollutant emissions reduction Boundary 

waters Voyageurs Isle Royale 

D Days > 0.5 DV .......................................................................................................................... ¥24 ¥11 ¥15 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: References to the optional 

use of Part 75 recordkeeping 

requirements should be removed from 

the proposed rule because taconite 

furnaces are not Acid Rain subject units. 

Response: EPA intended to provide 

the Part 75 recordkeeping requirements 

as an option for facilities electing to use 

those recordkeeping requirements. If a 

subject-to-BART facility is not subject to 

the Acid Rain requirements, then 

recordkeeping requirements of either 40 

CFR part 60 or 40 CFR part 63 may be 

used. 

Commenter: Cliffs Natural Resources, 

ArcelorMittal Minorca Mine, and U.S. 

Steel. 

Comment: Cliffs and U.S. Steel noted 

that the reference to 40 CFR 163.3 is 

incorrect and should be revised to 40 

CFR 136.3. 

Response: A correct citation is 

provided in the final rule. 

Commenter: Cliffs Natural Resources 

and ArcelorMittal Minorca Mine. 

Comment: Cliffs noted that the 

reference to 40 CFR part 60, appendix 

B, Performance Specification 2, 

Procedure 1, is incorrect. Procedure 1 

should be associated with 40 CFR part 

60, appendix F. 

Response: A correct citation is 

provided in the final rule. 

Commenter: Cliffs Natural Resources, 

ArcelorMittal Minorca Mine, and U.S. 

Steel. 

Comment: Cliffs and U.S. Steel stated 

that the inclusion of references to the 

General Provisions of 40 CFR part 63 is 

inappropriate and overly burdensome. 

The references to 40 CFR part 63 should 

be removed. 

Response: EPA included references to 

40 CFR part 63 because many of those 

requirements (including the 

development of a startup, shutdown and 

malfunction plan and monitoring plan) 

should have already been developed for 

the subject-to-BART facilities for 

purposes of the Taconite MACT rule. 

Additionally, the requirements 

associated with the installation, 

certification, maintenance, and 

operation of the CEMS are similar. 

However, in response to the comments 

received, references to 40 CFR part 63 

will be removed. References to 40 CFR 

part 60, appendices B and F will be 

retained where appropriate. The rule 

has also been revised to specifically 

identify requirements that we intended 

to include (for example notifications or 

reporting), but which were previously 

incorporated through citing to either 40 

CFR part 60 or 40 CFR part 63. 

III. What action is EPA taking? 

The emission sources discussed 

below are indurating furnaces at seven 

taconite facilities. Six of the taconite 

facilities, ArcelorMittal, Hibbing 

Taconite, Northshore Mining, U.S. Steel 

Keetac, U.S. Steel Minntac, and United 

Taconite, are located in Minnesota, 

while Tilden is located in Michigan. 

EPA has adopted the terminology used 

by the companies and states to identify 

the indurating furnaces to ensure 

consistency with permits and other 

enforceable documents. However, 

regardless of whether the emission 

sources are referred to as furnaces, kilns, 

or lines, all terms refer to indurating 

furnaces, which involve a high 

temperature process for hardening 

taconite pellets for subsequent use in 

blast furnaces. 

A. NOX Limits 

EPA is revising its proposed limit of 

1.2 lbs NOX/MMBTU, on a 30-day 

rolling average, to a limit of 1.2 lbs 

NOX/MMBTU when only natural gas is 

used and a limit of 1.5 lbs NOX/MMBTU 

for all other fuels, on a 30-day rolling 

average, for all indurating furnaces. 

These revised limits are based upon test 

data submitted by U.S. Steel for Lines 6 

and 7 at Minntac while using low NOX

burners. This revision affects U.S. Steel 

Keetac, U.S. Steel Minntac, and United 

Taconite, which use solid fuel. The 

other four facilities will be subject to the 

natural gas limit of 1.2 lbs NOX/ 

MMBTU. To meet these limits, the 

sources will essentially be required to 

install low NOX burners on each 

indurating furnace. Based upon 

information received during the 

comment period, EPA believes that 26 

months is a reasonable time for a 

company’s first indurating furnace to 

comply with the limit. This will allow 

each company sufficient time to perform 

an engineering analysis, prepare a 

permit applicability determination, 

manufacture and install the low NOX

burner(s), and provide for a shakedown 

period to achieve compliance after the 

low NOX burner(s) have been installed. 

While this compliance schedule is six 

months longer than the proposal, EPA 

believes that the additional time is 

necessary for a shakedown period. 

As specified in the proposal, a second 

line will have an additional year to 

comply with the emission limit, while 

a third line will have two additional 

years to comply. This approach will 

stagger the installation and minimize 

impacts on production. EPA notes, 

however, that U.S. Steel Minntac is on 

a shorter schedule consistent with what 

was proposed, while U.S. Steel Keetac 

has been given three years to comply 

with its only line. The additional time 

afforded to U.S. Steel Keetac is 

primarily due to the lead time 

associated with acquiring process fans. 

B. SO2 Limits 

EPA is revising all of the proposed 

SO2 limits as follows. Unless otherwise 

stated, these limits are based on the 95th 

percentile UPL. 

Tilden Mining Company 

Tilden’s Grate Kiln Line 1 is required 

to convert to 100 percent natural gas 

and install CEMS within one year of the 

effective date of this rule. Within 26 

months of the effective date of this rule, 

an emission limit must be established, 

in terms of lbs SO2/hr, on a 30-day 

rolling average, based on the 95th 

percentile UPL. This compliance 

schedule allows two months to process 

12 months of CEMS data. This is a 

change from the proposed requirement 

to install an add-on control system, 

achieving either 5 ppmv SO2 or 95 

percent removal efficiency, because 

such a control system is not 

economically feasible when a furnace is 

using only natural gas. 

U.S. Steel Keetac 

An emission limit of 225 lbs SO2/hr, 

based on a 30-day rolling average, shall 

apply to U.S. Steel Keetac’s Grate Kiln 

pelletizing furnace beginning three 

months from the effective date of the 

rule. This numerical limit and 

compliance schedule are the same as 

those contained in the proposed 

rulemaking and reflect existing controls. 

However, redundant control efficiency 

and pH limits have been eliminated. 


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EPA has clarified in the final rule that, 

in addition to this SO2 limit, any coal 

burned at Keetac must have a sulfur 

content no greater than 0.60 percent 

sulfur by weight based on a monthly 

block average. 

Hibbing Taconite 

An aggregate emission limit of 247.8 

lbs SO2/hr, based on a 30-day rolling 

average, shall apply to the pelletizing 

furnaces at Hibbing’s three lines 

beginning six months from the effective 

date of this rule. This limit reflects 

existing controls. This is an increase 

from the proposed limit, which totaled 

183 lbs SO2/hr, based on a 30-day 

rolling average. This increase is a result 

of more accurate emission data that was 

obtained subsequent to the proposal. 

U.S. Steel Minntac 

An aggregate emission limit of 498 lbs 

SO2/hr shall apply to indurating furnace 

Lines 3–7 when all lines are producing 

flux pellets. An aggregate emission limit 

of 630 lbs SO2/hr shall apply to Lines 

3–7 when Lines 3–5 are producing acid 

pellets and Lines 6 and 7 are producing 

flux pellets. An aggregate emission limit 

of 800 lbs SO2/hr shall apply to Lines 

3–7 when all lines are producing acid 

pellets. These limits reflect existing 

controls. These SO2 emission limits are 

based on a 30-day rolling average and 

apply three months from the effective 

date of this rule. This is an increase 

from the proposed limits, which totaled 

327 lbs SO2/hr, based on a 30-day 

rolling average. This increase is a result 

of more accurate emission data that was 

obtained subsequent to the proposal. 

EPA has clarified in the final rule that, 

in addition to these SO2 limits, any coal 

burned at Minntac must have a sulfur 

content no greater than 0.60 percent 

sulfur by weight based on a monthly 

block average. 

United Taconite 

An aggregate emission limit of 529 lbs 

SO2/hr, based on a 30-day rolling 

average, shall apply to the Line 1 and 

Line 2 pellet furnaces beginning 54 

months from the effective date of this 

rule. In addition to this limit, United 

Taconite is required to burn either 

natural gas or a blend of natural gas and 

coal. Any coaled burned must have a 

sulfur content no greater than 0.60 

percent sulfur by weight based on a 

monthly block average. This limit 

represents a change from the proposed 

requirement to install an add-on control 

system, achieving either 5 ppmv SO2 or 

95 percent removal efficiency. Because 

this federally enforceable operational 

change in fuel mixture will achieve 

approximately a 50 percent reduction in 

the facility’s baseline and actual 

emissions, the proposed add-on control 

system is no longer cost effective. 

ArcelorMittal Minorca Mine 

An emission limit of 38.16 lbs SO2/hr, 

based on a 30-day rolling average, shall 

apply to ArcelorMittal’s indurating 

furnace beginning six months from the 

effective date of this rule. This is an 

increase from the proposed limit of 23 

lbs SO2/hr, based upon a 30-day rolling 

average. This increase is a result of more 

accurate emission data that was 

obtained subsequent to the proposal. 

Northshore Mining Company 

An aggregate emission limit of 39 lbs 

SO2/hr, based on a 30-day rolling, shall 

apply to Furnace 11 and Furnace 12, 

beginning six months from the effective 

date of this rule. This limit will stay 

effective for one year. This is an 

increase from the proposed limit of 33.4 

lbs SO2/hr, based upon a 30-day rolling 

average. The proposed control efficiency 

requirement has been eliminated 

because it is a redundant requirement. 

Within 20 months of the effective date 

of this rule, a revised SO2 limit must be 

established based on one year of hourly 

CEMS data using the 95th percentile 

UPL. 

C. CEMS 

As required in the proposal, 

installation and operation of CEMS is 

required no later than the applicable 

compliance date for each limit. This 

represents no change from the proposed 

rulemaking. However, as indicated 

above, some compliance dates have 

been extended, and some indurating 

furnaces are now subject to status-quo 

SO2 limits. Based upon comments 

received, as well as additional 

information regarding the amount of 

time needed to install CEMS, we have 

increased the compliance schedule from 

three months to six months for those 

sources that are maintaining status quo 

controls and do not currently have 

CEMS. 

