Vol. 77 Wednesday, 

No. 247 December 26, 2012 

Part II 

Environmental Protection Agency 

40 CFR Part 52 

Approval and Promulgation of Implementation Plans; State of Washington; 

Regional Haze State Implementation Plan; Federal Implementation Plan for 

Best Available Retrofit Technology for Alcoa Intalco Operations and Tesoro 

Refining and Marketing; Proposed Rule 


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76174 Federal Register / Vol. 77, No. 247 / Wednesday, December 26, 2012 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 52 

[EPA–R10–OAR–2010–1071, FRL–9760–6] 

Approval and Promulgation of 

Implementation Plans; State of 

Washington; Regional Haze State 

Implementation Plan; Federal 

Implementation Plan for Best Available 

Retrofit Technology for Alcoa Intalco 

Operations and Tesoro Refining and 

Marketing 

AGENCY: Environmental Protection 

Agency (EPA) 

ACTION: Proposed rule. 

SUMMARY: EPA is proposing to partially 

approve and partially disapprove a 

Washington Regional Haze 

Implementation Plan (SIP) submitted by 

the State of Washington on December 

22, 2010, that addresses regional haze 

for the first implementation period. This 

plan was submitted to meet the 

requirements of Clean Air Act (CAA) 

sections 169A and 169B that require 

states to prevent any future and remedy 

any existing man-made impairment of 

visibility in mandatory Class I areas. 

EPA is proposing to: (1) Approve 

portions of this SIP submittal as meeting 

most of the requirements of the regional 

haze program, (2) propose a limited 

approval and limited disapproval of the 

SO2 Best Available Retrofit Technology 

(BART) determination for Intalco 

Aluminum Corp. (Intalco) potline 

operation and propose a federal ‘‘Better 

than BART’’ alternative, and (3) propose 

to disapprove the NOx BART 

determination for five BART emission 

units at the Tesoro Refining and 

Marketing refinery (Tesoro) and propose 

a federal Better than BART alternative. 

This combined rule package of proposed 

SIP approved elements and proposed 

federal elements will meet the 

requirements of CAA sections 169A and 

169B. On August 20, 2012, EPA 

approved those provisions of the 

Washington SIP addressing the BART 

determination for TransAlta Centralia 

Generation L.L.C. coal fired power plant 

(TransAlta). 

DATES: Comments: Written comments 

must be received at the address below 

on or before February 15, 2013. 

Public Hearing: A public hearing is 

offered to provide interested parties the 

opportunity to present information and 

opinions to EPA concerning our 

proposal. Interested parties may also 

submit written comments, as discussed 

below. If you wish to request a hearing 

and present testimony, you should 

notify Mr. Steve Body on or before 

January 10, 2013 and indicate the nature 

of the issues you wish to provide oral 

testimony during the hearing. Mr. 

Body’s contact information is found in 

FOR FURTHER INFORMATION CONTACT

below. At the hearing, the hearing 

officer may limit oral testimony to 5 

minutes per person. The hearing will be 

limited to the subject matter of this 

proposal, the scope of which is 

discussed below. EPA will not respond 

to comments during the public hearing. 

When we publish our final action we 

will provide a written response to all 

written or oral comments received on 

the proposal. EPA will not be providing 

equipment for commenters to show 

overhead slides or make computerized 

slide presentations. A transcript of the 

hearing and written statements will be 

made available for copying during 

normal working hours at the address 

listed for inspection of documents, and 

also included in the Docket. Any 

member of the public may provide 

written or oral comments and data 

pertaining to our proposal at the 

hearing. Note that any written 

comments and supporting information 

submitted during the comment period 

will be considered with the same weight 

as any oral comments presented at the 

public hearing. If no requests for a 

public hearing are received by close of 

business on January 10, 2013, a hearing 

will not be held; please contact Mr. 

Body at (206) 553–0782 to find out if the 

hearing will actually be held or if it will 

be cancelled for lack of any request to 

speak. 

ADDRESSES: Public Hearing: A public 

hearing, if requested, will be held 

January 16, 2013, beginning at 6:00 p.m. 

at the Washington Department of 

Ecology Offices, Room #ROA–32, 300 

Desmond Drive, Lacey, WA 98503. 

Comments: Submit your comments, 

identified by Docket ID No. EPA–R10– 

OAR–2010–1071 by one of the following 

methods: 

• www.regulations.gov. Follow the 

on-line instructions for submitting 

comments. 

• Email: R10- 

Public_Comments@epa.gov. 

• Mail: Steve Body, EPA Region 10, 

Suite 900, Office of Air, Waste and 

Toxics, 1200 Sixth Avenue, Seattle, WA 

98101. 

• Hand Delivery: EPA Region 10, 

1200 Sixth Avenue, Suite 900, Seattle, 

WA 98101. Attention: Steve Body, 

Office of Air, Waste and Toxics, AWT– 

107. Such deliveries are only accepted 

during normal hours of operation, and 

special arrangements should be made 

for deliveries of boxed information. 

Instructions: Direct your comments to 

Docket ID No. EPA–R10–OAR–2010– 

1071. EPA’s policy is that all comments 

received will be included in the public 

docket without change and may be 

made available online at 

www.regulations.gov, including any 

personal information provided, unless 

the comment includes information 

claimed to be Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Do not submit information that you 

consider to be CBI or otherwise 

protected through www.regulations.gov 

or email. The www.regulations.gov Web 

site is an ‘‘anonymous access’’ system, 

which means EPA will not know your 

identity or contact information unless 

you provide it in the body of your 

comment. If you send an email 

comment directly to EPA, without going 

through www.regulations.gov, your 

email address will be automatically 

captured and included as part of the 

comment that is placed in the public 

docket and made available on the 

Internet. If you submit an electronic 

comment, EPA recommends that you 

include your name and other contact 

information in the body of your 

comment and with any disk or CD–ROM 

you submit. If EPA cannot read your 

comment due to technical difficulties 

and cannot contact you for clarification, 

EPA may not be able to consider your 

comment. Electronic files should avoid 

the use of special characters, any form 

of encryption, and be free of any defects 

or viruses. 

Docket: All documents in the docket 

are listed in the www.regulations.gov 

index. Although listed in the index, 

some information is not publicly 

available (e.g., CBI or other information 

whose disclosure is restricted by 

statute). Certain other material, such as 

copyrighted material, will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically at 

www.regulations.gov or in hard copy at 

the Office of Air, Waste and Toxics, EPA 

Region 10, 1200 Sixth Avenue, Seattle, 

WA 98101. EPA requests that if at all 

possible, you contact the individual 

listed below to view a hard copy of the 

docket. 

FOR FURTHER INFORMATION CONTACT: 

Steve Body at telephone number (206) 

553–0782, body.steve@epa.gov, or the 

above EPA, Region 10 address. 

SUPPLEMENTARY INFORMATION: 

Throughout this document whenever 

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

the EPA. Information is organized as 

follows: 


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1Areas designated as mandatory Class I Federal 

areas consist of national parks exceeding 6000 

acres, wilderness areas and national memorial parks 

exceeding 5000 acres, and all international parks 

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

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

CAA, EPA, in consultation with the Department of 

Interior, promulgated a list of 156 areas where 

visibility is identified as an important value. 44 FR 

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

mandatory Class I area includes subsequent changes 

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

7472(a). Although states and tribes may designate 

as Class I additional areas which they consider to 

have visibility as an important value, the 

requirements of the visibility program set forth in 

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

Class I Federal areas.’’ Each mandatory Class I 

Federal area is the responsibility of a ‘‘Federal Land 

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

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

Class I Federal area.’’ 2See 64 FR at 35715. 

3 Id. 

Table of Contents 

I. Overview and Summary of EPA’s Proposed 

Action 

II. Background for EPA’s Proposed Action 

A. Definition of Regional Haze 

B. Regional Haze Rules and Regulations 

C. Roles of Agencies in Addressing 

Regional Haze 

III. Requirements for the Regional Haze SIP 

A. The CAA and the Regional Haze Rule 

B. Determination of Baseline, Natural, and 

Current Visibility Conditions 

C. Consultation With States and Federal 

Land Managers 

D. Best Available Retrofit Technology 

E. Determination of Reasonable Progress 

Goals (RPGs) 

F. Long Term Strategy (LTS) 

G. Coordinating Regional Haze and 

Reasonably Attributable Visibility 

Impairment (RAVI) 

H. Monitoring Strategy and Other 

Implementation Requirements 

IV. EPA’s Analysis of the Washington 

Regional Haze SIP 

A. Affected Class I Areas 

B. Baseline and Natural Conditions and 

Uniform Rate of Progress 

C. Washington Emissions Inventories 

D. Sources of Visibility Impairment in 

Washington Class I Areas 

E. Best Available Retrofit Technology 

1. BART-Eligible Sources in Washington 

2. Sources Subject to BART 

3. Washington Source Specific BART 

Analysis 

a. British Petroleum, Cherry Point Refinery 

b. Intalco Aluminum Corp. 

c. Tesoro Refining and Marketing 

d. Port Townsend Paper Company 

e. Lafarge North America 

f. TransAlta Centralia Generation, LLC 

g. Weyerhaeuser Company-Longview 

F. Determination of Reasonable Progress 

Goals 

G. Long Term Strategy 

H. Monitoring Strategy and Other 

Implementation Requirements 

I. Consultation With States and Federal 

Land Managers 

J. Periodic SIP Revisions and 5-Year 

Progress Reports 

V. What action is EPA proposing? 

VI. Washington Notice 

VII. Scope of Action 

VIII. Statutory and Executive Order Reviews 

I. Overview and Summary of EPA’s 

Proposed Action 

In this action, EPA proposes to 

approve the following provisions of 

Washington’s Regional Haze SIP 

submittal: Washington’s identification 

of Class I areas and determination of 

baseline conditions, natural conditions 

and uniform rate of progress (URP) for 

each of these Class I areas. We also 

propose to approve Washington’s 

emission inventories, sources of 

visibility impairment in Washington 

Class I areas, monitoring strategy, 

consultation with other states and 

Federal Land Managers (FLMs), 

reasonable progress goals (RPGs), and 

long term strategy (LTS). 

EPA previously approved 

Washington’s BART determination for 

the TransAlta power plant in Centralia, 

Washington. In today’s action we are 

proposing to approve BART 

determinations for all other sources 

subject to BART with the exception of 

certain BART emission units at two 

sources subject to BART. Specifically 

EPA is proposing to approve the BART 

determinations for the British Petroleum 

(BP) Cherry Point Refinery, Port 

Townsend Paper Company, LaFarge 

North America, and Weyerhaeuser 

Longview and portions of the BART 

determinations for Intalco and Tesoro. 

EPA is proposing a limited approval and 

limited disapproval of Washington’s 

SO2 BART determination for the 

potlines at Intalco in Ferndale, 

Washington. EPA proposes an 

alternative ‘Better than BART’’ Federal 

Implementation Plan (FIP) for SO2

BART for the potlines with an annual 

limit on SO2 emissions of 80% of 

baseyear emissions. EPA is proposing to 

disapprove Washington’s NOX BART 

determination for 5 BART units at the 

Tesoro refinery in Anacortes, 

Washington. EPA proposes a Better than 

BART alternative FIP for these 5 BART 

units. 

II. Background for EPA’s Proposed 

Action 

In the CAA Amendments of 1977, 

Congress established a program to 

protect and improve visibility in 

national parks and wilderness areas. See 

CAA section 169A. Congress amended 

the visibility provisions in the CAA in 

1990 to focus attention on the problem 

of regional haze. See CAA section 169B. 

EPA promulgated regulations in 1999 to 

implement sections 169A and 169B of 

the Act. These regulations require states 

to develop and implement plans to 

ensure reasonable progress toward 

improving visibility in mandatory Class 

I Federal areas 1 (Class I areas). 64 FR 

35714 (July 1, 1999); see also 70 FR 

39104 (July 6, 2005) and 71 FR 60612 

(October 13, 2006). 