D. Visibility Benefits and Cost 

Effectiveness 

EPA estimates that this action will 

improve visibility at four Class I areas 

by reducing about 22,000 tons per year 

of NOX emissions and 2,000 tons per 

year of SO2 emissions from seven 

taconite facilities. The reductions in 

NOX emissions will result from the 

installation of low NOX burners, a 

relatively inexpensive control device 

that does not involve significant retrofit 

costs as the process consists primarily of 

switching out burners. U.S. Steel 

Minntac is the only facility at which 

low NOX burners have been installed 

and the only one for which detailed cost 

information is available. 

TABLE 8—LOW NOX BURNER COST ANALYSIS AT U.S. STEEL MINNTAC LINE 6 

Fuel blend Capital cost 

($) 

Annualized 

capital cost 

($/yr) 

Annual O&M 

($/yr) 

Total 

annualized 

cost 

($/yr) 

Costeffectiveness 

($/ton) 

60% Coal/40% Natural Gas ................................................. $2,846,422 $536,754 $228,293 $765,048 $441 

100% Natural Gas ............................................................... 2,846,422 536,754 228,293 765,048 210 

EPA believes that the costs cited by 

U.S. Steel are generally applicable 

across the industry based on discussions 

the Agency had with vendors. As a 

result, a figure of $500/ton was 

ultimately selected as a conservative 

upper bound for the cost effectiveness of 

installations at the other taconite 

facilities. 

Reductions in SO2 emissions will 

result from fuel switching and new 

emission limits that properly reflect 

existing SO2 controls. EPA did not have 

sufficient information to estimate the 

costs of fuel switching. 

Proposed Disapproval of the States’ 

BART Determinations for Taconite 

Facilities 

EPA reiterates that the Agency is not 

taking action today on its proposed 

disapproval of Minnesota and 

Michigan’s BART determinations for the 

taconite industry. EPA is issuing a 

separate supplemental notice of 


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8732 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

proposed rulemaking that provides 

additional explanation of the Agency’s 

rationale for the proposed disapproval 

and solicits additional comments. EPA 

will publish a separate final rulemaking 

regarding the proposed disapproval 

once the Agency has completed review 

of any additional public comments 

received. 

IV. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action finalizes BART 

requirements for seven taconite facilities 

in Minnesota and Michigan. Therefore, 

it is not a rule of general applicability, 

and not a ‘‘significant regulatory action’’ 

under the terms of Executive Order 

12866 (58 FR 51753, October 4, 1993). 

Because this type of action is exempt 

from review under EO 12866, it is also 

not subject to review under Executive 

Order 13563 (76 FR 3821, January 21, 

2011). 

B. Paperwork Reduction Act 

This action does not impose an 

information collection burden under the 

provisions of the Paperwork Reduction 

Act, 44 U.S.C. 3501 et seq. Burden is 

defined at 5 CFR 1320.3(b). Because this 

FIP only applies to seven facilities in 

Minnesota and Michigan, the Paperwork 

Reduction Act does not apply. See 5 

CFR 1320.3(c). 

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 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-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of this action on small entities, 

I certify that this action will not have a 

significant economic impact on a 

substantial number of small entities. 

The net result of this final action is that 

EPA is promulgating emission controls 

on selected units at seven large taconite 

facilities that are not owned by small 

entities, and therefore are not 

themselves small entities. 

D. Unfunded Mandates Reform Act 

(UMRA) 

This rule does not contain a Federal 

mandate that may result in expenditures 

of $100 million or more for State, local, 

and tribal governments, in the aggregate, 

or the private sector in any one year. It 

is a rule of particular applicability that 

affects only seven facilities in Michigan 

and Minnesota. Thus, this rule is not 

subject to the requirements of sections 

202 or 205 of UMRA. 

This rule is also not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. This 

rule only applies to seven facilities in 

Michigan and Minnesota. 

E. Executive Order 13132 Federalism 

This action does not have federalism 

implications. It 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. This action 

addresses Michigan and Minnesota’s 

failure to submit SIPs by the applicable 

deadline that meet the regional haze 

requirements under the Clean Air Act. 

Thus, Executive Order 13132 does not 

apply to this action. Although section 6 

of Executive Order 13132 does not 

apply to this action, EPA did consult 

with Michigan and Minnesota in 

developing this action. 

F. Executive Order 13175 

Subject to Executive Order 13175 (65 

FR 67249, November 9, 2000), EPA may 

not issue a regulation that has Tribal 

implication, 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 Tribal governments, or 

EPA consults with Tribal officials early 

in the process of developing the 

proposed regulation and develops a 

Tribal summary impact statement. 

EPA has concluded that this action 

may have Tribal implications. For 

example, although the FIP does not 

apply to sources in Indian country, 

controls and emission reductions arising 

from the program may affect Indian 

country or other Tribal interests. 

However, the regulations arising under 

this action will neither impose 

substantial direct compliance costs on 

Tribal governments, nor preempt Tribal 

law. 

EPA initiated consultation with Tribal 

officials early in the process of 

developing this regulation to permit 

them to have meaningful and timely 

input into its development. EPA sent an 

invitation to consult to each Region 5 

Tribe on August 15, 2012, along with a 

copy of the proposed taconite FIP 

Federal Register notice. Conference 

calls were held on the taconite FIP 

proposal on August 22, 2012 and 

September 12, 2012 to provide all 

Region 5 Tribes with more information 

on the proposed rulemaking and an 

opportunity to ask questions of EPA 

technical staff and request individual 

consultation if desired. Four Region 5 

Tribes participated in the August 22, 

2012 call. Two Region 5 Tribes 

participated in the September 12, 2012 

discussion. One Region 5 Tribe 

provided verbal testimony at the public 

hearing held on the proposed taconite 

FIP rulemaking on August 29, 2012. One 

Region 5 Tribal Chair expressed 

appreciation for the discussions held 

with the Tribes and gratitude for EPA’s 

careful consideration of the regional 

haze situation in northeast Minnesota. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets Executive Order 13045 

(62 FR 19885, April 23, 1997) as 

applying only to those regulatory 

actions that concern health or safety 

risks, such that the analysis required 

under section 5–501 of the executive 

order has the potential to influence the 

regulation. This action is not subject to 

Executive Order 13045 because it 

implements specific standards 

established by Congress in statutes. 

However, to the extent this rule will 

limit emissions, 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, 

2001) because it is not a significant 

regulatory action under Executive Order 

12866. 


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Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 8733 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (‘‘NTTAA’’), Public Law 

104–113, 12(d) (15 U.S.C. 272 note) 

directs EPA to use voluntary consensus 

standards in its regulatory activities 

unless to do so would be inconsistent 

with applicable law or otherwise 

impractical. Voluntary consensus 

standards are technical standards (e.g., 

materials specifications, test methods, 

sampling procedures, and business 

practices) that are developed or adopted 

by voluntary consensus standards 

bodies. NTTAA directs EPA to provide 

Congress, through OMB, explanations 

when the Agency decides not to use 

available and applicable voluntary 

consensus standards. 

This action does not involve technical 

standards. Today’s action does not 

require the public to perform activities 

conducive to the use of voluntary 

consensus standards. Therefore, EPA 

did not consider the use of any 

voluntary consensus standards. 

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 rule 

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. This rule limits 

emissions from seven facilities. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. Section 804 

exempts from section 801 the following 

types of rules: (1) Rules of particular 

applicability; (2) rules relating to agency 

management or personnel; and (3) rules 

of agency organization, procedure, or 

practice that do not substantially affect 

the rights or obligations of non-agency 

parties. 5 U.S.C. 804(3). EPA is not 

required to submit a rule report 

regarding today’s action under section 

801 because this is a rule of particular 

applicability. 

L. Judicial Review 

Under section 307(b)(1) of the Clean 

Air Act, petitions for judicial review of 

this action must be filed in the United 

States Court of Appeals for the 

appropriate circuit by April 8, 2013. 

Pursuant to Clean Air Act section 

307(d)(1)(B), this action is subject to the 

requirements of Clean Air Act section 

307(d) because it promulgates a FIP 

under Clean Air Act section 110(c). 

Filing a petition for reconsideration by 

the Administrator of this final rule does 

not affect the finality of this action for 

the purposes of judicial review, nor 

does it extend the time within which a 

petition for judicial review may be filed, 

and shall not postpone the effectiveness 

of such rule or action. This action may 

not be challenged later in proceedings to 

enforce its requirements. See Clean Air 

Act section 307(b)(2). 

List of Subjects in 40 CFR Part 52 

Environmental protection, Air 

pollution control, Incorporation by 

reference, Intergovernmental relations, 

Nitrogen dioxide, Particulate matter, 

Reporting and recordkeeping 

requirements, Sulfur oxides, Volatile 

organic compounds. 

Dated: January 15, 2013. 

Lisa P. Jackson, 

Administrator. 

40 CFR part 52 is amended as follows: 

PART 52—APPROVAL AND 

PROMULGATION OF 

IMPLEMENTATION PLANS 

■ 1. The authority citation for part 52 

continues to read as follows: 

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

Subpart X—Michigan 

■ 2. Section 52.1183 is amended by 

adding and reserving paragraph (j), and 

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

to read as follows: 

§ 52.1183 Visibility protection. 

* * * * * 

(j) [Reserved] 

(k) Tilden Mining Company, or any 

subsequent owner/operator of the 

Tilden Mining Company facility in 

Ishpeming, Michigan, shall meet the 

following requirements: 

(1) NOX Emission Limits. An emission 

limit of 1.5 lbs NOX/MMBtu, based on 

a 30-day rolling average, shall apply to 

the indurating furnace, Grate Kiln Line 

1 (EUKILN1), beginning 26 months from 

March 8, 2013. However, for any 30, or 

more, consecutive days when only 

natural gas is used a limit of 1.2 lbs 

NOX/MMBtu, based on a 30-day rolling 

average, shall apply. 

(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 March 8, 2013. 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 March 8, 2013. The 

sampling and calculation methodology 

for determining the sulfur content of 

fuel must be described in the 

monitoring plan required at paragraph 

(n)(8)(x) of this section. 

(3) The owner or operator of the 

facility must switch Grate Kiln Line 1 

(EUKILN1) to 100 percent natural gas 

beginning 1 year from March 8, 2013. 

For the purposes of CEMS requirements, 

the compliance date by which the CEMS 

must be installed and operated for 

Tilden is one year from March 8, 2013. 

Within 26 months of March 8, 2013, the 

owner or operator must calculate and 

comply with an SO2 limit based on one 

year of hourly CEMS emissions data 

reported in lbs SO2/hr and submit such 

limit, calculations and CEMS data to 

EPA. This limit shall be calculated in 

terms of lbs SO2/hr, based on the 

following equations, with compliance to 

be determined on a 30-day rolling 

average. 

m ¥ (n + 1) * a 

m = the rank of the ordered data point, when 

data is sorted smallest to largest 

n = number of data points 

a = 0.95, to reflect the 95th percentile 

If m is a whole number, then the limit, 

UPL, shall be computed as: 

UPL = Xm, 

Where: 

xm ¥ value of the mth data point in terms 

of lbs SO2/hr, when the data is sorted 

smallest to largest 

If m is not a whole number, the limit 

shall be computed by linear 


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8734 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

interpolation according to the following 

equation. 

Where: 

mt = the integer portion of m, i.e., m 

truncated at zero decimal places, and 

md = the decimal portion of m 

(4) Starting 26 months from March 8, 

2013, records shall be kept for any day 

during which fuel oil is burned as fuel 

(either alone or blended with other 

fuels) in Grate Kiln Line 1. These 

records must include, at a minimum, 

the gallons of fuel oil burned per hour, 

the sulfur content of the fuel oil, and the 

SO2 emissions in pounds per hour. 

(5) Starting 26 months from March 8, 

2013 for Grate Kiln Line 1, the SO2 limit 

does not apply for any hour in which it 

is documented that there is a natural gas 

curtailment, beyond Cliffs’ control, 

necessitating that the supply of natural 

gas to Tilden’s Line 1 indurating furnace 

is restricted or eliminated. Records must 

be kept of the cause of the curtailment 

and duration of such curtailment. 

During such curtailment, the use of 

backup coal is restricted to coal with no 

greater than 0.60 percent sulfur by 

weight. 

(l) Testing and monitoring. (1) 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. 

Compliance with the emission limits for 

NOX shall be determined using data 

from the CEMS. 

(2) The owner or operator shall 

install, certify, calibrate, maintain and 

operate a CEMS for SO2 on Tilden 

Mining Company unit EUKILN1. 

Compliance with the emission standard 

selected for SO2 shall be determined 

using data from the CEMS. 

(3) 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 NOX and SO2

concentrations to units of the standard 

(lbs/MMBtu and lbs/hr, respectively) 

unless a demonstration is made that a 

diluent monitor and continuous flow 

rate monitor are not needed for the 

owner or operator to demonstrate 

compliance with applicable emission 

limits in units of the standards. 

(4) For purposes of this section, all 

CEMS required by this section must 

meet the requirements of paragraphs 

(l)(4)(i)–(xiv) of this section. 

(i) All CEMS must be installed, 

certified, calibrated, maintained, and 

operated in accordance with 40 CFR 

Part 60, Appendix B, Performance 

Specification 2 (PS–2) and Appendix F, 

Procedure 1. 

(ii) All CEMS associated with 

monitoring NOX (including the NOX

monitor and necessary diluent and flow 

rate monitors) must be installed and 

operational no later than the compliance 

date for the emission limit identified at 

(k)(1). All CEMS associated with 

monitoring SO2 must be installed and 

operational no later than twelve months 

after March 8, 2013. Verification of the 

CEMS operational status shall, as a 

minimum, include completion of the 

manufacturer’s written requirements or 

recommendations for installation, 

operation, and calibration of the 

devices. 

(iii) The owner or operator must 

conduct a performance evaluation of 

each CEMS in accordance with 40 CFR 

Part 60, Appendix B, PS–2. The 

performance evaluations must be 

completed no later than 60 days after 

the respective CEMS installation. 

(iv) The owner or operator of each 

CEMS must conduct periodic Quality 

Assurance, Quality Control (QA/QC) 

checks of each CEMS in accordance 

with 40 CFR Part 60, Appendix F, 

Procedure 1. The first CEMS accuracy 

test will be a relative accuracy test audit 

(RATA) and must be completed no later 

than 60 days after the respective CEMS 

installation. 

(v) The owner or operator of each 

CEMS must furnish the Regional 

Administrator two, or upon request, 

more copies of a written report of the 

results of each performance evaluation 

and QA/QC check within 60 days of 

completion. 

(vi) The owner or operator of each 

CEMS must check, record, and quantify 

the zero and span calibration drifts at 

least once daily (every 24 hours) in 

accordance with 40 CFR Part 60, 

Appendix F, Procedure 1, Section 4. 

(vii) Except for CEMS breakdowns, 

repairs, calibration checks, and zero and 

span adjustments, all CEMS required by 

this section shall be in continuous 

operation during all periods of process 

operation of the indurating furnaces, 

including periods of process unit 

startup, shutdown, and malfunction. 

(viii) All CEMS required by this 

section must meet the minimum data 

requirements at paragraphs 

(l)(4)(viii)(A)–(C) of this section. 

(A) Complete a minimum of one cycle 

of operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute quadrant of an hour. 

(B) Sample, analyze and record 

emissions data for all periods of process 

operation except as described in 

paragraph (l)(4)(viii)(C) of this section. 

(C) When emission data from CEMS 

are not available due to continuous 

monitoring system breakdowns, repairs, 

calibration checks, or zero and span 

adjustments, emission data must be 

obtained using other monitoring 

systems or emission estimation methods 

approved by the EPA. The other 

monitoring systems or emission 

estimation methods to be used must be 

incorporated into the monitoring plan 

required by this section and provide 

information such that emissions data are 

available for a minimum of 18 hours in 

each 24 hour period and at least 22 out 

of 30 successive unit operating days. 

(ix) Owners or operators of each 

CEMS required by this section must 

reduce all data to 1-hour averages. 

Hourly averages shall be computed 

using all valid data obtained within the 

hour but no less than 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 

systems, and recertification events. 

(x) The 30-day rolling average 

emission rate determined from data 

derived from the CEMS required by this 

section (in lbs/MMBtu or lbs/hr 

depending on the emission standard 

selected) must be calculated in 

accordance with paragraphs (l)(4)(x)(A)– 

(F) of this section. 

(A) Sum the total pounds of the 

pollutant in question emitted from the 

Unit during an operating day and the 

previous twenty-nine operating days. 

(B) Sum the total heat input to the 

unit (in MMBtu) or the total actual 

hours of operation (in hours) during an 


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Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 8735 

operating day and the previous twentynine operating days. 

(C) Divide the total number of pounds 

of the pollutant in question emitted 

during the thirty operating days by the 

total heat input (or actual hours of 

operation depending on the emission 

limit selected) during the thirty 

operating days. 

(D) For purposes of this calculation, 

an operating day is any day during 

which fuel is combusted in the BART 

affected Unit regardless of whether 

pellets are produced. Actual hours of 

operation are the total hours a unit is 

firing fuel regardless of whether a 

complete 24-hour operational cycle 

occurs (i.e. if the furnace is firing fuel 

for only 5 hours during a 24-hour 

period, then the actual operating hours 

for that day are 5. Similarly, total 

number of pounds of the pollutant in 

question for that day is determined only 

from the CEMS data for the five hours 

during which fuel is combusted.) 

(E) If the owner or operator of the 

CEMS required by this section uses an 

alternative method to determine 30-day 

rolling averages, that method must be 

described in detail in the monitoring 

plan required by this section. The 

alternative method will only be 

applicable if the final monitoring plan 

and the alternative method are approved 

by EPA. 

(F) A new 30-day rolling average 

emission rate must be calculated for the 

period ending each new operating day. 

(xi) The 30-day rolling average 

removal efficiency determined from 

data derived from the CEMS required by 

this section must be calculated in 

accordance with paragraphs 

(l)(4)(xi)(A)–(G) of this section. 

(A) Calculate the 30-day rolling 

average emission rate described in 

paragraphs (l)(4)(x)(A)–(F) of this 

section at the inlet of the control device. 

(B) Calculate the 30-day rolling 

average emission rate described in 

paragraphs (l)(4)(x)(A)–(F) of this 

section at the outlet of the control 

device. 

(C) Subtract the 30-day rolling average 

emission rate determined at the outlet of 

the control device from the 30-day 

rolling average emission rate 

determined at the inlet of the control 

device. 

(D) Divide the result of paragraph 

(l)(4)(xi)(C) of this section by the 30-day 

rolling average emission rate 

determined at the inlet. 

(E) Multiply the result of paragraph 

(l)(4)(xi)(D) of this section by 100 to 

determine the 3-day rolling average 

percent removal efficiency. 

(F) If the owner or operator of the 

CEMS required by this section uses an 

alternative method to determine the 30- 

day rolling average removal efficiency, 

that method must be described in detail 

in the monitoring plan required by this 

section. The alternative method will 

only be applicable if the final 

monitoring plan and the alternative 

method are approved by EPA. 

(G) A new 30-day rolling average 

removal efficiency must be calculated 

for each new operating day. 

(xii) Data substitution must not be 

used for purposes of determining 

compliance under this section. 

(xiii) All CEMS data shall be reduced 

and reported in units of the applicable 

standard. 

(xiv) A Quality Control Program must 

be developed and implemented for all 

CEMS required by this section in 

accordance with 40 CFR Part 60, 

Appendix F, Procedure 1, Section 3. 

The program will include, at a 

minimum, written procedures and 

operations for calibration checks, 

calibration drift adjustments, 

preventative maintenance, data 

collection, recording and reporting, 

accuracy audits/procedures, periodic 

performance evaluations, and a 

corrective action program for 

malfunctioning CEMS. 

(m) Recordkeeping requirements. 

(1)(i) Records required by this section 

must be kept in a form suitable and 

readily available for expeditious review. 

(ii) Records required by this section 

must be kept for a minimum of 5 years 

following the date of creation. 

(iii) Records must be kept on site for 

at least 2 years following the date of 

creation and may be kept offsite, but 

readily accessible, for the remaining 3 

years. 

(2) The owner or operator of the 

BART affected unit must maintain the 

records identified in paragraphs 

(m)(2)(i)–(xi) of this section. 

(i) A copy of each notification and 

report developed for and submitted to 

comply with this section including all 

documentation supporting any initial 

notification or notification of 

compliance status submitted, according 

to the requirements of this section. 

(ii) Records of the occurrence and 

duration of each startup, shutdown, and 

malfunction of the BART affected unit, 

air pollution control equipment, and 

CEMS required by this section. 

(iii) Records of activities taken during 

each startup, shutdown, and 

malfunction of the BART affected unit, 

air pollution control equipment, and 

CEMS required by this section. 

(iv) Records of the occurrence and 

duration of all major maintenance 

conducted on the BART affected unit, 

air pollution control equipment, and 

CEMS required by this section. 