A. Definition of Regional Haze 

Regional haze is impairment of visual 

range or colorization caused by 

emission of air pollution produced by 

numerous sources and activities, located 

across a broad regional area. The 

sources include but are not limited to, 

major and minor stationary sources, 

mobile sources, and area sources 

including non-anthropogenic sources. 

Visibility impairment is primarily 

caused by fine particulate matter, 

particles with an aerodynamic diameter 

of less than 2.5 micrometers, (PM2.5) or 

secondary aerosol formed in the 

atmosphere from precursor gasses (e.g., 

sulfur dioxide, nitrogen oxides, and in 

some cases, ammonia and volatile 

organic compounds). Atmospheric fine 

particulate reduces clarity, color, and 

visual range of visual scenes. Visibility 

reducing fine particulate is primarily 

composed of sulfate, nitrate, organic 

carbon compounds, elemental carbon, 

and soil dust, and impairs visibility by 

scattering and absorbing light. Fine 

particulate can also cause serious health 

effects and mortality in humans, and 

contributes to environmental effects 

such as acid deposition and 

eutrophication.2

Data from the existing visibility 

monitoring network, the ‘‘Interagency 

Monitoring of Protected Visual 

Environments’’ (IMPROVE) monitoring 

network, show that visibility 

impairment caused by air pollution 

occurs virtually all the time at most 

national parks and wilderness areas. 

Average visual range in many Class I 

areas in the Western United States is 

100–150 kilometers, or about one-half to 

two-thirds the visual range that would 

exist without anmade air pollution.3

Visibility impairment also varies day-today and by season depending on 

variation in meteorology and emission 

rates. 

B. Regional Haze Rules and Regulations 

In section 169A of the 1977 CAA 

Amendments, Congress created a 

program for protecting visibility in the 

nation’s national parks and wilderness 

areas. This section of the CAA 

establishes as a national goal the 

‘‘prevention of any future, and the 

remedying of any existing, impairment 

of visibility in Class I areas which 

impairment results from manmade air 


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4Albuquerque/Bernalillo County in New Mexico 

must also submit a regional haze SIP to completely 

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

the CAA for the entire State of New Mexico under 

the New Mexico Air Quality Control Act (section 

74–2–4). 

5The preamble to the RHR provides additional 

details about the deciview. 64 FR 35714, 35725 

(July 1, 1999). 

pollution.’’ CAA section 169A(a)(1). On 

December 2, 1980, EPA promulgated 

regulations to address visibility 

impairment in Class I areas that is 

‘‘reasonably attributable’’ to a single 

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

‘‘reasonably attributable visibility 

impairment’’. 45 FR 80084. These 

regulations represented the first phase 

in addressing visibility impairment. 

EPA deferred action on regional haze 

that emanates from a variety of sources 

until monitoring, modeling, and 

scientific knowledge about the 

relationships between pollutants and 

visibility impairment were improved. 

Congress added section 169B to the 

CAA in 1990 to address regional haze 

issues. EPA promulgated a rule to 

address regional haze on July 1, 1999 

(64 FR 35713) (the Regional Haze Rule 

or RHR). The RHR revised the existing 

visibility regulations to integrate into 

the regulation, provisions addressing 

regional haze impairment and 

established a comprehensive visibility 

protection program for Class I areas. The 

requirements for regional haze, found at 

40 CFR 51.308 and 51.309, are included 

in EPA’s visibility protection 

regulations at 40 CFR 51.300–309. Some 

of the main elements of the regional 

haze requirements are summarized in 

section III of this notice. The 

requirement to submit a regional haze 

SIP applies to all 50 states, the District 

of Columbia and the Virgin Islands.4 40 

CFR 51.308(b) requires states to submit 

the first implementation plan 

addressing regional haze visibility 

impairment no later than December 17, 

2007. 

C. Roles of Agencies in Addressing 

Regional Haze 

Successful implementation of the 

regional haze program will require longterm regional coordination among 

states, tribal governments and various 

federal agencies. As noted above, 

pollution affecting the air quality in 

Class I areas can be transported over 

long distances, even hundreds of 

kilometers. Therefore, to effectively 

address the problem of visibility 

impairment in Class I areas, states need 

to develop strategies in coordination 

with one another, taking into account 

the effect of emissions from one 

jurisdiction on the air quality in 

another. 

Because the pollutants that lead to 

regional haze impairment can originate 

from across state lines, even across 

international boundaries, EPA has 

encouraged the states and Tribes to 

address visibility impairment from a 

regional perspective. Five regional 

planning organizations (RPOs) were 

created nationally to address regional 

haze and related issues. One of the main 

objectives of the RPOs is to develop and 

analyze data and conduct pollutant 

transport modeling to assist the States or 

Tribes in developing their regional haze 

plans. 

The Western Regional Air Partnership 

(WRAP), one of the five RPOs 

nationally, is a voluntary partnership of 

state, Tribal, federal, and local air 

agencies dealing with air quality in the 

West. WRAP member states include: 

Alaska, Arizona, California, Colorado, 

Idaho, Montana, New Mexico, North 

Dakota, Oregon, South Dakota, Utah, 

Washington, and Wyoming. WRAP 

Tribal members include Campo Band of 

Kumeyaay Indians, Confederated Salish 

and Kootenai Tribes, Cortina Indian 

Rancheria, Hopi Tribe, Hualapai Nation 

of the Grand Canyon, Native Village of 

Shungnak, Nez Perce Tribe, Northern 

Cheyenne Tribe, Pueblo of Acoma, 

Pueblo of San Felipe, and ShoshoneBannock Tribes of Fort Hall. 

II. Requirements for the Regional Haze 

SIPs 

A. The CAA and the Regional Haze Rule 

Regional haze SIPs must assure 

reasonable progress towards the 

national goal of achieving natural 

visibility conditions in Class I areas. 

Section 169A of the CAA and EPA’s 

implementing regulations require states 

to establish long-term strategies for 

making reasonable progress toward 

meeting this goal. Implementation plans 

must also give specific attention to 

certain stationary sources that were in 

existence on August 7, 1977, but were 

not in operation before August 7, 1962, 

and require these sources, where 

appropriate, to install BART controls for 

the purpose of eliminating or reducing 

visibility impairment. The specific 

regional haze SIP requirements are 

discussed in further detail below. 

B. Determination of Baseline, Natural, 

and Current Visibility Conditions 

The RHR establishes the deciview 

(dv) as the principal metric for 

measuring visibility. This visibility 

metric expresses uniform changes in 

haziness in terms of common 

increments across the entire range of 

visibility conditions, from pristine to 

extremely hazy conditions. Visibility is 

determined by measuring the visual 

range (or deciview), which is the 

greatest distance, in kilometers or miles, 

at which a dark object can be viewed 

against the sky. The deciview is a useful 

measure for tracking progress in 

improving visibility, because each 

deciview change is an equal incremental 

change in visibility perceived by the 

human eye. Most people can detect a 

change in visibility at one deciview.5

The deciview is used in expressing 

reasonable progress goals (which are 

interim visibility goals towards meeting 

the national visibility goal), defining 

baseline, current, and natural 

conditions, and tracking changes in 

visibility. The regional haze SIPs must 

contain measures that ensure 

‘‘reasonable progress’’ toward the 

national goal of preventing and 

remedying visibility impairment in 

Class I areas caused by manmade air 

pollution by reducing anthropogenic 

emissions that cause regional haze. The 

national goal is a return to natural 

conditions, i.e., manmade sources of air 

pollution would no longer impair 

visibility in Class I areas. 

To track changes in visibility over 

time at each of the 156 Class I areas 

covered by the visibility program (40 

CFR 81.401–437), and as part of the 

process for determining reasonable 

progress, states must calculate the 

degree of existing visibility impairment 

at each Class I area at the time of each 

regional haze SIP submittal and 

periodically review progress every five 

years midway through each 10-year 

implementation period. To do this, the 

RHR requires states to determine the 

degree of impairment (in deciviews) for 

the average of the 20% least impaired 

(‘‘best’’) and 20% most impaired 

(‘‘worst’’) visibility days over a specified 

time period at each of their Class I areas. 

In addition, states must also develop an 

estimate of natural visibility conditions 

for the purpose of comparing progress 

toward the national goal. Natural 

visibility is determined by estimating 

the natural concentrations of pollutants 

that cause visibility impairment and 

then calculating total light extinction 

based on those estimates. EPA has 

provided guidance to states regarding 

how to calculate baseline, natural and 

current visibility conditions in 

documents titled, EPA’s Guidance for 

Estimating Natural Visibility Conditions 

Under the Regional Haze Rule, 

September 2003, (EPA–454/B–03–005 

located at http://www.epa.gov/ttncaaa1/ 

t1/memoranda/rh_envcurhr_gd.pdf), 

(hereinafter referred to as ‘‘EPA’s 2003 

Natural Visibility Guidance’’), and 


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6The set of ‘‘major stationary sources’’ potentially 

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

Guidance for Tracking Progress Under 

the Regional Haze Rule (EPA–454/B– 

03–004 September 2003 located at 

http://www.epa.gov/ttncaaa1/t1/ 

memoranda/rh_tpurhr_gd.pdf)), 

(hereinafter referred to as ‘‘EPA’s 2003 

Tracking Progress Guidance’’). 

For the first regional haze SIPs that 

were due by December 17, 2007, 

‘‘baseline visibility conditions’’ were the 

starting points for assessing ‘‘current’’ 

visibility impairment. Baseline visibility 

conditions represent the degree of 

visibility impairment for the 20% least 

impaired days and 20% most impaired 

days for each calendar year from 2000 

to 2004. Using monitoring data for 2000 

through 2004, states are required to 

calculate the average degree of visibility 

impairment for each Class I area, based 

on the average of annual values over the 

five-year period. The comparison of 

initial baseline visibility conditions to 

natural visibility conditions indicates 

the amount of improvement necessary 

to attain natural visibility, while the 

future comparison of baseline 

conditions to the then current 

conditions will indicate the amount of 

progress made. In general, the 2000– 

2004 baseline time period is considered 

the time from which improvement in 

visibility is measured. 

C. Consultation With States and Federal 

Land Managers 

The RHR requires that states consult 

with Federal Land Managers (FLMs) 

before adopting and submitting their 

SIPs. 40 CFR 51.308(i). States must 

provide FLMs an opportunity for 

consultation, in person and at least 60 

days prior to holding any public hearing 

on the SIP. This consultation must 

include the opportunity for the FLMs to 

discuss their assessment of visibility 

impairment in any Class I area and to 

offer recommendations on the 

development of the reasonable progress 

goals and on the development and 

implementation of strategies to address 

visibility impairment. Further, a state 

must include in its SIP a description of 

how it addressed any comments 

provided by the FLMs. Finally, a SIP 

must provide procedures for continuing 

consultation between the state and 

FLMs regarding the state’s visibility 

protection program, including 

development and review of SIP 

revisions, five-year progress reports, and 

the implementation of other programs 

having the potential to contribute to 

impairment of visibility in Class I areas. 

D. Best Available Retrofit Technology 

Section 169A of the CAA directs 

states to evaluate the use of retrofit 

controls at certain larger, often 

uncontrolled, older stationary sources in 

order to address visibility impacts from 

these sources. Specifically, section 

169A(b)(2)(A) of the CAA requires states 

to revise their SIPs to contain such 

measures as may be necessary to make 

reasonable progress towards the natural 

visibility goal, including a requirement 

that certain categories of existing major 

stationary sources 6 built between 1962 

and 1977 procure, install, and operate 

the ‘‘Best Available Retrofit 

Technology’’ as determined by the state. 

States are directed to conduct BART 

determinations for such sources that 

may be anticipated to cause or 

contribute to any visibility impairment 

in a Class I area. Rather than requiring 

source-specific BART controls, states 

also have the flexibility to adopt an 

emissions trading program or other 

alternative program as long as the 

alternative provides greater reasonable 

progress towards improving visibility 

than BART. 

On July 6, 2005, EPA published the 

Guidelines for BART Determinations 

Under the Regional Haze Rule at 

appendix Y to 40 CFR part 51 

(hereinafter referred to as the ‘‘BART 

Guidelines’’) to assist states in 

determining which of their sources 

should be subject to the BART 

requirements and in determining 

appropriate emission limits for each 

applicable source. In making a BART 

applicability determination for a fossil 

fuel-fired electric generating plant with 

a total generating capacity in excess of 

750 megawatts, a state must use the 

approach set forth in the BART 

Guidelines. A state is encouraged, but 

not required, to follow the BART 

Guidelines in making BART 

determinations for other types of 

sources. 

States must address all visibilityimpairing pollutants emitted by a source 

in the BART determination process. The 

most significant visibility-impairing 

pollutants are sulfur dioxide, nitrogen 

oxides, and fine particulate matter. EPA 

has indicated that states should use 

their best judgment in determining 

whether volatile organic compounds or 

ammonia compounds impair visibility 

in Class I areas. 

Under the BART Guidelines, states 

may select an exemption threshold 

value to determine those BART eligible 

sources not subject to BART. A BARTeligible source with an impact below the 

threshold would not be expected to 

cause or contribute to visibility 

impairment in any Class I area. The 

state must document this exemption 

threshold value in the SIP and must 

state the basis for its selection of that 

value. Any source with emissions that 

model above the threshold value would 

be subject to a BART determination 

review. The BART Guidelines 

acknowledge varying circumstances 

affecting different Class I areas. States 

should consider the number of emission 

sources affecting the Class I areas at 

issue and the magnitude of the 

individual sources’ impacts. Generally, 

an exemption threshold set by the state 

should not be higher than 0.5 deciview. 

In their SIPs, states must identify 

BART sources, (BART-eligible sources), 

as well as those BART eligible sources 

that have a visibility impact in any Class 

I area above the ‘‘BART subject’’ 

exemption threshold established by the 

state and thus, subject to BART. States 

must document their BART control 

analysis and determination for all 

sources subject to BART. 

The term ‘‘BART-eligible source’’ 

used in the BART Guidelines means the 

collection of individual emission units 

at a facility that together comprises the 

BART-eligible source. In making a 

BART determination, section 169A(g)(2) 

of the CAA requires that states consider 

the following factors: (1) The costs of 

compliance, (2) the energy and non-air 

quality environmental impacts of 

compliance, (3) any existing pollution 

control technology in use at the source, 

(4) the remaining useful life of the 

source, and (5) the degree of 

improvement in visibility which may 

reasonably be anticipated to result from 

the use of such technology. States are 

free to determine the weight and 

significance to be assigned to each 

factor. 

The regional haze SIP must include 

source-specific BART emission limits 

and compliance schedules for each 

source subject to BART. Once a state has 

made its BART determination, the 

BART controls must be installed and in 

operation as expeditiously as 

practicable, but no later than 5 years 

after the date EPA approves the regional 

haze SIP. CAA section 169A(g)(4)). 40 

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

is required by the RHR, general SIP 

requirements mandate that the SIP must 

also include all regulatory requirements 

related to monitoring, recordkeeping, 

and reporting for the BART controls on 

the source. States have the flexibility to 

choose the type of control measures 

they will use to meet the requirements 

of BART. 

E. Determination of Reasonable Progress 

Goals (RPGs) 

The vehicle for ensuring continuing 

progress towards achieving the natural 


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visibility goal is the submission of a 

series of regional haze SIPs from the 

states that establish two RPGs (i.e., two 

distinct goals, one for the ‘‘best’’ and 

one for the ‘‘worst’’ days) for every Class 

I area for each (approximately) 10-year 

implementation period. The RHR does 

not mandate specific milestones or rates 

of progress, but instead calls for states 

to establish goals that provide for 

‘‘reasonable progress’’ toward achieving 

natural (i.e., ‘‘background’’) visibility 

conditions. In setting RPGs, states must 

provide for an improvement in visibility 

for the most impaired days over the 

(approximately) 10-year period of the 

SIP, and ensure no degradation in 

visibility for the least impaired days 

over the same period. 

States have significant discretion in 

establishing RPGs, but are required to 

consider the following factors 

established in section 169A of the CAA 

and in EPA’s RHR at 40 CFR 

51.308(d)(1)(i)(A): (1) The costs of 

compliance; (2) the time necessary for 

compliance; (3) the energy and non-air 

quality environmental impacts of 

compliance; and (4) the remaining 

useful life of any potentially affected 

sources. States must demonstrate in 

their SIPs how these factors are 

considered when selecting the RPGs for 

the best and worst days for each 

applicable Class I area. States have 

considerable flexibility in how they take 

these factors into consideration, as 

noted in EPA’s Guidance for Setting 

Reasonable Progress Goals under the 

Regional Haze Program, (‘‘EPA’s 

Reasonable Progress Guidance’’), July 1, 

2007, memorandum from William L. 

Wehrum, Acting Assistant 

Administrator for Air and Radiation, to 

EPA Regional Administrators, EPA 

Regions 1–10 (pp. 4–2, 5–1). In setting 

the RPGs, states must also consider the 

rate of progress needed to reach natural 

visibility conditions by 2064 (referred to 

as the ‘‘uniform rate of progress’’ or the 

‘‘glidepath’’) and the emission reduction 

measures needed to achieve that rate of 

progress over the 10-year period of the 

SIP. Uniform progress towards 

achievement of natural conditions by 

the year 2064 represents a rate of 

progress which states are to use for 

analytical comparison to the amount of 

progress they expect to achieve. In 

setting RPGs, each state with one or 

more Class I areas (‘‘Class I state’’) must 

also consult with potentially 

‘‘contributing states,’’ i.e., other nearby 

states with emission sources that may be 

affecting visibility impairment at the 

Class I state’s areas. 40 CFR 

51.308(d)(1)(iv). 

F. Long Term Strategy (LTS) 

Consistent with the requirement in 

section 169A(b) of the CAA that states 

include in their regional haze SIP a 10 

to 15 year strategy for making 

reasonable progress, section 51.308(d)(3) 

of the RHR requires that states include 

a LTS in their regional haze SIPs. The 

LTS is the compilation of all control 

measures a state will use during the 

implementation period of the specific 

SIP submittal to meet applicable RPGs. 

The LTS must include ‘‘enforceable 

emissions limitations, compliance 

schedules, and other measures as 

necessary to achieve the reasonable 

progress goals’’ for all Class I areas 

within, or affected by emissions from, 

the state. 40 CFR 51.308(d)(3). 

When a state’s emissions are 

reasonably anticipated to cause or 

contribute to visibility impairment in a 

Class I area located in another state, the 

RHR requires the impacted state to 

coordinate with the contributing states 

in order to develop coordinated 

emissions management strategies. 40 

CFR 51.308(d)(3)(i). In such cases, the 

contributing state must demonstrate that 

it has included, in its SIP, all measures 

necessary to obtain its share of the 

emissions reductions needed to meet 

the RPGs for the Class I area. The RPOs 

have provided forums for significant 

interstate consultation, but additional 

consultations between states may be 

required to sufficiently address 

interstate visibility issues. This is 

especially true where two states belong 

to different RPOs. 

States should consider all types of 

anthropogenic sources of visibility 

impairment in developing their LTS, 

including stationary, minor, mobile, and 

area sources. At a minimum, states must 

describe how each of the following 

seven factors listed below are taken into 

account in developing their LTS: (1) 

Emissions reductions due to ongoing air 

pollution control programs, including 

measures to address RAVI; (2) measures 

to mitigate the impacts of construction 

activities; (3) emissions limitations and 

schedules for compliance to achieve the 

RPG; (4) source retirement and 

replacement schedules; (5) smoke 

management techniques for agricultural 

and forestry management purposes 

including plans as currently exist 

within the state for these purposes; (6) 

enforceability of emissions limitations 

and control measures; and (7) the 

anticipated net effect on visibility due to 

projected changes in point, area, and 

mobile source emissions over the period 

addressed by the LTS. See 40 CFR 

51.308(d)(3)(v). 

G. Coordinating Regional Haze and 

Reasonably Attributable Visibility 

Impairment (RAVI) 

As part of the RHR, EPA revised 40 

CFR 51.306(c) regarding the LTS for 

RAVI to require that the RAVI plan must 

provide for a periodic review and SIP 

revision not less frequently than every 

three years until the date of submission 

of the state’s first plan addressing 

regional haze visibility impairment, 

which was due December 17, 2007, in 

accordance with 40 CFR 51.308(b) and 

(c). On or before this date, the state must 

revise its plan to provide for review and 

revision of a coordinated LTS for 

addressing RAVI and regional haze, and 

the state must submit the first such 

coordinated LTS with its first regional 

haze SIP. Future coordinated LTS’s, and 

periodic progress reports evaluating 

progress towards RPGs, must be 

submitted consistent with the schedule 

for SIP submission and periodic 

progress reports set forth in 40 CFR 

51.308(f) and 51.308(g), respectively. 

The periodic review of a state’s LTS 

must report on both regional haze and 

RAVI impairment and must be 

submitted to EPA as a SIP revision. 

H. Monitoring Strategy and Other 

Implementation Requirements 

Section 51.308(d)(4) of the RHR 

includes the requirement for a 

monitoring strategy for measuring, 

characterizing, and reporting of regional 

haze visibility impairment that is 

representative of all mandatory Class I 

Federal areas within the state. The 

strategy must be coordinated with the 

monitoring strategy required in section 

51.305 for RAVI. Compliance with this 

requirement may be met through 

‘‘participation’’ in the IMPROVE 

network, i.e., review and use of 

monitoring data from the network. The 

monitoring strategy is due with the first 

regional haze SIP, and it must be 

reviewed every five years. The 

monitoring strategy must also provide 

for additional monitoring sites if the 

IMPROVE network is not sufficient to 

determine whether RPGs will be met. 

The SIP must also provide for the 

following: 

• Procedures for using monitoring 

data and other information in a state 

with mandatory Class I areas to 

determine the contribution of emissions 

from within the state to regional haze 

visibility impairment at Class I areas 

both within and outside the state; 

• Procedures for using monitoring 

data and other information in a state 

with no mandatory Class I areas to 

determine the contribution of emissions 

from within the state to regional haze 


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visibility impairment at Class I areas in 

other states; 

• Reporting of all visibility 

monitoring data to the Administrator at 

least annually for each Class I area in 

the state, and where possible, in 

electronic format; 

• Developing a statewide inventory of 

emissions of pollutants that are 

reasonably anticipated to cause or 

contribute to visibility impairment in 

any Class I area. The inventory must 

include emissions for a baseline year, 

emissions for the most recent year for 

which data are available, and estimates 

of future projected emissions. A state 

must also make a commitment to update 

the inventory periodically; and 

• Other elements, including 

reporting, recordkeeping, and other 

measures necessary to assess and report 

on visibility. 

The RHR requires control strategies to 

cover an initial implementation period 

extending to the year 2018, with a 

comprehensive reassessment and 

revision of those strategies, as 

appropriate, every 10 years thereafter. 

Periodic SIP revisions must meet the 

core requirements of section 51.308(d) 

with the exception of BART. The 

requirement to evaluate sources for 

BART applies only to the first regional 

haze SIP. Facilities subject to BART 

must continue to comply with the BART 

provisions of section 51.308(e), as noted 

above. Periodic SIP revisions will assure 

that the statutory requirement of 

reasonable progress will continue to be 

met. 

III. EPA’s Analysis of the Washington 

Regional Haze SIP 

A. Affected Class I Areas 

There are eight mandatory Class I 

areas within Washington: Olympic 

National Park, North Cascades National 

Park, Glacier Peak Wilderness Area, 

Alpine Lakes Wilderness Area, Mt. 

Rainier National Park, Goat Rocks 

Wilderness Area, Mt. Adams Wilderness 

Area, and Pasayten Wilderness Area. 

See 40 CFR 81.434. The Washington SIP 

submittal addresses all eight Class I 

areas. 