(v) Records of each excess emission 

report, including all documentation 

supporting the reports, dates and times 

when excess emissions occurred, 

investigations into the causes of excess 

emissions, actions taken to minimize or 

eliminate the excess emissions, and 

preventative measures to avoid the 

cause of excess emissions from 

occurring again. 

(vi) Records of all CEMS data 

including, as a minimum, the date, 

location, and time of sampling or 

measurement, parameters sampled or 

measured, and results. 

(vii) All records associated with 

quality assurance and quality control 

activities on each CEMS as well as other 

records required by 40 CFR Part 60, 

Appendix F, Procedure 1 including, but 

not limited to, the quality control 

program, audit results, and reports 

submitted as required by this section. 

(viii) Records of the NOX emissions 

during all periods of BART affected unit 

operation, including startup, shutdown 

and malfunction, in the units of the 

standard. The owner or operator shall 

convert the monitored data into the 

appropriate unit of the emission 

limitation using appropriate conversion 

factors and F-factors. F-factors used for 

purposes of this section 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. 

(ix) Records of the SO2 emissions or 

records of the removal efficiency (based 

on CEMS data), depending on the 

emission standard selected, during all 

periods of operation, including periods 

of startup, shutdown and malfunction, 

in the units of the standard. 

(x) Records associated with the CEMS 

unit including type of CEMS, CEMS 

model number, CEMS serial number, 

and initial certification of each CEMS 

conducted in accordance with 40 CFR 

Part 60, Appendix B, Performance 

Specification 2 must be kept for the life 

of the CEMS unit. 

(xi) Records of all periods of fuel oil 

usage as required at paragraph (k)(4) of 

this section. 

(n) Reporting requirements. (1) All 

requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

by this section shall be submitted, 

unless instructed otherwise, to the Air 

and Radiation Division, U.S. 

Environmental Protection Agency, 

Region 5 (A–18J) at 77 West Jackson 

Boulevard, Chicago, Illinois 60604. 


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8736 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

References in this section to the 

Regional Administrator shall mean the 

EPA Regional Administrator for Region 

5. 

(2) The owner or operator of each 

BART affected unit identified in this 

section and CEMS required by this 

section must provide to the Regional 

Administrator the written notifications, 

reports and plans identified at 

paragraphs (n)(2)(i)–(viii) of this section. 

If acceptable to both the Regional 

Administrator and the owner or 

operator of each BART affected unit 

identified in this section and CEMS 

required by this section the owner or 

operator may provide electronic 

notifications, reports and plans. 

(i) A notification of the date 

construction of control devices and 

installation of burners required by this 

section commences postmarked no later 

than 30 days after the commencement 

date. 

(ii) A notification of the date the 

installation of each CEMS required by 

this section commences postmarked no 

later than 30 days after the 

commencement date. 

(iii) A notification of the date the 

construction of control devices and 

installation of burners required by this 

section is complete postmarked no later 

than 30 days after the completion date. 

(iv) A notification of the date the 

installation of each CEMS required by 

this section is complete postmarked no 

later than 30 days after the completion 

date. 

(v) A notification of the date control 

devices and burners installed by this 

section startup postmarked no later than 

30 days after the startup date. 

(vi) A notification of the date CEMS 

required by this section startup 

postmarked no later than 30 days after 

the startup date. 

(vii) A notification of the date upon 

which the initial CEMS performance 

evaluations are planned. This 

notification must be submitted at least 

60 days before the performance 

evaluation is scheduled to begin. 

(viii) A notification of initial 

compliance, signed by the responsible 

official who shall certify its accuracy, 

attesting to whether the source has 

complied with the requirements of this 

section, including, but not limited to, 

applicable emission standards, control 

device and burner installations, CEMS 

installation and certification. This 

notification must be submitted before 

the close of business on the 60th 

calendar day following the completion 

of the compliance demonstration and 

must include, at a minimum, the 

information at paragraphs 

(n)(2)(viii)(A)–(F) of this section. 

(A) The methods used to determine 

compliance. 

(B) The results of any CEMS 

performance evaluations, and other 

monitoring procedures or methods that 

were conducted. 

(C) The methods that will be used for 

determining continuing compliance, 

including a description of monitoring 

and reporting requirements and test 

methods. 

(D) The type and quantity of air 

pollutants emitted by the source, 

reported in units of the standard. 

(E) A description of the air pollution 

control equipment and burners installed 

as required by this section, for each 

emission point. 

(F) A statement by the owner or 

operator as to whether the source has 

complied with the relevant standards 

and other requirements. 

(3) The owner or operator must 

develop and implement a written 

startup, shutdown, and malfunction 

plan for NOX and SO2. The plan must 

include, at a minimum, procedures for 

operating and maintaining the source 

during periods of startup, shutdown, 

and malfunction; and a program of 

corrective action for a malfunctioning 

process and air pollution control and 

monitoring equipment used to comply 

with the relevant standard. The plan 

must ensure that, at all times, the owner 

or operator operates and maintains each 

affected source, including associated air 

pollution control and monitoring 

equipment, in a manner which satisfies 

the general duty to minimize or 

eliminate emissions using good air 

pollution control practices. The plan 

must ensure that owners or operators 

are prepared to correct malfunctions as 

soon as practicable after their 

occurrence. 

(4) The written reports of the results 

of each performance evaluation and QA/ 

QC check in accordance with and as 

required by paragraph (l)(4)(v) of this 

section. 

(5) Compliance Reports. The owner or 

operator of each BART affected unit 

must submit semiannual compliance 

reports. The semiannual compliance 

reports must be submitted in accordance 

with paragraphs (n)(5)(i) through (iv) of 

this section, unless the Regional 

Administrator has approved a different 

schedule. 

(i) The first compliance report must 

cover the period beginning on the 

compliance date that is specified for the 

affected source through 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 no later than 30 calendar 

days after the reporting period covered 

by that report (July 30 or January 30), 

whichever comes first. 

(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 no later than 

30 calendar days after the reporting 

period covered by that report (July 30 or 

January 30). 

(6) Compliance report contents. Each 

compliance report must include the 

information in paragraphs (n)(6)(i) 

through (vi) 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) Identification of the process unit, 

control devices, and CEMS covered by 

the compliance report. 

(v) A record of each period of a 

startup, shutdown, or malfunction 

during the reporting period and a 

description of the actions the owner or 

operator took to minimize or eliminate 

emissions arising as a result of the 

startup, shutdown or malfunction and 

whether those actions were or were not 

consistent with the source’s startup, 

shutdown, and malfunction plan. 

(vi) A statement identifying whether 

there were or were not any deviations 

from the requirements of this section 

during the reporting period. If there 

were deviations from the requirements 

of this section during the reporting 

period, then the compliance report must 

describe in detail the deviations which 

occurred, the causes of the deviations, 

actions taken to address the deviations, 

and procedures put in place to avoid 

such deviations in the future. If there 

were no deviations from the 

requirements of this section during the 

reporting period, then the compliance 

report must include a statement that 

there were no deviations. For purposes 

of this section, deviations include, but 

are not limited to, emissions in excess 

of applicable emission standards 

established by this section, failure to 

continuously operate an air pollution 

control device in accordance with 

operating requirements designed to 

assure compliance with emission 

standards, failure to continuously 

operate CEMS required by this section, 

and failure to maintain records or 

submit reports required by this section. 


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Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 8737 

(7) Each owner or operator of a CEMS 

required by this section must submit 

quarterly excess emissions and 

monitoring system performance reports 

to the Regional Administrator for each 

pollutant monitored for each BART 

affected unit monitored. All reports 

must be postmarked by the 30th day 

following the end of each three-month 

period of a calendar year (January– 

March, April–June, July–September, 

October–December) and must include, 

at a minimum, the requirements at 

paragraphs (n)(7)(i)–(xv). 

(i) Company name and address. 

(ii) Identification and description of 

the process unit being monitored. 

(iii) The dates covered by the 

reporting period. 

(iv) Total source operating hours for 

the reporting period. 

(v) Monitor manufacturer, monitor 

model number and monitor serial 

number. 

(vi) Pollutant monitored. 

(vii) Emission limitation for the 

monitored pollutant. 

(viii) Date of latest CEMS certification 

or audit. 

(ix) A description of any changes in 

continuous monitoring systems, 

processes, or controls since the last 

reporting period. 

(x) A table summarizing the total 

duration of excess emissions, as defined 

at paragraphs (n)(7)(x)(A)–(B) of this 

section, for the reporting period broken 

down by the cause of those excess 

emissions (startup/shutdown, control 

equipment problems, process problems, 

other known causes, unknown causes), 

and the total percent of excess 

emissions (for all causes) for the 

reporting period calculated as described 

at paragraph (n)(7)(x)(C) of this section. 

(A) For purposes of this section, an 

excess emission is defined as any 30- 

day rolling average period, including 

periods of startup, shutdown and 

malfunction, during which the 30-day 

rolling average emissions of either 

regulated pollutant (SO2 and NOX), as 

measured by a CEMS, exceeds the 

applicable emission standards in this 

section. 

(B) For purposes of this section, if a 

facility calculates a 30-day rolling 

average emission rate in accordance 

with this section which exceeds the 

applicable emission standards of this 

section, then it will be considered 30 

days of excess emissions. If the 

following 30-day rolling average 

emission rate is calculated and found to 

exceed the applicable emission 

standards of this section as well, then it 

will add one more day to the total days 

of excess emissions (i.e. 31 days). 

Similarly, if an excess emission is 

calculated for a 30-day rolling average 

period and no additional excess 

emissions are calculated until 15 days 

after the first, then that new excess 

emission will add 15 days to the total 

days of excess emissions (i.e. 30 + 15 = 

45). For purposes of this section, if an 

excess emission is calculated for any 

period of time within a reporting period, 

there will be no fewer than 30 days of 

excess emissions but there should be no 

more than 121 days of excess emissions 

for a reporting period. 

(C) For purposes of this section, the 

total percent of excess emissions will be 

determined by summing all periods of 

excess emissions (in days) for the 

reporting period, dividing that number 

by the total BART affected unit 

operating days for the reporting period, 

and then multiplying by 100 to get the 

total percent of excess emissions for the 

reporting period. An operating day, as 

defined previously, is any day during 

which fuel is fired in the BART affected 

unit for any period of time. Because of 

the possible overlap of 30-day rolling 

average excess emissions across 

quarters, there are some situations 

where the total percent of excess 

emissions could exceed 100 percent. 