B. Baseline and Natural Conditions and 

Uniform Rate of Progress 

Washington, using data from the 

IMPROVE monitoring network, 

identified baseline and natural visibility 

conditions for all eight Class I areas in 

Washington. Baseline visibility was 

calculated from monitoring data 

collected by IMPROVE monitors for the 

20% most-impaired (20% worst) days 

and the 20% least-impaired (20% best) 

days. Washington used the WRAP 

derived natural visibility conditions. In 

general, WRAP based their estimates on 

EPA guidance, ‘‘Guidance for Estimating 

Natural Visibility Conditions Under the 

Regional Haze Program’’ (EPA–45/B– 

03–0005 September 2003), (http:// 

www.epa.gov/ttn/caaa/t1/memoranda/

rh_envcurhr_gd.pdf), but incorporated 

refinements which EPA believes 

provides results more appropriate for 

western states than the general EPA 

default approach. See section 2.E of the 

WRAP Technical Support Document 

(WRAP TSD). 

Olympic National Park: An IMPROVE 

monitor is located northeast of the Park 

boundary at the extreme northeast 

corner of the Olympic Peninsula near 

Sequim, Washington. Based on baseline 

data from the years 2000 to 2004, the 

average 20% worst days visibility is 

16.7 dv and the average 20% best days 

visibility is 6.0 dv. Natural visibility for 

the average 20% worst days is 8.4 dv. 

North Cascades National Park and 

Glacier Peak Wilderness Areas: The 

North Cascades National Park and 

Glacier Peak Wilderness Area are both 

represented by an IMPROVE monitor 

located near Ross Lake on the Skagit 

River just outside the eastern boundary 

of the northern section of North 

Cascades National Park. Based on 

baseline data from the years 2000 to 

2004, the average 20% worst days 

visibility is 16.0 dv and the average 20% 

best days visibility is 3.37 dv. Natural 

visibility for the average 20% worst 

days is 8.39 dv. 

Alpine Lakes Wilderness Area: Alpine 

Lakes Wilderness Area visibility is 

represented by an IMPROVE monitor 

located southwest of the wilderness area 

at Snoqualmie Pass in the Cascade 

Mountains. Based on baseline data from 

the years 2000 to 2004, the average 20% 

worst days visibility is 17.8 dv and the 

average 20% best days visibility is 5.5 

dv. Natural visibility for the Alpine 

Lakes Wilderness Area average 20% 

worst days is 8.4 dv. 

Mt. Rainier National Park: Mt. Rainier 

National Park visibility is represented 

by an IMPROVE monitor located at Park 

headquarters at Tahoma Woods. Based 

on baseline data from the years 2000 to 

2004, the average 20% worst days 

visibility is 18.2 dv and the average 20% 

best days visibility is 5.5 dv. Natural 

visibility for the Mt. Rainier National 

Park average 20% worst days is 8.5 dv. 

Goat Rocks and Mt. Adams 

Wilderness Areas: The Goat Rocks and 

Mt. Adams Wilderness Area’s visibility 

are both represented by an IMPROVE 

monitor located at White Pass in the 

Cascade Mountain Range. Based on 

baseline data from the years 2000 to 

2004, the average 20% worst days 

visibility is 12.7 dv and the average 20% 

best days visibility is 1.7 dv for both 

areas. Natural visibility for the Goat 

Rocks and Mt. Adams Wilderness Areas 

average 20% worst days is 8.35 dv. 

Pasayten Wilderness Area: The 

Pasayten Wilderness Area visibility is 

represented by an IMPROVE monitor 

located 50 km south and east of the 

wilderness boundary. Based on baseline 

data from the years 2000 to 2004, the 

average 20% worst days visibility is 

15.2 dv and the average 20% best days 

visibility is 2.7 dv. Natural visibility for 

the Pasayten Wilderness Area average 

20% worst days is 8.3 dv. 

Based on our evaluation of the 

Washington’s baseline and natural 

conditions analysis, EPA is proposing to 

find that Washington has appropriately 

determined the baseline visibility for 

the average 20% worst and 20% best 

days, and natural conditions for the 

average 20% worst days in each Class I 

area in Washington. 

C. Washington Emissions Inventories 

There are three main categories of air 

pollution emission sources: Point 

sources, area sources, and mobile 

sources. Point sources are larger 

stationary sources. Area sources are 

large numbers of small sources that are 

widely distributed across an area, such 

as residential heating units, wildfire, reentrained dust from unpaved roads, or 

windblown dust from agricultural 

fields. Mobile sources are sources such 

as motor vehicles, locomotives, and 

aircraft. 

The RHR requires a statewide 

emission inventory of pollutants that are 

reasonably anticipated to cause or 

contribute to visibility impairment in 

any mandatory Class I area. 40 CFR 

51.308(d)(4)(v). The WRAP, with data 

supplied by Washington, compiled 

emission inventories for all major 

source categories in Washington for the 

2002 baseline year and estimated 

emissions for 2018. Emission estimates 

for 2018 were generated from 

anticipated population growth, growth 

in industrial activity, and emission 

reductions from implementation of 

expected control measures, e.g., 

implementation of BART limitations 

and motor vehicle tailpipe emissions. 

Chapter 6 of the SIP submittal discusses 

how emission estimates were 

determined and contains the emission 

inventory. Detailed estimates of the 

emissions, used in the modeling 

conducted by the WRAP and 

Washington, can be found at the WRAP 

Web site: http://vista.cira.colostate.edu/ 

TSS/Results/Emissions.aspx. 

There are a number of emission 

inventory source categories identified in 


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the Washington SIP submittal. The 

source categories vary with type of 

pollutant but include: Point, area, onroad mobile, off-road mobile, 

anthropogenic fire (prescribed forest 

fire, agricultural field burning, and 

residential wood combustion), natural 

fire, biogenic, road dust, fugitive dust 

and windblown dust. The 2002 baseline 

and 2018 projected emissions, as well as 

the net changes of emissions between 

these two years, are presented in Tables 

6–1 through 6–8 of the SIP submittal for 

sulfur dioxide (SO2), oxides of nitrogen 

(NOX), volatile organic carbon (VOC), 

organic carbon (OC), elemental carbon 

(EC), PM2.5, and ammonia. The methods 

that WRAP used to develop these 

emission inventories are described in 

more detail in the WRAP TSD. As 

explained in the WRAP TSD, emissions 

were calculated using best available 

data and approved EPA methods. See 

WRAP TSD section 12. 

Sulfur dioxide emissions in 

Washington come mostly from one coal 

fired power plant, oil refineries, 

aluminum plants, pulp and paper mills, 

and a cement plant. SO2 emission 

estimates for point sources come either 

from source test data (where available) 

or calculations based on the quantity 

and type of fuel burned. These 

industrial point sources contribute 64% 

of total statewide SO2 emissions. The 

second largest source category 

contributing to SO2 emissions in 

Washington is off-road mobile sources 

which contribute 17%. The remainder 

of SO2 emissions is from a variety of 

area sources including anthropogenic 

and natural fire. See Table 6–1 of the 

SIP submittal. 

Washington projects a 29% statewide 

reduction in point source S02 emissions 

by 2018 due to implementation of BART 

emission limitations and other 

Washington State and federal emission 

reduction actions. Washington projects 

total 2018 statewide SO2 emissions to be 

reduced by 40% below 2002 levels as a 

result of BART and additional 

reductions from mobile sources. 

NOX emissions in Washington come 

mostly from mobile sources, both onroad and off-road, which contribute 

76% of total statewide NOX emissions. 

The second largest source category of 

NOX emissions is point source 

emissions which accounts for 11% of 

statewide NOX emissions. Area source 

emissions account for less than 5% of 

statewide NOX emissions. 

Washington projects that 2018 total 

statewide emissions of NOX will be 46% 

lower than 2002 levels. Washington also 

projects on-road and off-road mobile 

source emissions to be reduced by 72% 

and 45% respectively by 2018, due to 

new federal motor vehicle emission 

standards and fleet turnover. 

Washington projects area source NOX

emissions to increase by 29% due to 

population growth. See Table 6–2 of the 

SIP submittal. 

Volatile organic compounds in 

Washington come mostly from biogenic 

emissions from forests, agriculture, and 

urban vegetation. The second largest 

source category in VOC emissions is onroad and off-road mobile sources. 

Washington projects 2018 statewide 

VOC emissions to increase by only 1% 

over 2002 levels. This very minor 

change is due to anticipated increases in 

area and point source emissions that 

would offset anticipated decreases in 

mobile sources and anthropogenic fire. 

See Table 6–3 of the SIP submittal. 

Organic carbon in Washington comes 

almost equally from wildfire at 35% and 

other area sources at 33%. 

Anthropogenic fire accounts for 20% of 

statewide organic carbon emissions. 

Washington projects 2018 statewide 

organic carbon emissions to decrease 

4% from 2002. Large reductions in 

emissions from mobile sources and 

anthropogenic fire are expected to be 

offset by increases in emissions from 

point and area sources due to 

population growth. See Table 5–4 of the 

SIP submittal. 

The largest source categories of 

elemental carbon are mobile sources, 

natural fire and area sources. 

Washington projects 2018 statewide 

elemental carbon emissions to decrease 

by 25% from 2002 emission levels. 

These projected reductions are the 

result of anticipated emission 

reductions in on-road mobile and offroad mobile emissions of 76% and 60% 

respectively. See Table 6–5 of the SIP 

submittal. 

Fine particulate is emitted from a 

variety of area sources which account 

for 95% of statewide fine particulate. 

Fugitive dust, from agriculture, mining, 

construction and roads, is the largest 

source category contributing 31% of 

total fine particulate. Anthropogenic 

and natural fire only account for 12% of 

the statewide fine particulate emissions. 

Point sources account for only 5% of 

statewide fine particulate. Washington 

projects that 2018 fine particulate 

emissions will increase by 20% over 

2002 emission levels due to population 

and industrial growth. Emissions 

increases are projected from point, area, 

and fugitive dust at 16%, 36%, and 34% 

respectively. See Table 6–6 of the SIP 

submittal. 

Ammonia does not directly impair 

visibility but can be a precursor to the 

formation of particulate in the 

atmosphere through chemical reaction 

with SO2 and NOX to form a ‘‘secondary 

aerosol’’ of ammonium sulfate and 

ammonium nitrate. Area sources are the 

primary source category contributing to 

ammonia emissions and account for 

77% of total ammonia emissions. 

Washington projects ammonia 

emissions in 2018 to increase by 8% 

over 2002 emission levels with 

increasing emissions in all categories 

except for anthropogenic fire which 

Washington projects to decrease by 

30%. See Table 6–8 of the SIP submittal. 

EPA believes Washington’s inventory 

of baseline emissions is accurate and 

comprehensive as Washington used the 

most current and appropriate methods 

at the time it was developed. We note 

that additional emission reductions may 

occur between the baseline year and 

2018 that are not accounted for in the 

2018 inventory. For example, no 

emission reductions from the new 

regulations relating to the International 

Maritime Organization Emission Control 

Area (ECA) on the west coast of the 

United States and Canada were taken 

into account in the 2018 emission 

estimates (ECA Amendments to 

MARPOL Annex VI). These emissions 

are outside the modeling domain but 

may impact the visibility in the Class I 

areas. Washington’s projected 2018 

emissions inventory also did not 

account for the now anticipated NOX

emission reductions from the TransAlta 

NOX BART determination recently 

approved into the SIP. 

The federal Better than BART 

determination proposed today for 

Tesoro identifies SO2 emission 

reductions of 1068 t/y that were not 

included in the 2018 emission 

inventory. Also, the proposed federal 

Better than BART emission limits for 

Alcoa’s Intalco operations, if finalized, 

are expected to reduce SO2 emissions 

from the baseline year emission 

inventory by 1310 t/y. The sum total of 

the expected NOX reductions from the 

TransAlta BART determination and the 

proposed FIP actions for Tesoro and 

Intalco are: 3688 t/y NOX from 

TransAlta and 2378 t/y SO2 Tesoro and 

Intalco. 