This extreme situation would only 

result from serious excess emissions 

problems where excess emissions occur 

for nearly every day during a reporting 

period. 

(xi) A table summarizing the total 

duration of monitor downtime, as 

defined at paragraph (n)(7)(xi)(A) of this 

section, for the reporting period broken 

down by the cause of the monitor 

downtime (monitor equipment 

malfunctions, non-monitor equipment 

malfunctions, quality assurance 

calibration, other known causes, 

unknown causes), and the total percent 

of monitor downtime (for all causes) for 

the reporting period calculated as 

described at paragraph (n)(7)(xi)(B) of 

this section. 

(A) For purposes of this section, 

monitor downtime is defined as any 

period of time (in hours) during which 

the required monitoring system was not 

measuring emissions from the BART 

affected unit. This includes any period 

of CEMS QA/QC, daily zero and span 

checks, and similar activities. 

(B) For purposes of this section, the 

total percent of monitor downtime will 

be determined by summing all periods 

of monitor downtime (in hours) for the 

reporting period, dividing that number 

by the total number of BART affected 

unit operating hours for the reporting 

period, and then multiplying by 100 to 

get the total percent of excess emissions 

for the reporting period. 

(xii) A table which identifies each 

period of excess emissions for the 

reporting period and includes, at a 

minimum, the information in 

paragraphs (n)(7)(xii)(A)–(F) of this 

section. 

(A) The date of each excess emission. 

(B) The beginning and end time of 

each excess emission. 

(C) The pollutant for which an excess 

emission occurred. 

(D) The magnitude of the excess 

emission. 

(E) The cause of the excess emission. 

(F) The corrective action taken or 

preventative measures adopted to 

minimize or eliminate the excess 

emissions and prevent such excess 

emission from occurring again. 

(xiii) A table which identifies each 

period of monitor downtime for the 

reporting period and includes, at a 

minimum, the information in 

paragraphs (n)(7)(xiii)(A)–(D) of this 

section. 

(A) The date of each period of monitor 

downtime. 

(B) The beginning and end time of 

each period of monitor downtime. 

(C) The cause of the period of monitor 

downtime. 

(D) The corrective action taken or 

preventative measures adopted for 

system repairs or adjustments to 

minimize or eliminate monitor 

downtime and prevent such downtime 

from occurring again. 

(xiv) If there were no periods of 

excess emissions during the reporting 

period, then the excess emission report 

must include a statement which says 

there were no periods of excess 

emissions during this reporting period. 

(xv) If there were no periods of 

monitor downtime, except for daily zero 

and span checks, during the reporting 

period, then the excess emission report 

must include a statement which says 

there were no periods of monitor 

downtime during this reporting period 

except for the daily zero and span 

checks. 

(8) The owner or operator of each 

CEMS required by this section must 

develop and submit for review and 

approval by the Regional Administrator 

a site specific monitoring plan. The 

purpose of this monitoring plan is to 

establish procedures and practices 

which will be implemented by the 

owner or operator in its effort to comply 

with the monitoring, recordkeeping and 

reporting requirements of this section. 

The monitoring plan must include, at a 

minimum, the information at 

paragraphs (n)(8)(i)–(x) of this section. 

(i) Site specific information including 

the company name, address, and contact 

information. 


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8738 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

(ii) The objectives of the monitoring 

program implemented and information 

describing how those objectives will be 

met. 

(iii) Information on any emission 

factors used in conjunction with the 

CEMS required by this section to 

calculate emission rates and a 

description of how those emission 

factors were determined. 

(iv) A description of methods to be 

used to calculate emission rates when 

CEMS data is not available due to 

downtime associated with QA/QC 

events. 

(v) A description of the QA/QC 

program to be implemented by the 

owner or operator of CEMS required by 

this section. This can be the QA/QC 

program developed in accordance with 

40 CFR Part 60, Appendix F, Procedure 

1, Section 3. 

(vi) A list of spare parts for CEMS 

maintained on site for system 

maintenance and repairs. 

(vii) A description of the procedures 

to be used to calculate 30-day rolling 

averages and an example calculation 

which shows the algorithms used by the 

CEMS to calculate 30-day rolling 

averages. 

(viii) A sample of the document to be 

used for the quarterly excess emission 

reports required by this section. 

(ix) A description of the procedures to 

be implemented to investigate root 

causes of excess emissions and monitor 

downtime and the proposed corrective 

actions to address potential root causes 

of excess emissions and monitor 

downtime. 

(x) A description of the sampling and 

calculation methodology for 

determining the percent sulfur by 

weight as a monthly block average for 

coal used during that month. 

Subpart Y—Minnesota 

■ 3. Section 52.1235 is added to read as 

follows: 

§ 52.1235 Regional haze. 

(a) [Reserved] 

(b)(1) NOX emission limits. (i) United 

States Steel Corporation, Keetac: An 

emission limit of 1.5 lbs NOX/MMBtu, 

based on a 30-day rolling average, shall 

apply to the Grate Kiln pelletizing 

furnace (EU030), beginning 3 years from 

March 8, 2013. However, for any 30, or 

more, consecutive days when only 

natural gas is used a limit of 1.2 lbs 

NOX/MMBtu, based on a 30-day rolling 

average, shall apply. 

(ii) Hibbing Taconite Company: An 

emission limit of 1.5 lbs NOX/MMBtu, 

based on a 30-day rolling average, shall 

apply to the Line 1 pelletizing furnace 

(EU020) beginning 26 months from 

March 8, 2013. An emission limit of 1.5 

lbs NOX/MMBtu, based on a 30-day 

rolling average, shall apply to the Line 

2 pelletizing furnace (EU021) beginning 

38 months from March 8, 2013. An 

emission limit of 1.5 lbs NOX/MMBtu, 

based on a 30-day rolling average, shall 

apply to the Line 3 pelletizing furnace 

(EU022) beginning 50 months from 

March 8, 2013. However, for any 30, or 

more, consecutive days when only 

natural gas is used at any Hibbing 

Taconite pelletizing furnace, a limit of 

1.2 lbs NOX/MMBtu, based on a 30-day 

rolling average, shall apply to that 

furnace. 

(iii) United States Steel Corporation, 

Minntac: An emission limit of 1.5 lbs 

NOX/MMBtu, 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 limit beginning 12 months 

from March 8, 2013 for the Line 6 

indurating furnace (EU315); 24 months 

from March 8, 2013 for the Line 7 

indurating furnace (EU334); 36 months 

from March 8, 2013 for the Line 4 or 

Line 5 indurating furnace (EU261) or 

(EU282); 48 months from March 8, 2013 

for the Line 5 or Line 4 indurating 

furnace (EU282) or (EU261); and 59 

months from March 8, 2013 for the Line 

3 indurating furnace (EU225). However, 

for any 30 or more consecutive days 

when only natural gas is used at any of 

Minntac’s indurating furnaces, a limit of 

1.2 lbs NOX/MMBtu, based on a 30-day 

rolling average, shall apply to that 

furnace. 

(iv) United Taconite: An emission 

limit of 1.5 lbs NOX/MMBtu, based on 

a 30-day rolling average, shall apply to 

the Line 1 pellet furnace (EU040) 

beginning 38 months from March 8, 

2013. An emission limit of 1.5 lbs NOX/ 

MMBtu, based on a 30-day rolling 

average, shall apply to the Line 2 pellet 

furnace (EU042) beginning 26 months 

from March 8, 2013. However, for any 

30, or more, consecutive days when 

only natural gas is used at either of 

United Taconites’ Line 1 or Line 2 pellet 

furnaces, a limit of 1.2 lbs NOX/MMBtu, 

based on a 30-day rolling average, shall 

apply to that furnace. 

(v) ArcelorMittal Minorca Mine: An 

emission limit of 1.5 lbs NOX/MMBtu, 

based on a 30-day rolling average, shall 

apply to the indurating furnace (EU026) 

beginning 26 months from March 8, 

2013. However, for any 30, or more, 

consecutive days when only natural gas 

is used, a limit of 1.2 lbs NOX/MMBtu, 

based on a 30-day rolling average, shall 

apply. 

(vi) Northshore Mining CompanySilver Bay: An emission limit of 1.5 lbs 

NOX/MMBtu, based on a 30-day rolling 

average, shall apply to Furnace 11 

(EU100/EU104) beginning 26 months 

from March 8, 2013. An emission limit 

of 1.5 lbs NOX/MMBtu, based on a 30- 

day rolling average, shall apply to 

Furnace 12 (EU110/114) beginning 38 

months from March 8, 2013. However, 

for any 30, or more, consecutive days 

when only natural gas is used at either 

Northshore Mining Furnace 11 or 

Furnace 12, a limit of 1.2 lbs NOX/ 

MMBtu, based on a 30-day rolling 

average, shall apply. An emission limit 

of 0.085 lbs/MMBtu, based on a 30-day 

rolling average, shall apply to Process 

Boiler #1 (EU003) and Process Boiler #2 

(EU004) beginning 5 years from March 

8, 2013. The 0.085 lbs/MMBtu 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 lbs SO2/hr, based 

on a 30-day rolling average, shall apply 

to the Grate Kiln pelletizing furnace 

(EU030). Any coal burned at Keetac 

shall have a sulfur content of 0.60 

percent sulfur by weight or less based 

on a monthly block average. The 

sampling and calculation methodology 

for determining the sulfur content of 

fuel must be described in the 

monitoring plan required at paragraph 

(e)(8)(x) of this section. Compliance 

with these requirements for EU030 is 

required beginning 3 months from 

March 8, 2013. 

(ii) Hibbing Taconite Company: An 

aggregate emission limit of 247.8 lbs 

SO2/hr shall apply to the three affected 

lines, EU020, EU021, and EU022. The 

SO2 emission limits for these three 

pelletizing furnaces are based on a 30- 

day rolling average. Emissions resulting 

from the combustion of fuel oil are not 

included in the calculation of the 30- 

day rolling average. However, if any fuel 

oil is burned after the first day that SO2

CEMS are required to be operational, 

then the information specified in 

(b)(2)(vii) must be submitted, for each 

calendar year, to the Regional 

Administrator no later than 30 days 

after the end of each calendar year so 

that a limit can be set. Compliance with 

the emission limits is required 

beginning 6 months from March 8, 2013. 

Within 20 months of March 8, 2013, the 

owner or operator may calculate a 

revised SO2 limit based on one year of 

hourly CEMS emissions data reported in 

lbs SO2/hr and submit such limit, 

calculations and CEMS data to EPA. 