D. Sources of Visibility Impairment in 

Washington Class I Areas 

Each pollutant species has its own 

visibility impairing property; 1 mg/m3 of 

sulfate, for example, is more effective in 

scattering light than 1 mg/m3 of organic 

carbon and therefore impairs visibility 

more than organic carbon. Following the 

approach recommended by the WRAP 

and as explained more fully below, 

Washington used a two-step process to 

identify the contribution of each source 

or source category to existing visibility 


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impairment. First, ambient pollutant 

concentration by species (sulfate, 

nitrate, organic carbon, fine particulate, 

etc.) was determined from the IMPROVE 

sampler in each Class I area. These 

concentrations were then converted into 

light extinction values to distribute 

existing impairment among the 

measured pollutant species. This 

calculation used the ‘‘improved 

IMPROVE equation’’ (See section 2.C of 

the WRAP TSD) to calculate extinction 

from each pollutant specie 

concentration. Total extinction, in 

inverse megameters, was then converted 

to deciview using the equation defining 

deciview. 

After considering the available 

models, the WRAP and western states 

selected two source apportionment 

analysis tools. The first source 

apportionment tool was the 

Comprehensive Air Quality Model with 

Extensions (CAMX) in conjunction with 

PM Source Apportionment Technology 

(PSAT). This model uses emission 

source characterization, meteorology 

and atmospheric chemistry for aerosol 

formation to predict pollutant 

concentrations in the Class I area. The 

predicted results are compared to 

measured concentrations to assess 

accuracy of model output. CAMX PSAT 

modeling was used to determine source 

contribution to ambient sulfate and 

nitrate concentrations. Thus, the WRAP 

used state-of-the-science source 

apportionment tools within a widely 

used photochemical model. EPA has 

reviewed the PSAT analysis and 

considers the modeling, methodology, 

and analysis acceptable. See section 6.A 

of the WRAP TSD. 

The second tool was the Weighted 

Emissions Potential (WEP) model, used 

primarily as a screening tool to decide 

which geographic source regions have 

the potential to contribute to haze at 

specific Class I areas. WEP does not 

account for atmospheric chemistry 

(secondary aerosol formation) or 

removal processes, and thus is used for 

estimating inert particulate 

concentrations. The model uses back 

trajectory wind flow calculations and 

resident time of an air parcel over each 

area source to determine source area 

and source category and location for 

ambient organic carbon, elemental 

carbon, PM2.5, and coarse PM 

concentrations. These modeling tools 

were the state-of-the-science and EPA 

has determined that these tools were 

appropriately used by WRAP for 

regional haze planning. Description of 

these tools and our evaluation of them 

are described in more detail in section 

6 of the WRAP TSD. 

Chapter 8 of the Washington Regional 

Haze SIP submittal presents the light 

extinction for the base year at each Class 

I area by visibility impairing pollutant 

species for the average of the 20% worst 

days and the 20% best days. The most 

significant visibility impairing pollutant 

species identified for all Class I areas 

are: sulfate, nitrate, and organic carbon 

mass. For the Pasayten Wilderness area 

elemental carbon is also presented. See 

chapter 8 of the SIP submittal. 

Tables 8–1 and 8–2 of the SIP 

submittal provides the percent 

contribution of ‘‘in state’’ sources to 

impairment in each Class I area on the 

20% worst and best days for sulfate and 

nitrate for both 2002 and 2018. In the 

discussion below of each Class I area, 

the source category with the greatest 

impact will be identified. 

Olympic National Park 

Visibility at Olympic National Park is 

represented by the OLYM1 IMPROVE 

monitoring site. On the 20% most 

impaired days at Olympic National 

Park, sulfate accounts for 39%, nitrate 

accounts for 19%, and organic carbon 

accounts for 28% of impairment. On the 

20% least impaired days, sulfate 

accounted for 36%, nitrate accounted 

for 17%, and organic carbon accounted 

26% of impairment. See section 8.1 of 

the SIP submittal. 

Sulfate on the 20% most impaired 

days at Olympic National Park: 37% is 

from outside the modeling domain, 21% 

originates from offshore Pacific offshore 

sources, and 21% from Canadian 

sources. Only 25% of the sulfate 

originates from sources in Washington. 

Washington point sources account for 

15%, mobile sources 7%, and area 

sources 3% of sulfate impairment on the 

20% most impaired days. Sulfate on the 

20% least impaired days at Olympic 

National Park: 37% of the sulfate 

originates from outside the modeling 

domain, 34% from sources in 

Washington, 21% from sources in 

Canada, and 15% from Pacific offshore 

sources. Washington point sources 

account for 18% of the sulfate 

impairment on the 20% least impaired 

days. 

Nitrate on the 20% most impaired 

days at Olympic National Park: 53% of 

the nitrate originates from sources in 

Washington, 21% originates in Canada, 

and 15% from the Pacific offshore. See 

Figure 8–5 of the SIP submittal. Of the 

sources in Washington, 40% is 

attributed to mobile sources, 9% to 

point sources, and 3% to area sources. 

Nitrate on the 20% least impaired days 

at Olympic National Park: 45% of the 

nitrate is from mobile sources, 8% from 

point sources, and 4% from area sources 

in Washington. See Table 8–2 of the SIP 

submittal. 

Organic carbon is the second most 

significant pollutant impairing visibility 

in Olympic National Park. Most of the 

organic carbon originates in the Puget 

Sound area from area sources including 

aerosol formation from volatile organic 

compounds, natural and anthropogenic 

fire, and mobile sources. See section 

8.1.3 of the SIP submittal. 

North Cascades National Park and 

Glacier Peak Wilderness Area 

These two Class I areas are 

represented by one IMPROVE monitor 

(NOCA1) located in the upper Skagit 

Valley. On the 20% most impaired days, 

sulfate accounts for 26%, nitrate 

accounts for 5%, and organic carbon 

accounts for 58% of impairment. On the 

20% least impaired days, sulfate 

accounted for 45%, nitrate accounted 

for 14%, and organic carbon accounted 

to 21% of impairment. See section 8.2 

of the SIP submittal. 

Sulfate on the 20% most impaired: 

32% of the sulfate originates from 

outside the modeling domain, 29% 

originates from sources in Washington, 

and 28% originates in Canada. See 

Figure 8–12 of the SIP submittal. Point 

sources in Washington contribute 20%, 

mobile sources contribute 5%, and area 

sources contribute 3% of the sulfate in 

these two areas. See Table 8–1 of the SIP 

submittal. Sulfate on the 20% least 

impaired days: 40% of the sulfate 

originates from outside the modeling 

domain, and 39% originates from 

sources in Washington. Of the sources 

in Washington, 23% comes from point 

sources, 10% from mobile sources, 5% 

from area sources (excluding fire), and 

2% from fire. See Table 8–1 and Figure 

8–15 of the SIP submittal. 

Nitrate on the 20% most impaired 

days: 46% of the nitrate originates from 

sources in Washington, 27% from 

Canada, 16% from outside the modeling 

domain, and 7% from Pacific offshore 

sources. Of the sources in Washington, 

34% is from mobile sources, 6% from 

point sources, 3% from fire, and 2% 

from area sources. See Table 8–2 and 

Figure 8–16 of the SIP submittal. Nitrate 

on the 20% least impaired days: 63% of 

the nitrate originates from sources in 

Washington, 13% from sources in 

Oregon and 10% originates from sources 

outside the modeling domain. Of the 

sources in Washington, 51% comes 

from mobile sources, 6% from point 

sources, 3% from area sources, and 2% 

from fire. See Table 8–2 and Figure 8– 

18 of the SIP submittal. 

Organic carbon accounts for 56% of 

the impairment on the 20% most 

impaired days. Figure 8–21 shows that 


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most organic carbon originates in 

Washington with a smaller fraction 

originating in Canada. Most of the 

organic carbon originates in the Puget 

Sound area from area sources including 

aerosol formation from volatile organic 

compounds, natural and anthropogenic 

fire, and mobile sources. 

Alpine Lakes Wilderness Area 

Alpine Lakes Wilderness Area is 

represented by the SNPA1 IMPROVE 

monitoring site. On the 20% most 

impaired days, sulfate accounts for 

34%, nitrate accounts for 23% and 

organic carbon accounts for 30% of 

impairment. On the 20% least impaired 

days, sulfate accounted for 40%, nitrate 

accounted for 18% and organic carbon 

accounted for 16% of impairment. See 

section 8.3 of the SIP submittal. 

Sulfate on the 20% most impaired 

days: 38% of the sulfate originates from 

outside the modeling domain, 32% from 

sources in Washington, 17% from 

Canada, and 8% from Pacific offshore. 

Of the sources in Washington, 16% is 

from point sources, 10% from mobile 

sources, and 5% from area sources. See 

Table 8–1 and Figure 8–23 of the SIP 

submittal. Sulfate on the 20 least 

impaired days: 42% of the sulfate 

originates from sources in Washington, 

38% from outside the modeling domain, 

and 8% from Pacific offshore. Of the 

sources in Washington, 26% is from 

point sources, 11% from mobile 

sources, and 5% from area sources. See 

Table 8–1 and Figure 8–25 of the SIP 

submittal. 

Nitrate on the 20% most impaired 

days: 68% of the nitrate originates from 

sources in Washington, 9% from outside 

the modeling domain, and 5% from 

Canada. Of the sources in Washington, 

56% is from mobile sources, 5% from 

point sources and 3% from area sources 

and 3% from fire. See Table 8–2 and 

Figure 8–27 of the SIP submittal. Nitrate 

on the 20% least impaired days: 65% of 

the nitrate originates from sources in 

Washington, 15% from sources in 

Oregon, 9% from outside the modeling 

domain, and 7% from offshore Pacific 

sources. Of the sources in Washington, 

52% is from mobile sources, 7% from 

point sources, 3% from area sources, 

and 1% from fire. See Table 8–2 of the 

SIP submittal. 

Organic carbon on the 20% most 

impaired days is dominated by area 

sources in Washington. See Figure 8.2.3 

and Table 8–3 of the SIP submittal. 

Organic carbon on the 20% least 

impaired days is dominated by area 

sources in Washington. See Table 8–3 of 

the SIP submittal. 

Mount Rainier National Park 

In Mount Rainier National Park, as 

monitored at the MORA1 IMPROVE 

monitoring site, sulfate is the largest 

contributor to visibility impairment on 

the most impaired days, as well as on 

the least impaired days. On the 20% 

most impaired days, sulfate accounts for 

46%, nitrate accounts for 10%, and 

organic carbon accounts for 29% of 

impairment. On the 20% least impaired 

days, sulfate accounted for 40%, nitrate 

accounted for 10%, and organic carbon 

accounted to 23% of impairment. See 

section 8.4 of the SIP submittal. 

Sulfate on the 20% most impaired 

days: 42% originates from sources in 

Washington, 31% originates from 

outside the modeling domain, 12% from 

Canada, and 12% from Pacific offshore. 

See Figure 8–34 of the SIP submittal. Of 

the sources in Washington, 25% is from 

point sources, 11% from mobile 

sources, and 6% from area sources. See 

Table 8–1 of the SIP submittal. Sulfate 

on the 20% least impaired days: 36% of 

the sulfate originates from sources in 

Washington, 38% from outside the 

modeling domain, 16% from sources in 

Oregon, and 8% from Pacific offshore. 

Of the sources in Washington, 25% is 

from point sources, 7% from mobile 

sources, and 3% from area sources. See 

Table 8–1 and Figure 8–36 of the SIP 

submittal. 

Nitrate on the 20% most impaired 

days: Washington sources account for 

78% of nitrate impairment. Of the 

Washington sources, 62% is from 

mobile sources, 9% from point sources, 

5% from area sources, and 1% from fire. 

Nitrate on the 20% least impaired days: 

Washington sources account for 42% 

and sources in Oregon accounts for 35% 

of nitrate impairment. Of the sources in 

Washington, 32% is from mobile 

sources, 7% from point sources, 2% 

from area sources, and 1% from fire. 

On the 20% most impaired days, 

almost all the organic carbon originates 

from sources located in Washington. See 

Figure 8–43 of the SIP submittal. On the 

20% least impaired days, almost all the 

organic carbon originates from sources 

in Washington with some contribution 

from sources in Oregon. See Figure 8– 

44 of the SIP submittal. 