This limit shall be set in terms of lbs 


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Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 8739 

SO2/hr, based on the following 

equations, with compliance to be 

determined on a 30-day rolling average. 

m=(n+1)*a 

m = the rank of the ordered data point, when 

data is sorted smallest to largest 

n=a number of data points 

a = 0.95, to reflect the 95th percentile 

If m is a whole number, then the limit, 

UPL, shall be computed as: 

UPL = Xm, 

Where: 

X=m value of the mth data point in terms of 

lbs SO2/hr, when the data is sorted 

smallest to largest. 

If m is not a whole number, the limit 

shall be computed by linear 

interpolation according to the following 

equation. 

Where: 

m=i the integer portion of m, i.e., m 

truncated at zero decimal places, and 

m=d the decimal portion of m 

(iii) United States Steel Corporation, 

Minntac: An aggregate emission limit 

for indurating furnace Lines 3–7 

(EU225, EU261, EU282, EU315, and 

EU334) of 498 lbs SO2/hr shall apply 

when all lines are producing flux 

pellets. An aggregate emission limit of 

630 lbs SO2/hr shall apply to Lines 3– 

7 when Line 3–5 are producing acid 

pellets and Lines 6 and 7 are producing 

flux pellets. An aggregate emission limit 

of 800 lbs SO2/hr shall apply to Lines 

3–7 when all lines are producing acid 

pellets. The SO2 emission limits are 

based on a 30-day rolling average and 

apply beginning 3 months from March 

8, 2013. The emission limit for a given 

30-day rolling average period is 

calculated using a weighted average as 

follows: 

Where: 

L30 = the limit for a given 30 day averaging 

period 

nf = the number of days in the 30 day period 

that the facility is producing flux pellets 

on lines 3–7 

naf = the number of days in the 30 day period 

that the facility is producing acid pellets 

on lines 3–5 and flux pellets on lines 6 

and 7 

na = the number of days in the 30 day period 

that the facility is producing acid pellets 

on lines 3–7 

Also, beginning 3 months from March 

8, 2013, any coal burned at Minntac’s 

Lines 3–7 shall have a sulfur content of 

0.60 percent sulfur by weight or less 

based on a monthly block average. The 

sampling and calculation methodology 

for determining the sulfur content of 

fuel must be described in the 

monitoring plan required at paragraph 

(e)(8)(x) of this section. 

(iv) United Taconite: An aggregate 

emission limit of 529.0 lbs SO2/hr, 

based on a 30-day rolling average, shall 

apply to the Line 1 pellet furnace 

(EU040) and Line 2 pellet furnace 

(EU042) beginning 54 months from 

March 8, 2013. Also, beginning 54 

months from March 8, 2013, any coal 

burned in the Line 1 or Line 2 pellet 

furnace shall have a sulfur content of 

0.60 percent sulfur by weight or less 

based on a monthly block average. The 

sampling and calculation methodology 

for determining the sulfur content of 

fuel must be described in the 

monitoring plan required at paragraph 

(e)(8)(x) of this section. 

(v) ArcelorMittal Minorca Mine: An 

emission limit of 38.16 lbs SO2/hr, 

based on a 30-day rolling average, shall 

apply to the indurating furnace (EU026) 

beginning 6 months from March 8, 2013. 

This limit shall not apply when the unit 

is combusting fuel oil. However, if any 

fuel oil is burned after the first day that 

SO2 CEMS are required to be 

operational, then the information 

specified in paragraph (b)(2)(vii) of this 

section must be submitted, for each 

calendar year, to the Regional 

Administrator no later than 30 days 

after the end of each calendar year so 

that a limit can be set. Within 20 

months of March 8, 2013, the owner or 

operator may calculate a revised SO2

limit based on one year of hourly CEMS 

emissions data reported in lbs SO2/hr 

and submit such limit, calculations, and 

CEMS data to EPA. This limit shall be 

set in terms of lbs SO2/hr, based on the 

following equations, with compliance to 

be determined on a 30-day rolling 

average. 

m = (n + 1) * a 

m = the rank of the ordered data point, when 

data is sorted smallest to largest 

n = number of data points 

a = 0.95, to reflect the 95th percentile 

If m is a whole number, then the limit, 

UPL, shall be computed as: 

UPL = Xm, 

Where: 

xm = value of the mth data point in terms of 

lbs SO2/hr, when the data is sorted 

smallest to largest 

If m is not a whole number, the limit 

shall be computed by linear 

interpolation according to the following 

equation. 

Where: 

mi = the integer portion of m, i.e., m 

truncated at zero decimal places, and 

mα = the decimal portion of m 

(vi) Northshore Mining Company— 

Silver Bay: An aggregate emission limit 

of 39.0 lbs SO2/hr, based on a 30-day 

rolling average, shall apply to Furnace 

11 (EU100/EU104) and Furnace 12 

(EU110/EU114). Compliance with this 

limit is required within 6 months. 

Emissions resulting from the 

combustion of fuel oil are not included 

in the calculation of the 30-day rolling 

average. However, if any fuel oil is 

burned after the first day that SO2 CEMS 

are required to be operational, then the 

information specified in paragraph 

(b)(2)(vii) of this section must be 

submitted, for each calendar year, to the 

Regional Administrator no later than 30 

days after the end of each calendar year 

so that a limit can be set. Within 20 

months of March 8, 2013, the owner or 

operator must calculate a revised SO2

limit based on one year of hourly CEMS 

emissions data reported in lbs SO2/hr 

and submit such limit, calculations and 

CEMS data to EPA. This limit shall be 

set in terms of lbs SO2/hr, based on the 

following equations, with compliance to 

be determined on a 30-day rolling 

average. 

m = (n + 1) * a 

m = the rank of the ordered data point, when 

data is sorted smallest to largest 

n = number of data points 

a = 0.95, to reflect the 95th percentile 

If m is a whole number, then the limit, 

UPL, shall be computed as: 

UPL = Xm, 

Where: 


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xm = value of the mth data point in terms of 

lbs SO2/hr, when the data is sorted 

smallest to largest 

If m is not a whole number, the limit 

shall be computed by linear 

interpolation according to the following 

equation. 

Where: 

mi = the integer portion of m, i.e., m 

truncated at zero decimal places, and 

ma = the decimal portion of m 

(vii) Starting with the first day that 

SO2 CEMS are required to be 

operational, for the facilities listed in 

paragraphs (b)(2)(i)–(b)(2)(vi) of this 

section, records shall be kept for any 

day during which fuel oil is burned 

(either alone or blended with other 

fuels) in one or more of a facility’s 

indurating furnaces. These records must 

include, at a minimum, the gallons of 

fuel oil burned per hour, the sulfur 

content of the fuel oil, and the SO2

emissions in pounds per hour. If any 

fuel oil is burned after the first day that 

SO2 CEMS are required to be 

operational, then the records must be 

submitted, for each calendar year, to the 

Regional Administrator no later than 30 

days after the end of each calendar year. 

(c) Testing and monitoring. (1) 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). Compliance with the emission 

limits for NOX shall be determined 

using data from the CEMS. 

(2) The owner or operator shall 

install, certify, calibrate, maintain and 

operate 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). 

(3) 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 the BART 

affected units to allow conversion of the 

NOX and SO2 concentrations to units of 

the standard (lbs/MMBtu and lbs/hr, 

respectively) unless a demonstration is 

made that a diluent monitor and 

continuous flow rate monitor are not 

needed for the owner or operator to 

demonstrate compliance with 

applicable emission limits in units of 

the standards. 

(4) For purposes of this section, all 

CEMS required by this section must 

meet the requirements of paragraphs 

(c)(4)(i)–(xiv) of this section. 

(i) All CEMS must be installed, 

certified, calibrated, maintained, and 

operated in accordance with 40 CFR 

Part 60, Appendix B, Performance 

Specification 2 (PS–2) and Appendix F, 

Procedure 1. 

(ii) All CEMS associated with 

monitoring NOX (including the NOX

monitor and necessary diluent and flow 

rate monitors) must be installed and 

operational no later than the unit 

specific compliance dates for the 

emission limits identified at paragraphs 

(b)(1)(i)–(vi) of this section. All CEMS 

associated with monitoring SO2 (except 

the CEMS associated with monitoring 

SO2 at United Taconite Line 1 and Line 

2 pellet furnaces) must be installed and 

operational no later than six months 

after March 8, 2013. All CEMs 

associated with monitoring SO2 at 

United Taconite Line 1 and Line 2 pellet 

furnaces must be installed and 

operational no later than 54 months 

from March 8, 2013. Verification of the 

CEMS operational status shall, as a 

minimum, include completion of the 

manufacturer’s written requirements or 

recommendations for installation, 

operation, and calibration of the 

devices. 

(iii) The owner or operator must 

conduct a performance evaluation of 

each CEMS in accordance with 40 CFR 

Part 60, Appendix B, PS–2. The 

performance evaluations must be 

completed no later than 60 days after 

the respective CEMS installation. 

(iv) The owner or operator of each 

CEMS must conduct periodic Quality 

Assurance, Quality Control (QA/QC) 

checks of each CEMS in accordance 

with 40 CFR Part 60, Appendix F, 

Procedure 1. The first CEMS accuracy 

test will be a relative accuracy test audit 

(RATA) and must be completed no later 

than 60 days after the respective CEMS 

installation. 

(v) The owner or operator of each 

CEMS must furnish the Regional 

Administrator two, or upon request, 

more copies of a written report of the 

results of each performance evaluation 

and QA/QC check within 60 days of 

completion. 

(vi) The owner or operator of each 

CEMS must check, record, and quantify 

the zero and span calibration drifts at 

least once daily (every 24 hours) in 

accordance with 40 CFR Part 60, 

Appendix F, Procedure 1, Section 4. 

(vii) Except for CEMS breakdowns, 

repairs, calibration checks, and zero and 

span adjustments, all CEMS required by 

this section shall be in continuous 

operation during all periods of BART 

affected process unit operation, 

including periods of process unit 

startup, shutdown, and malfunction. 

(viii) All CEMS required by this 

section must meet the minimum data 

requirements at paragraphs 

(c)(4)(viii)(A)–(C) of this section. 

(A) Complete a minimum of one cycle 

of operation (sampling, analyzing, and 

data recording) for each successive 15- 

minute quadrant of an hour. 

(B) Sample, analyze and record 

emissions data for all periods of process 

operation except as described in 

paragraph (c)(4)(viii)(C) of this section. 

(C) When emission data from CEMS 

are not available due to continuous 

monitoring system breakdowns, repairs, 

calibration checks, or zero and span 

adjustments, emission data must be 

obtained using other monitoring 

systems or emission estimation methods 

approved by the EPA. The other 

monitoring systems or emission 

estimation methods to be used must be 

incorporated into the monitoring plan 

required by this section and provide 

information such that emissions data are 

available for a minimum of 18 hours in 

each 24 hour period and at least 22 out 

of 30 successive unit operating days. 

(ix) Owners or operators of each 

CEMS required by this section must 

reduce all data to 1-hour averages. 

Hourly averages shall be computed 

using all valid data obtained within the 

hour but no less than 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 


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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 

systems, and recertification events. 

(x) The 30-day rolling average 

emission rate determined from data 

derived from the CEMS required by this 

section (in lbs/MMBtu or lbs/hr 

depending on the emission standard 

selected) must be calculated in 

accordance with paragraphs 

(c)(4)(x)(A)–(F) of this section. 

(A) Sum the total pounds of the 

pollutant in question emitted from the 

Unit during an operating day and the 

previous twenty-nine operating days. 

(B) Sum the total heat input to the 

unit (in MMBtu) or the total actual 

hours of operation (in hours) during an 

operating day and the previous twentynine operating days. 

(C) Divide the total number of pounds 

of the pollutant in question emitted 

during the thirty operating days by the 

total heat input (or actual hours of 

operation depending on the emission 

limit selected) during the thirty 

operating days. 

(D) For purposes of this calculation, 

an operating day is any day during 

which fuel is combusted in the BART 

affected Unit regardless of whether 

pellets are produced. Actual hours of 

operation are the total hours a unit is 

firing fuel regardless of whether a 

complete 24-hour operational cycle 

occurs (i.e. if the furnace is firing fuel 

for only 5 hours during a 24-hour 

period, then the actual operating hours 

for that day are 5. Similarly, total 

number of pounds of the pollutant in 

question for that day is determined only 

from the CEMS data for the five hours 

during which fuel is combusted.) 

(E) If the owner or operator of the 

CEMS required by this section uses an 

alternative method to determine 30-day 

rolling averages, that method must be 

described in detail in the monitoring 

plan required by this section. The 

alternative method will only be 

applicable if the final monitoring plan 

and the alternative method are approved 

by EPA. 

(F) A new 30-day rolling average 

emission rate must be calculated for 

each new operating day. 

(xi) The 30-day rolling average 

removal efficiency determined from 

data derived from the CEMS required by 

this section must be calculated in 

accordance with paragraphs 

(c)(4)(xi)(A)–(G) of this section. 

(A) Calculate the 30-day rolling 

average emission rate described in 

paragraphs (c)(4)(x)(A)–(F) of this 

section at the inlet of the control device. 

(B) Calculate the 30-day rolling 

average emission rate described in 

paragraphs (c)(4)(x)(A)–(F) of this 

section at the outlet of the control 

device. 

(C) Subtract the 30-day rolling average 

emission rate determined at the outlet of 

the control device from the 30-day 

rolling average emission rate 

determined at the inlet of the control 

device. 

(D) Divide the result of paragraph 

(c)(4)(xi)(C) of this section by the 30-day 

rolling average emission rate 

determined at the inlet. 

(E) Multiply the result of paragraph 

(c)(4)(xi)(D) of this section by 100 to 

determine the 30-day rolling average 

removal efficiency. 

(F) If the owner or operator of the 

CEMS required by this section uses an 

alternative method to determine the 30- 

day rolling average removal efficiency, 

that method must be described in detail 

in the monitoring plan required by this 

section. The alternative method will 

only be applicable if the final 

monitoring plan and the alternative 

method are approved by EPA. 

(G) A new 30-day rolling average 

removal efficiency must be calculated 

for each new operating day. 

(xii) Data substitution must not be 

used for purposes of determining 

compliance under this section. 

(xiii) All CEMS data shall be reduced 

and reported in units of the applicable 

standard. 

(xiv) A Quality Control Program must 

be developed and implemented for all 

CEMS required by this section in 

accordance with 40 CFR Part 60, 

Appendix F, Procedure 1, Section 3. 

The program will include, at a 

minimum, written procedures and 

operations for calibration checks, 

calibration drift adjustments, 

preventative maintenance, data 

collection, recording and reporting, 

accuracy audits/procedures, periodic 

performance evaluations, and a 

corrective action program for 

malfunctioning CEMS. 

(5) No later than the compliance date 

of this section, 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 section. 

The pH evaluation shall be performed in 

accordance with the requirements of 40 

CFR 136.3 using EPA Method 150.2. 

(d) Recordkeeping requirements. (1)(i) 

Records required by this section must be 

kept in a form suitable and readily 

available for expeditious review. 

(ii) Records required by this section 

must be kept for a minimum of 5 years 

following the date of creation. 

(iii) Records must be kept on site for 

at least 2 years following the date of 

creation and may be kept offsite, but 

readily accessible, for the remaining 3 

years. 

(2) The owner or operator of the 

BART affected units must maintain the 

records at paragraphs (d)(2)(i)–(xi) of 

this section. 

(i) A copy of each notification and 

report developed for and submitted to 

comply with this section including all 

documentation supporting any initial 

notification or notification of 

compliance status submitted according 

to the requirements of this section. 

(ii) Records of the occurrence and 

duration of startup, shutdown, and 

malfunction of the BART affected units, 

air pollution control equipment, and 

CEMS required by this section. 

(iii) Records of activities taken during 

each startup, shutdown, and 

malfunction of the BART affected unit, 

air pollution control equipment, and 

CEMS required by this section. 

(iv) Records of the occurrence and 

duration of all major maintenance 

conducted on the BART affected units, 

air pollution control equipment, and 

CEMS required by this section. 

(v) Records of each excess emission 

report, including all documentation 

supporting the reports, dates and times 

when excess emissions occurred, 

investigations into the causes of excess 

emissions, actions taken to minimize or 

eliminate the excess emissions, and 

preventative measures to avoid the 

cause of excess emissions from 

occurring again. 

(vi) Records of all CEMS data 

including, as a minimum, the date, 

location, and time of sampling or 

measurement, parameters sampled or 

measured, and results. 

(vii) All records associated with 

quality assurance and quality control 

activities on each CEMS as well as other 

records required by 40 CFR Part 60, 

Appendix F, Procedure 1 including, but 

not limited to, the quality control 

program, audit results, and reports 

submitted as required by this section. 

(viii) Records of the NOX emissions 

during all periods of BART affected unit 

operation, including startup, shutdown 

and malfunction in the units of the 

standard. The owner or operator shall 

convert the monitored data into the 

appropriate unit of the emission 

limitation using appropriate conversion 

factors and F-factors. F-factors used for 

purposes of this section shall be 

documented in the monitoring plan and 

developed in accordance with 40 CFR 


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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. 

(ix) Records of the SO2 emissions or 

records of the removal efficiency (based 

on CEMS data), depending on the 

emission standard selected, during all 

periods of operation, including periods 

of startup, shutdown and malfunction, 

in the units of the standard. 

(x) Records associated with the CEMS 

unit including type of CEMS, CEMS 

model number, CEMS serial number, 

and initial certification of each CEMS 

conducted in accordance with 40 CFR 

Part 60, Appendix B, Performance 

Specification 2 must be kept for the life 

of the CEMS unit. 

(xi) Records of all periods of fuel oil 

usage as required at paragraph (b)(2)(vi) 

of this section. 

(e) Reporting requirements. (1) All 

requests, reports, submittals, 

notifications, and other communications 

to the Regional Administrator required 

by this section shall be submitted, 

unless instructed otherwise, to the Air 

and Radiation Division, U.S. 

Environmental Protection Agency, 

Region 5 (A–18J), at 77 West Jackson 

Boulevard, Chicago, Illinois 60604. 

(2) The owner or operator of each 

BART affected unit identified in this 

section and CEMS required by this 

section must provide to the Regional 

Administrator the written notifications, 

reports and plans identified at 

paragraphs (e)(2)(i)–(viii) of this section. 

If acceptable to both the Regional 

Administrator and the owner or 

operator of each BART affected unit 

identified in this section and CEMS 

required by this section the owner or 

operator may provide electronic 

notifications, reports and plans. 

(i) A notification of the date 

construction of control devices and 

installation of burners required by this 

section commences postmarked no later 

than 30 days after the commencement 

date. 

(ii) A notification of the date the 

installation of each CEMS required by 

this section commences postmarked no 

later than 30 days after the 

commencement date. 

(iii) A notification of the date the 

construction of control devices and 

installation of burners required by this 

section is complete postmarked no later 

than 30 days after the completion date. 

(iv) A notification of the date the 

installation of each CEMS required by 

this section is complete postmarked no 

later than 30 days after the completion 

date. 

(v) A notification of the date control 

devices and burners installed by this 

section startup postmarked no later than 

30 days after the startup date. 

(vi) A notification of the date CEMS 

required by this section startup 

postmarked no later than 30 days after 

the startup date. 

(vii) A notification of the date upon 

which the initial CEMS performance 

evaluations are planned. This 

notification must be submitted at least 

60 days before the performance 

evaluation is scheduled to begin. 

(viii) A notification of initial 

compliance, signed by the responsible 

official who shall certify its accuracy, 

attesting to whether the source has 

complied with the requirements of this 

section, including, but not limited to, 

applicable emission standards, control 

device and burner installations, CEMS 

installation and certification. This 

notification must be submitted before 

the close of business on the 60th 

calendar day following the completion 

of the compliance demonstration and 

must include, at a minimum, the 

information at paragraphs 

(e)(2)(viii)(A)–(F) of this section. 

(A) The methods used to determine 

compliance. 

(B) The results of any CEMS 

performance evaluations, and other 

monitoring procedures or methods that 

were conducted. 

(C) The methods that will be used for 

determining continuing compliance, 

including a description of monitoring 

and reporting requirements and test 

methods. 

(D) The type and quantity of air 

pollutants emitted by the source, 

reported in units of the standard. 

(E) A description of the air pollution 

control equipment and burners installed 

as required by this section, for each 

emission point. 

(F) A statement by the owner or 

operator as to whether the source has 

complied with the relevant standards 

and other requirements. 