Goat Rocks and Mount Adams 

Wilderness Areas 

Both wilderness areas are represented 

by one IMPROVE monitoring site 

WHPA1. On the 20% most impaired 

days at these areas, sulfate accounts for 

37%, nitrate accounts for 13%, and 

organic carbon accounts for 36% of 

impairment. On the 20% least impaired 

days, sulfate accounts for 49%, nitrate 

accounts for 13%, and organic carbon 

accounts for 14% of impairment. See 

section 8.5 of the SIP submittal. 

Sulfate on the 20% most impaired 

days: 39% originates from sources 

outside the modeling domain, 29% 

originates from sources in Washington, 

and 18% from Canada. See Figure 8–45 

of the SIP submittal. Of the sources in 

Washington, 16% is from point sources, 

8% from mobile sources, and 4% from 

area sources. See Table 8–1 of the SIP 

submittal. Sulfate on the 20 least 

impaired days: 44% of the sulfate 

originates from sources in Washington, 

29% from outside the modeling domain, 

16% from sources in Oregon, and 8% 

from Pacific offshore. Of the sources in 

Washington, 30% is from point sources, 

9% from mobile and 4% from area 

sources. 

Nitrate on the 20% most impaired 

days: 64% originates from sources in 

Washington and 13% from sources 

outside the modeling domain. Of the 

sources in Washington, 52% is from 

mobile sources, 6% from point sources, 

4% from area sources, and 2% from fire. 

See Table 8–2 and Figure 8–49 of the 

SIP submittal. Nitrate on the 20% least 

impaired days: 49% originates from 

sources in Washington, and 29% from 

sources in Oregon. Of the sources in 

Washington, 38% is from mobile 

sources, 7% from point sources, 2% 

from area sources, and 1% from fire. See 

Table 8–2 and Figure 8–51 of the SIP 

submittal. 

On the 20% most impaired days, 

organic carbon is the second largest 

contributor to impairment in the Goat 

Rocks and Mt. Adams Wilderness Areas. 

Most of the OMC originates in 

Washington, with Oregon sources 

contributing minor amounts. See Figure 

8–54 of the SIP submittal. On the 20% 

least impaired days, organic carbon 

sources in Washington, and Oregon 

contribute almost equally. See Figure 8– 

55 of the SIP submittal. 

Pasayten Wilderness Area 

The Pasayten Wilderness Area is 

monitored by the PASA1 IMPROVE 

monitor. On the 20% most impaired 

days, 20% is due to sulfate, nitrate 

accounts for 8%, and organic carbon 

accounts for 56% of impairment. On the 

20% least impaired days, sulfate 

accounts for 49%, nitrate accounts for 

17%, and organic carbon accounts for 

17% of impairment. See section 8.6 of 

the SIP submittal. 

Sulfate on the 20% most impaired 

days: 50% originates from outside the 

modeling domain, 22% from Canada, 

and 18% from Washington. Of the 

Washington sources, 8% is from point 

sources, 4% is from mobile sources, 4% 


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from fire and 2% from area sources. See 

section 8.6 and Table 8–1 of the SIP 

submittal. Sulfate on the 20% least 

impaired days: 40% originates from 

outside the modeling domain, 36% from 

Washington sources, and 10% from 

Canadian sources. Of the sources in 

Washington, 21% is from point sources, 

10% from mobile sources, and 5% from 

area sources. 

Nitrate on the 20% most impaired 

days: 48% originates from sources in 

Washington, 17% from outside the 

modeling domain, and 13% from 

Canadian sources. Of the sources in 

Washington, mobile sources contribute 

36%, natural fire and biogenic sources 

8%, and 3% point sources. Nitrate on 

the 20% least impaired days: 62% 

originates from sources in Washington, 

15% from Oregon, and 85 from outside 

the modeling domain. Of the sources in 

Washington, 49% is from mobile 

sources, 6% from point sources, and 4% 

from natural and biogenic sources. 

On the 20% most and least impaired 

days, organic carbon is responsible for 

over half of the total impairment. 

Natural fire in Washington is 

responsible for almost all the organic 

carbon and a small portion due to 

Washington area sources. See Figure 8– 

65 of the SIP submittal. 

EPA is proposing to find that 

Washington, using the WRAP analysis, 

appropriately identified the pollutant 

species and source categories 

contributing to impairment to the Class 

I areas in Washington. See WRAP TSD. 

E. Best Available Retrofit Technology 

1. BART-Eligible Sources in Washington 

The first phase of a BART evaluation 

is to identify all the BART-eligible 

sources within the Washington’s 

boundaries. Table 11–1 in the SIP 

submission presents the list of all 

BART-eligible sources located in 

Washington. These sources and their 

source categories are: 

Source Category 

Graymont Western US INC (Tacoma) ..................................................... Lime plants. 

TransAlta Centralia Generation, LLC ....................................................... Fossil fuel-fired steam electric plants with a heat input greater than 250 

MMBtu per hour. 

Longview Fibre Co—Longview ................................................................. Kraft Pulp Mills. 

Weyerhaeuser Co—Longview .................................................................. Kraft Pulp Mills. 

Fort James Camas LLC (now Georgia Pacific Corporation—Camas) .... Kraft Pulp Mills. 

Goldendale Aluminum .............................................................................. Primary Aluminum Ore Reduction Plants. 

Port Townsend Paper Co ......................................................................... Kraft Pulp Mills. 

Simpson Tacoma Kraft ............................................................................. Kraft Pulp Mills. 

Lafarge North America (Seattle) .............................................................. Portland Cement Plants. 

Intalco (Ferndale) ..................................................................................... Primary Aluminum Ore Reduction Plants. 

Alcoa Wenatchee Works .......................................................................... Primary Aluminum Ore Reduction Plants. 

BP Cherry Point Refinery (Ferndale) ....................................................... Petroleum Refineries. 

Tesoro Refining and Marketing (Anacortes) ............................................ Petroleum Refineries. 

Puget Sound Refining Company .............................................................. Petroleum Refineries. 

Conoco-Philips Company (Ferndale) ....................................................... Petroleum Refineries. 

2. Sources Subject to BART 

The second phase of the BART 

determination process is to identify 

those BART-eligible sources that may 

reasonably be anticipated to cause or 

contribute to any impairment of 

visibility at any Class I area and are, 

therefore, subject to BART. As 

explained above, EPA has issued 

guidelines that provide states with 

guidance for addressing the BART 

requirements. 40 CFR part 51 appendix 

Y; see also 70 FR 39104 (July 6, 2005). 

The BART Guidelines describe how 

states may consider exempting some 

BART-eligible sources from further 

BART review based on dispersion 

modeling showing that the sources 

contribute to visibility impairment 

below a certain threshold. Washington 

conducted dispersion modeling for all 

the BART-eligible sources to determine 

the visibility impacts on Class I areas. 

The BART Guidelines advises states 

to set a contribution threshold to assess 

whether the impact of a single BARTeligible source is sufficient to cause or 

contribute to visibility impairment at a 

Class I area. Generally, states may not 

establish a contribution threshold that 

exceeds 0.5 dv impact. 70 FR 39161. 

Washington established a contribution 

threshold of 0.5 dv. The 0.5 dv 

threshold is consistent with the 

threshold used by all other states in the 

WRAP. Any BART-eligible source with 

an impact of greater than 0.5 dv in any 

mandatory Class I area, including Class 

I areas in other states, would be subject 

to a BART analysis and BART emission 

limitations. 

To determine those sources exceeding 

this contribution threshold and thus 

subject to BART, Washington used the 

CALPUFF dispersion modeling. The 

dispersion modeling was conducted in 

accord with the ‘‘Washington, Oregon, 

Idaho BART Modeling Protocol’’. This 

Protocol was jointly developed by the 

states of Idaho, Washington, Oregon and 

EPA and has undergone public review. 

The Protocol was used by all three states 

in determining which BART-eligible 

sources are subject to BART. See 

appendix H of the SIP submittal for 

details of the modeling protocol, its 

application and results. 

The SIP submittal contained no 

rationale for adopting a 0.5 dv threshold 

for determining whether a BARTeligible source may be reasonably 

anticipated to cause or contribute to any 

visibility impairment in a mandatory 

Class I area. Although a number of 

stakeholders may have agreed that a 0.5 

dv threshold is appropriate, and other 

states in the Region may have adopted 

such a threshold, such agreement does 

not provide sufficient basis for 

concluding that such a threshold was 

appropriate in the case of Washington. 

Based on EPA’s review of the BARTeligible sources in Washington, 

however, and for the reasons discussed 

below, EPA is proposing to find that a 

0.5 dv threshold is appropriate, given 

the specific facts in Washington. 

Relying on modeling that each source 

conducted using the ‘‘Idaho-OregonWashington BART Modeling Protocol’’ 

that was reviewed by Washington, the 

visibility impact of each source was 

determined on all Class I areas within 

300 km of all but one of the BARTeligible sources. See Table 11–3 of the 

SIP submittal for those sources with less 

than a 0.5 dv impact. The BART-eligible 

sources are generally widely distributed 

across the Washington. Given the 

relatively limited impact on visibility 

from these sources, Washington could 

have reasonably concluded that a 0.5 dv 

threshold was appropriate for capturing 


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those BART-eligible sources with 

significant impacts on visibility in Class 

I areas. For these reasons, EPA is 

proposing to approve the 0.5 dv 

threshold adopted by Washington in its 

Regional Haze SIP. 

In the BART Guidelines, EPA 

recommended that states ‘‘consider the 

number of BART sources affecting the 

Class I areas at issue and the magnitude 

of the individual sources’ impacts. In 

general, a larger number of BART 

sources causing impacts in a Class I area 

may warrant a lower contribution 

threshold.’’ 70 FR 39104, 39161 (July 6, 

2005). In developing its Regional Haze 

SIP, Washington requested 14 of the 15 

BART-eligible sources to model their 

respective impact on the Class I areas 

within a 300 km radius. For Goldendale 

Aluminum, Washington relied on 

modeling conducted by EPA, rather 

than requesting the source to model its 

impact because the facility has not 

operated since 2001. 

Below is the list of sources that 

Washington determined were subject to 

BART and the Class I area for which the 

source has the greatest visibility impact 

(average of the three annual 8th highest 

daily value over 2003–2005 baseline): 

BP Cherry Point Refinery, Blaine Wa ................................................................................................ 0.9 dv at Olympic National Park 

Intalco Aluminum Corp. Ferndale .................................................................................................... 2.4 dv at Olympic National Park. 

Tesoro Refining and Marketing Co .................................................................................................... 1.7 dv at Olympic National Park. 

Port Townsend Paper Co .................................................................................................................... 1.2 dv at Olympic National Park. 

Lafarge North America ....................................................................................................................... 3.16 dv at Olympic National Park. 

TransAlta Centralia Generation LLC ................................................................................................. 5.5 dv at Mt. Rainier National Park. 

Weyerhaeuser Longview .................................................................................................................... 1.0 dv at Mt. Rainier National Park. 

3. Washington Source Specific BART 

Analyses 

A BART determination was 

conducted for each of the sources 

subject to BART. At Washington’s 

request, each source conducted its own 

BART analysis and prepared a report 

which Ecology then reviewed and used 

to make a case-by-case BART 

determination. In conducting the BART 

analysis, Washington considered all five 

BART factors. Washington explained 

that in order for it to select a specific 

control technology as BART, it must be 

technically feasible, cost effective, 

provide a visibility benefit, and have 

minimal potential for adverse non-air 

quality impacts. Washington further 

explained that normally visibility 

improvement is only one of the factors 

but if two available and technically 

feasible controls are essentially 

equivalent in cost effectiveness and 

collateral impacts then visibility may 

become the deciding factor. See e.g. 

Washington Regional Haze SIP 

submittal L–13. The BART 

determination, including controls, 

emission limits and compliance 

deadlines are reflected in an enforceable 

Order issued to each source. The BART 

Orders are included in the SIP 

submittal. Below is a table of 

compliance dates for each BART Order. 

Facility Compliance date 

BP Cherry Point Refinery: Compliance for all PM, NOX, and SO2 emission limits.July 7, 2010. 

Intalco Aluminum Corp. Compliance with all PM, NOX, and SO2 emission limits.November 15, 2010. 

Tesoro Refining and Marketing Company 

Compliance for all PM and SO2 emission limits ...................................... July 7, 2010. 

Compliance with NOX emission limits (unit F–103) ................................. September 30, 2015. 

Port Townsend Paper Corp. 

Compliance with emission limits for PM, NOX, and SO2 ......................... October 20, 2010. 

Lafarge North America, Inc. 

Compliance with all PM emission limits ................................................... July 28, 2010. 

Compliance with SO2 emission limits ....................................................... No than April 30, 2011, or 90 days after the kiln is restarted if the kiln 

is in temporary cessation on February 1, 2011. 

Compliance with NOX emission limits ...................................................... No later than the date Lafarge completes optimization of the NOX control system per specified criteria. 

Weyerhaeuser Corp. 

Compliance with emission limits for PM, NOX, and SO2 ......................... July 7, 2010. 

Below is a summary of Washington’s 

BART analysis and determination for 

each of the seven sources subject to 

BART. Additional detail regarding the 

analysis for each source, unit and 

pollutant may be found in the 

Washington Regional Haze SIP 

submittal, appendix L. 

a. British Petroleum, Cherry Point 

Refinery 

The BP Cherry Point Refinery located 

near Ferndale, Washington, is a BARTeligible source subject to BART. Its 

maximum visibility impact of 0.9 dv is 

at Olympic National Park. Impacts at all 

other Class I areas within 300 km are 

less than 0.5 dv. See Table 11–4 of the 

SIP submittal. As summarized below, 

Washington and BP completed a BART 

analysis for all BART-eligible units at 

the refinery. Washington’s BART 

determination, issued to BP as BART 

Compliance Order No. 7836 (BP Cherry 

Point BART Compliance Order), is 

included in the Washington’s Regional 

Haze SIP submission. See Washington 

Regional Haze SIP submittal, page L–47. 

Additionally, the operating permit No. 

7836 included with the SIP submittal 

contains emission control requirements 

for non-BART units beyond those 

required for BART. 

As a component of a national consent 

decree between BP and the EPA, 

(United States District Court for the 

Northern District of Indiana, Hammond 

Division; Civil No. 2:96CV 095RL) most 

of the refinery’s heaters and boilers have 

been evaluated for upgraded and retrofit 

control technology. As required under 

the consent decree, many heaters had 

been retrofitted with low-NOX burners 

(LNBs) or ultra-low-NOX burners 

(ULNBs). Washington considered these 

federally enforceable upgrades as 

existing control in the BART analysis. 


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7Power Boiler #1 and Power Boiler #3 were 

replaced in 2009 by Boilers #6 and #7. Boilers #6 

and #7 were not considered in the BART 

determination as they are not BART-eligible and 

were permitted under PSD. The BART Order 7836 

issued to BP July 7, 2010, Finding C and Condition 

7 ‘‘Other Requirements’’ requires decommissioning 

of Boilers #1 and #3 no later than March 27, 2010. 

One general consideration in 

determining the cost effectiveness of all 

potential BART control technologies for 

BP is the ability to install the retrofit 

technology during a regularly scheduled 

turnaround or maintenance period at 

the facility. Turnaround is the term used 

to describe when the refinery is 

shutdown periodically, on 

approximately 5 year intervals, for 

routine maintenance and process 

equipment upgrades. A retrofit during a 

routine turnaround would not incur the 

extra costs associated with loss of 

revenues during shutdown. Washington 

determined the cost effectiveness values 

of installing controls both during 

routine turnaround and outside the 

normal turnaround period. 

Table 1–1 of the BP Cherry Point 

BART determination of appendix L of 

the SIP submittal identifies all emitting 

units at the facility and indicates 

whether the units are BART-eligible. 

Twenty-one of the refinery’s emission 

units were determined to be BARTeligible and subject to BART. These 

units are as follows: 

Heaters and Boilers: 7

• Crude Charge Heater 

• South Vacuum Heater 

• Naphtha Hydrodesulfuriztion 

(HDS) Charge Heater 

• Naphtha HDS Stripper Reboiler 

• #1 Reformer Heaters 

• Coker Charge Heater (#1 North) 

• Coker Charge Heater (#2 South) 

• 1st Stage Hydrocracker (HC) 

Fractionator Reboiler 

• 2nd Stage HC Fractionator Reboiler 

• R–1 HC Reactor Heater 

• R–4 HC Reactor Heater 

• #1 Diesel HDS Charge Heater 

• Diesel HDS Stabilizer Reboiler 

• Steam Reforming Furnace #1 

• Steam Reforming Furnace #2 

Sulfur Recovery Systems 

• Two Sulfur Recovery Units (SRUs) 

and one of the associated Tail Gas Units 

(TGU) 

Flares 

• High Pressure Flare 

• Low Pressure Flare 

Material Handling 

• Green Coke Load Out equipment 

General Discussion of NOX Control 

Technologies Considered for Heaters 

and Boilers at BP 

BP conducted a source category 

evaluation of all available control 

technologies for this source category to 

eliminate those that are infeasible. All 

available NOX control technologies 

identified for further evaluation were 

based on the EPA RACT/BACT/LAER 

Clearinghouse (RBLC). See appendix L 

of the SIP submittal at L–29. The table 

below identifies those NOX control 

technologies and indicates which were 

determined to generally be technically 

feasible: 

Technology Sources to which they would potentially be 

applicable Is it technically Feasible? 

Selective Catalytic Reduction (SCR) ................. All Heaters ........................................................ Yes. 

Low-NOX Burners (LNB) or Ultra Low NOX

Burners (ULNB).

All Heaters ........................................................ Yes. 

Selective non-catalytic Reduction (SNCR) ........ All Heaters ........................................................ No. Exhaust gas temperatures vary too much 

and temperatures not in range for SNCR 

operation. 

External Flue Gas Recirculation (FGR) ............. All Heaters and Boilers .................................... No—Potential safety Issues. 

Low Excess Air 

Operation—CO 

Control 

All Units ............................................................ No—Potential safety issues and small operating range. 

Steam Injection .................................................. All Units ............................................................ Not feasible except 1st Stage HC Fractionator 

Reboiler. 

Lower Combustion Air 

Preheat ..............................................................

Units with air preheat ....................................... No. cooler air is introduced into the heater as 

combustion air, the heater has to utilize additional fuel to heat the air for the combustion process which ends up negating any 

NOX reductions generated. 

CETEK—Descale & Coat Tubes ....................... Units with externally scaled tubes .................... No. This technique is only applicable to units 

where the heat transfer tubes are externally 

scaled. 

Modify Existing Burners to Improve NOX emissions.All ...................................................................... Yes. 

Evaluation of Technically Feasible 

NOX Controls for specific heaters and 

boilers Crude Charge Heater (NOX): The 

Crude Charge Heater currently uses 

conventional burners. Washington 

determined that a LNB is technically 

infeasible for this specific emission unit 

due to the high flame temperatures and 

heat density needed for the process. 

LNB would lower the flame temperature 

below that needed for the process and 

flame impingement from LNB would derate the heater and reduce throughput. 

Washington determined that while SCR 

is technically feasible for the Crude 

Charge Heater, it is not cost effective at 

$14,658/ton during scheduled 

turnaround and $32,000/ton during 

non-scheduled turnaround. Washington 

determined BART for NOX for the Crude 

Heater is existing conventional burners. 

South Vacuum Heater (NOX): The 

South Vacuum Heater currently has 

ultra low-NOX burners. These burners 

were installed in 2005 in accordance 

with the national consent decree. 

Washington determined that SCR is not 

cost effective for the South Vacuum 

Heater regardless of whether it was 

installed during a scheduled turnaround 

or not. Cost effectiveness during a 

scheduled turnaround or outside 

turnaround is $54,551/ton and $82,643/ 

ton respectively. Washington 

determined BART for this unit is the 

existing ULNB. The NOX emission limit 

is 0.08 lb/MMBtu. 

Naphtha HDS Charge Heater & 

Naphtha HDS Stripper Reboiler (NOX): 

Both of these boilers currently employ 

conventional burners in relatively small 

fire boxes. LNB is deemed infeasible on 


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both of these units due to small size of 

the heater and because, with LNBs, 

flame impingement on the boiler tubes 

would cause premature failure. SCR is 

not cost effective at $46,667/ton during 

turnaround and $31,467/ton during 

non-turnaround. Washington 

determined BART for NOX is the 

existing conventional burners. 

#1 Reformer Heater (NOX): The #1 

Reformer Heater has a complex design 

with four independent fire boxes and 

two stacks. It is currently fitted with 

conventional burners. LNB is infeasible 

due to small size of firebox and because 

the longer flame length of LNB would 

cause flame impingement on the heater 

tubes and lead to premature failure. SCR 

is not cost effective at $15,253/ton 

during turnaround and $17,299/ton 

during non-turnaround. Washington 

determined BART for NOX is the current 

conventional burners. 

Coker Charge Heater (#1 North) and 

Coker Charge Heater (#2 South) (NOX): 

The Coker Heaters are both currently 

using early design (1999) LNB which 

incorporate staged air combustion and 

flue gas recirculation. LNB of a newer 

design is not cost effective at $31,301/ 

ton for the #1 North Heater and $30,762/ 

ton for the #2 South Heater. SCR is not 

cost effective at $35,202/ton for the #1 

North Heater and $34,597/ton for the #2 

South Heater. Washington found that 

BART for NOX is the existing LNB with 

staged air combustion and flue gas 

recirculation. The NOX emission limit 

for these units is 0.08 lb/MMBtu 

#1 Diesel HDS Charge Heater and 

Diesel HDS Stabilizer Reboiler (NOX): 

The heater and reboiler are currently 

fitted with ULNBs to comply with the 

consent decree. SCR is not cost effective 

at $192,585/ton for the #1 Diesel HDS 

Charge Heater and $145,094/ton for the 

Diesel HDS Stabilizer Reboiler. 

Washington determined BART for NOX

for the Diesel HDS Charge Heater is the 

existing ULNB with an emission limit of 

0.040 lb/MMBtu. 

Washington determined BART for 

NOX for the Stabilizer Reboiler Heater is 

existing ULNBs with an emission limit 

of 26 ppmv (dry basis corrected to 7% 

O2) based on a 24-hour rolling average. 

If this concentration is exceeded, a 

secondary limit to demonstrate 

compliance is 2.2 lb/hour based on a 24- 

hour rolling average. 

Steam Reforming Furnace #1 (North 

H2 Plant) and Steam Reforming Furnace 

#2 (South H2 Plant) (NOX): These units 

currently use conventional burners. 

LNB is not cost effective for these two 

furnaces at $21,234/ton for the North H2 

Plant and $21,682/ton for the South H2 

Plant. SCR is not cost effective at 

$28,378/ton for the North Plant and 

$28,900/ton for the South Plant. LNB 

with SCR is not cost effective at 

$29,555/ton and $30,104/ton. 

Washington determined that BART for 

NOX for these units is the existing 

conventional burners. 

R–1 HC Reactor Heater (NOX): This 

heater currently operates with ULNB in 

accord with consent decree. In the 

general evaluation of control 

technologies for heaters and boilers BP 

determined that the only feasible 

technology with greater control 

efficiency than ULNB is SCR. SCR is not 

cost effective at $214,726/ton NOX

removed. Washington determined BART 

is the existing ULNB with a NOX

emission limit of 26 ppm by volume dry 

basis corrected to 7% O2 on a 24-hour 

rolling average. Should the 

concentration limit be exceeded, the 

mass emission limit is 3.6 lb/hr on a 24- 

hour rolling average. 

R–4 HC Reactor Heater (NOX): The R– 

4 HC Reactor Heater is currently 

operating with conventional burners. 

LNBs are not technically feasible due to 

high heat density, flame impingement, 

and flame shape that would exceed the 

American Petroleum Institute (API) 

guidelines for burner spacing. SCR is 

not cost effective at $36,620/ton. 