(3) The owner or operator must 

develop and implement a written 

startup, shutdown, and malfunction 

plan for NOX and SO2. The plan must 

include, at a minimum, procedures for 

operating and maintaining the source 

during periods of startup, shutdown, 

and malfunction; and a program of 

corrective action for a malfunctioning 

process and air pollution control and 

monitoring equipment used to comply 

with the relevant standard. The plan 

must ensure that, at all times, the owner 

or operator operates and maintains each 

affected source, including associated air 

pollution control and monitoring 

equipment, in a manner which satisfies 

the general duty to minimize or 

eliminate emissions using good air 

pollution control practices. The plan 

must ensure that owners or operators 

are prepared to correct malfunctions as 

soon as practicable after their 

occurrence. 

(4) The written reports of the results 

of each performance evaluation and QA/ 

QC check in accordance with and as 

required by paragraph (c)(4)(v) of this 

section. 

(5) Compliance reports. The owner or 

operator of each BART affected unit 

must submit semiannual compliance 

reports. The semiannual compliance 

reports must be submitted in accordance 

with paragraphs (e)(5)(i) through (iv) of 

this section, unless the Administrator 

has approved a different schedule. 

(i) The first compliance report must 

cover the period beginning on the 

compliance date that is specified for the 

affected source through 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 no later than 30 calendar 

days after the reporting period covered 

by that report (July 30 or January 30), 

whichever comes first. 

(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 no later than 

30 calendar days after the reporting 

period covered by that report (July 30 or 

January 30). 

(6) Compliance report contents. Each 

compliance report must include the 

information in paragraphs (e)(6)(i) 

through (vi) 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) Identification of the process unit, 

control devices, and CEMS covered by 

the compliance report. 

(v) A record of each period of startup, 

shutdown, or malfunction during the 

reporting period and a description of the 

actions the owner or operator took to 

minimize or eliminate emissions arising 

as a result of the startup, shutdown, or 

malfunction and whether those actions 

were or were not consistent with the 

source’s startup, shutdown, and 

malfunction plan. 

(vi) A statement identifying whether 

there were or were not any deviations 

from the requirements of this section 


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during the reporting period. If there 

were deviations from the requirements 

of this section during the reporting 

period, then the compliance report must 

describe in detail the deviations which 

occurred, the causes of the deviations, 

actions taken to address the deviations, 

and procedures put in place to avoid 

such deviations in the future. If there 

were no deviations from the 

requirements of this section during the 

reporting period, then the compliance 

report must include a statement that 

there were no deviations. For purposes 

of this section, deviations include, but 

are not limited to, emissions in excess 

of applicable emission standards 

established by this section, failure to 

continuously operate an air pollution 

control device in accordance with 

operating requirements designed to 

assure compliance with emission 

standards, failure to continuously 

operate CEMS required by this section, 

and failure to maintain records or 

submit reports required by this section. 

(7) Each owner or operator of a CEMS 

required by this section must submit 

quarterly excess emissions and 

monitoring system performance reports 

for each pollutant monitored for each 

BART affected unit monitored. All 

reports must be postmarked by the 30th

day following the end of each threemonth period of a calendar year 

(January–March, April–June, July– 

September, October–December) and 

must include, at a minimum, the 

requirements at paragraphs (e)(7)(i)–(xv) 

of this section. 

(i) Company name and address. 

(ii) Identification and description of 

the process unit being monitored. 

(iii) The dates covered by the 

reporting period. 

(iv) Total source operating hours for 

the reporting period. 

(v) Monitor manufacturer, monitor 

model number and monitor serial 

number. 

(vi) Pollutant monitored. 

(vii) Emission limitation for the 

monitored pollutant. 

(viii) Date of latest CEMS certification 

or audit. 

(ix) A description of any changes in 

continuous monitoring systems, 

processes, or controls since the last 

reporting period. 

(x) A table summarizing the total 

duration of excess emissions, as defined 

at paragraphs (e)(7)(x)(A)–(B) of this 

section, for the reporting period broken 

down by the cause of those excess 

emissions (startup/shutdown, control 

equipment problems, process problems, 

other known causes, unknown causes), 

and the total percent of excess 

emissions (for all causes) for the 

reporting period calculated as described 

at paragraph (e)(7)(x)(C) of this section. 

(A) For purposes of this section, an 

excess emission is defined as any 30- 

day rolling average period, including 

periods of startup, shutdown and 

malfunction, during which the 30-day 

rolling average emissions of either 

regulated pollutant (SO2 and NOX), as 

measured by a CEMS, exceeds the 

applicable emission standards in this 

section. 

(B) For purposes of this section, if a 

facility calculates a 30-day rolling 

average emission rate in accordance 

with this section which exceeds the 

applicable emission standards of this 

section, then it will be considered 30 

days of excess emissions. If the 

following 30-day rolling average 

emission rate is calculated and found to 

exceed the applicable emission 

standards of this section as well, then it 

will add one more day to the total days 

of excess emissions (i.e. 31 days). 

Similarly, if an excess emission is 

calculated for a 30-day rolling average 

period and no additional excess 

emissions are calculated until 15 days 

after the first, then that new excess 

emission will add 15 days to the total 

days of excess emissions (i.e. 30 + 15 = 

45). For purposes of this section, if an 

excess emission is calculated for any 

period of time within a reporting period, 

there will be no fewer than 30 days of 

excess emissions but there should be no 

more than 121 days of excess emissions 

for a reporting period. 

(C) For purposes of this section, the 

total percent of excess emissions will be 

determined by summing all periods of 

excess emissions (in days) for the 

reporting period, dividing that number 

by the total BART affected unit 

operating days for the reporting period, 

and then multiplying by 100 to get the 

total percent of excess emissions for the 

reporting period. An operating day, as 

defined previously, is any day during 

which fuel is fired in the BART affected 

unit for any period of time. Because of 

the possible overlap of 30-day rolling 

average excess emissions across 

quarters, there are some situations 

where the total percent of excess 

emissions could exceed 100 percent. 

This extreme situation would only 

result from serious excess emissions 

problems where excess emissions occur 

for nearly every day during a reporting 

period. 

(xi) A table summarizing the total 

duration of monitor downtime, as 

defined at paragraph (e)(7)(xi)(A) of this 

section, for the reporting period broken 

down by the cause of the monitor 

downtime (monitor equipment 

malfunctions, non-monitor equipment 

malfunctions, quality assurance 

calibration, other known causes, 

unknown causes), and the total percent 

of monitor downtime (for all causes) for 

the reporting period calculated as 

described at paragraph (e)(7)(xi)(B) of 

this section. 

(A) For purposes of this section, 

monitor downtime is defined as any 

period of time (in hours) during which 

the required monitoring system was not 

measuring emissions from the BART 

affected unit. This includes any period 

of CEMS QA/QC, daily zero and span 

checks, and similar activities. 

(B) For purposes of this section, the 

total percent of monitor downtime will 

be determined by summing all periods 

of monitor downtime (in hours) for the 

reporting period, dividing that number 

by the total number of BART affected 

unit operating hours for the reporting 

period, and then multiplying by 100 to 

get the total percent of excess emissions 

for the reporting period. 

(xii) A table which identifies each 

period of excess emissions for the 

reporting period and includes, at a 

minimum, the information in 

paragraphs (e)(7)(xii)(A)–(F) of this 

section. 

(A) The date of each excess emission. 

(B) The beginning and end time of 

each excess emission. 

(C) The pollutant for which an excess 

emission occurred. 

(D) The magnitude of the excess 

emission. 

(E) The cause of the excess emission. 

(F) The corrective action taken or 

preventative measures adopted to 

minimize or eliminate the excess 

emissions and prevent such excess 

emission from occurring again. 

(xiii) A table which identifies each 

period of monitor downtime for the 

reporting period and includes, at a 

minimum, the information in 

paragraphs (e)(7)(xiii)(A)–(D) of this 

section. 

(A) The date of each period of monitor 

downtime. 

(B) The beginning and end time of 

each period of monitor downtime. 

(C) The cause of the period of monitor 

downtime. 

(D) The corrective action taken or 

preventative measures adopted for 

system repairs or adjustments to 

minimize or eliminate monitor 

downtime and prevent such downtime 

from occurring again. 

(xiv) If there were no periods of 

excess emissions during the reporting 

period, then the excess emission report 

must include a statement which says 

there were no periods of excess 

emissions during this reporting period. 

(xv) If there were no periods of 

monitor downtime, except for daily zero 


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8744 Federal Register / Vol. 78, No. 25 / Wednesday, February 6, 2013 / Rules and Regulations 

and span checks, during the reporting 

period, then the excess emission report 

must include a statement which says 

there were no periods of monitor 

downtime during this reporting period 

except for the daily zero and span 

checks. 

(8) The owner or operator of each 

CEMS required by this section must 

develop and submit for review and 

approval by the Regional Administrator 

a site specific monitoring plan. The 

purpose of this monitoring plan is to 

establish procedures and practices 

which will be implemented by the 

owner or operator in its effort to comply 

with the monitoring, recordkeeping and 

reporting requirements of this section. 

The monitoring plan must include, at a 

minimum, the information at 

paragraphs (e)(8)(i)–(x) of this section. 

(i) Site specific information including 

the company name, address, and contact 

information. 

(ii) The objectives of the monitoring 

program implemented and information 

describing how those objectives will be 

met. 

(iii) Information on any emission 

factors used in conjunction with the 

CEMS required by this section to 

calculate emission rates and a 

description of how those emission 

factors were determined. 

(iv) A description of methods to be 

used to calculate emission rates when 

CEMS data is not available due to 

downtime associated with QA/QC 

events. 

(v) A description of the QA/QC 

program to be implemented by the 

owner or operator of CEMS required by 

this section. This can be the QA/QC 

program developed in accordance with 

40 CFR Part 60, Appendix F, Procedure 

1, Section 3. 

(vi) A list of spare parts for CEMS 

maintained on site for system 

maintenance and repairs. 

(vii) A description of the procedures 

to be used to calculate 30-day rolling 

averages and an example calculation 

which shows the algorithms used by the 

CEMS to calculate 30-day rolling 

averages. 

(viii) A sample of the document to be 

used for the quarterly excess emission 

reports required by this section. 

(ix) A description of the procedures to 

be implemented to investigate root 

causes of excess emissions and monitor 

downtime and the proposed corrective 

actions to address potential root causes 

of excess emissions and monitor 

downtime. 

(x) A description of the sampling and 

calculation methodology for 

determining the percent sulfur by 

weight as a monthly block average for 

coal used during that month. 

[FR Doc. 2013–01473 Filed 2–5–13; 8:45 am] 

BILLING CODE 6560–50–P 


sroberts on DSK5SPTVN1PROD with RULES