Washington determined that BART is 

the current burners. 

1st Stage HC Fractionator Reboiler 

(NOX BART): The 1st stage HC 

Fractionator Reboiler is currently 

operating with conventional burners. 

The BART cost effectiveness analysis to 

install ULNBs is estimated by BP to be 

$12,044/ton. Washington determined 

this value to not be cost effective, 

however BP volunteered to install 

ULNB on this unit to achieve 0.05 lb 

NOX/MMBtu. Washington did not 

propose ULNB as BART, but rather said 

in the BART analysis report the 

emission reductions would be 

considered in a future SIP submittal as 

further reasonable progress. (appendix 

L, at L–41) SCR is determined to be not 

cost effective at $19,470/ton. 

Washington determined BART to be the 

current conventional burners. The 

BART Order for BP, submitted with the 

Plan, includes a NOX emission limit for 

this emission unit of 0.07 lb/MMBtu 

monthly average, or 56.2 tons per 

calendar year. 

2nd Stage HC Fractionator Reboiler: 

This reboiler is currently fitted with 

LNBs. Washington found that ULNB is 

not cost effective at $36,395/ton and 

SCR is not cost effective at $37,810/ton. 

LNB with SCR is not cost effective at 

$40,768/ton. Washington determined 

BART to be the existing LNBs with an 

emission limit for NOX of 0.07 lb/ 

MMBtu based on a 24-hour average not 

to exceed 56.2 t/y on a calendar year 

rolling average. 

General Discussion of SO2 Control 

Technologies Considered and Those 

Technically Feasible for Heaters and 

Other Combustion Devices 

Washington and BP identified four 

add-on SO2 control technologies from 

the RBLC as described below; 

Emerachem EMX, Dry Scrubbing, Fuel 

Gas Conditioning (sulfur content 

reduction), and wet flue gas 

desulfurization (wet-FGD). In addition, 

the combination of fuel gas conditioning 

and wet flue gas desulfurization (wetFGD) was considered. See SIP submittal, 

appendix L at L–28. 

Emerachem EMX (previously known 

as SCONOX): This technology has not 

been proven to run longer than one year 

without major maintenance. It has only 

been used on a small number of natural 

gas combustion turbines for NOX

control, and to date has not been used 

on oil refinery heaters to reduce SO2

emissions. BP requires the refinery 

heaters to be able to operate five years 

between turnarounds. This technology 

is technically infeasible for use on the 

refinery heaters. Therefore, Washington 

agreed with BP that the technology is 

considered technically infeasible at this 

facility. 

Dry Scrubbing: This technology 

requires a maintenance turnaround 

approximately every two years due to 

equipment plugging and wear. This 

level of needed maintenance is 

inconsistent with the refinery’s 

turnaround schedule of every 5 years. 

Therefore, Washington agreed with BP 

that the technology is considered 

technically infeasible at this facility. 

Fuel Gas Conditioning: This 

technology would reduce the 

concentration of sulfur in the refinery 

fuel gas from the current NSPS Subpart 

J limit of 162 ppmv hydrogen sulfide 

(H2S) to 50 ppmv and this would reduce 

the average sulfur concentration in the 

fuel gas combusted by BART-eligible 

units by 89%. Cost effectiveness to 

upgrade the fuel gas treatment system to 

meet a 50 ppmv concentration limit is 

$22,282/ton when the costs are applied 

only to the BART units. Because fuel gas 

conditioning would be used for all the 

combustion sources at the refinery (both 

BART and non-BART), the technology 

would also reduce emissions from the 

non-BART units. When cost 

effectiveness calculations are applied to 

all emission units at the BP refinery the 

cost effectiveness is $14,428/ton. 

Washington determined this technology 

to not be cost effective. 

Wet FGD: The cost effectiveness of 

wet flue gas desulfurization is 


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calculated to be between $29,982/ton 

and $102,068/ton because the fuel gas 

already meets the existing fuel gas limit 

of 162 ppmH2S. Washington has 

determined this technology is not cost 

effective. 

Fuel Gas Conditioning and Wet FGD: 

The cost effectiveness of combined fuel 

gas conditioning and wet flue gas 

desulfurization is $49,743/ton and 

$179,151/ton. Washington has 

determined this technology is not cost 

effective. 

Conclusions for SO2 BART: 

Washington determined that the 

existing fuel gas sulfur removal system 

is BART for SO2 for the refinery heaters. 

Particulate Matter Control 

Technologies Considered for Heaters: 

BP reviewed information in EPA’s RBLC 

database and control technology 

literature to find available technologies 

to control particulate emissions from 

refinery heaters. The most promising 

and thus those considered for further 

evaluation were fuel gas conditioning 

and wet electrostatic precipitators 

(WESP). 

Fuel Gas conditioning: This control 

technology is discussed above in the 

BART determination for SO2 and was 

determined to be not cost effective for 

PM control at this facility. 

WESP: Using this technology would 

require a wet electrostatic precipitator 

(WESP) to be added to each heater and 

boiler. The cost effectiveness is 

determined to be $24,280/ton and 

determined to not be cost effective. 

Since there are no technically or 

economically feasible PM control 

measures, Washington found that BART 

for PM for the heaters is good operating 

practices and the current refinery fuel 

gas treatment system. 

Control Technologies Considered for 

NOX, SO2 and PM and Those 

Technically Feasible for High and Low 

Pressure Flares: 

BP currently operates both a high 

pressure and low pressure flare. After a 

review of the RBLC, no add-on control 

technologies were identified. Currently 

both flares meet the applicable NSPS 

requirements for flares which emit NOX, 

SO2, and PM2.5 (40 CFR 60.18 General 

control device and work practice 

requirements). Both flares are of 

smokeless design and steam assisted. A 

flare gas recovery system was installed 

in 1984 that significantly decreased the 

total volume of gas routinely sent to the 

flare. In addition, a coker blow down 

vapor recovery system was installed in 

2007 that further reduced both the 

volume and sulfur content of the 

routinely flared gas. According to BP’s 

analysis, as relied on by Washington, no 

add-on control technologies for flares 

were identified or known to be in 

commercial use for additional control of 

NOX, SO2, or PM. 

Washington determined and required 

by BART Order 7836, BART for NOX, 

SO2, and PM control is the continued 

operation and maintenance of the 

existing high and low pressure flares, 

including the continued use of the flare 

gas recovery system, limiting pilot light 

fuel to pipeline grade natural gas, 

operating in accordance with 40 CFR 

60.18, and conversion from steam 

assisted to air assisted flares. 

Additionally, sources using flares to 

comply with Refinery MACT equipment 

leak provisions shall monitor flares to 

assure they are maintained and operated 

properly to reduce the emissions of 

organic HAPS from miscellaneous 

process vents by 98% or to 20 ppmv. 

Flares shall be operated at all times 

when emissions may be vented to them. 

SO2 emissions from the high and low 

pressure flares shall not exceed 1000 

ppm corrected to 7% O2 averaged over 

a 60-minute period. 

All Control Technologies Considered 

and Those Technically Feasible for 

Sulfur Recovery Systems 

The sulfur recovery units (SRU) 

convert hydrogen sulfide (H2S) to SO2

and elemental sulfur. BP operates two 

SRUs in parallel with their exhaust gas 

streams combined and distributed to 

two tail gas units (TGU). One TGU 

utilizes the Shell Claus Off-gas Treating 

Process (SCOT) technology, a patented 

technology, and the other utilizes the 

CANSOLV (registered trademark of 

Cansolv Technologies Inc.) technology 

to assist in further collection of sulfur 

compounds and reducing the quantity 

of SO2 discharged via the ‘‘incinerator 

stack.’’ The primary pollutant from the 

sulfur recovery unit is SO2. The SRUs 

are subject to the requirements of 40 

CFR 63 Subpart UUU, which specifies 

40 CFR 60, Subpart J compliance as a 

control option. The SRUs are currently 

controlled to this MACT standard. 

BP and Washington’s analysis found 

that the RBLC database and control 

technology literature lists available 

technologies to control NOX emissions 

from the SRUs and the TGU. In the 

RBLC, 24 entries were found regarding 

NOX control for SRUs and TGUs at 

refineries. Two categories of control 

methods for NOX were listed: 

• Good Operating Practices (e.g., 

‘‘proper equipment design and 

operation, good combustion practices, 

and use of gaseous fuels’’, ‘‘optimized 

air-fuel ratio’’, and ‘‘good operating 

practices’’) 

• LNBs: LNBs can be installed either 

within the SRU itself (usually only as 

part of the initial design) or in the TGU. 

Replacing the existing burner in the 

SRU with a LNB would increase the 

flame length causing flame 

impingement and possible damage to 

the SRU. Because of the flame 

impingement issues, a LNB within the 

SRU is technically infeasible. 

The original TGU at the refinery was 

installed in 1977 and utilizes natural 

draft burners which are not suitable for 

the direct installation of a LNB. The 

natural draft design would require 

addition of fans to supply air to the 

LNBs. The cost to install LNBs and 

additional fans would not be cost 

effective. 

Washington determined that the 

continued operation of the existing 

SRUs and TGUs is BART for NOX, SO2

and PM10/PM2.5. The BART Order 7836 

for BP, included in the SIP submittal, 

requires that SO2 emitted from the SRU 

not exceed 135 tons during each 

consecutive 12-month rolling period. 

Supplemental fuel gas combusted in the 

No. 1 TGU is limited to a composition 

of H2S <230 mg/dscm (0.10 gr/dscf) 

which is equivalent to 162 ppmH2S, 3 

hour rolling average. NOX emissions 

from No. 2 TGU Stack are limited to 2.5 

lbs/hr. SO2 emissions from No. 2 TGU 

Stack are limited to 24.0 lbs/hr. In 

accordance with NSPS Subpart J, SO2

emissions from the TGU stacks is 

limited to 250 ppm dry basis corrected 

to 0% O2 based on a 12-hour rolling 

average or 1500 ppm dry basis corrected 

to 0% O2 based on a 1-hour average. 

Control Technologies Considered and 

Those Technically Feasible for Green 

Coke Load Out 

The Green Coke Load Out system was 

constructed as part of the original 

refinery. The equipment was 

functionally replaced in 1978 by 

installation of the #1 & #2 calciners and 

a new coke load out system. However, 

the old equipment still physically exists 

at the refinery as back up during an 

emergency because there is no storage 

capability at the facility. Washington 

recognizes that continued ability to use 

the Green Coke Load Out system in an 

emergency is appropriate. Due to the 

limited use of the Green Coke Load Out 

system, the cost of any control would 

result in a high cost effectiveness value 

and limited visibility improvement. 

Washington’s BART determination 

allows its limited emergency usage. 

Cooling Tower: Cooling towers 

produce particulate from water droplet 

drift away from the towers. Washington 

evaluated droplet and particulate drift 

from cooling towers in the past and 

found that they produce relatively large 

particulate that does not drift far from 


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the tower. Washington has made a 

qualitative review of BART for the 

control of particulate from this cooling 

tower and determined that the existing 

drift controls satisfy BART for this unit. 

Visibility Improvement Expected From 

BART 

BP modeled the visibility 

improvement expected to result from 

the implementation of BART 

determinations for the #1 Diesel HDS 

Charge Heater, HDS Stabilizer Reboiler, 

R–1 HC Reactor Heater, and 1st Stage 

HC Fractionator Reboiler. Visibility at 

the most impacted Class I area, Olympic 

National Park, using the metric of the 3- 

year combined 98% value (22nd high), 

improved from 0.84 dv to 0.79 dv, and 

the 98% value (max annual 8th high) 

improved from 0.9 dv to 0.83 dv. EPA 

is proposing to approve the BART Order 

with emission limitations on SO2, NOX, 

and PM2.5 for the BART-eligible units at 

BP as they are reasonable. 

The Table summarizes the proposed 

BART determination technology for 

each BART emission unit: 

Emission unit Technology 

Crude Charge Heater ............................................................................... Current burners and operations. 

South Vacuum Heater .............................................................................. Existing ULNB. 

Naphtha HDS Charge Heater .................................................................. Current burners and operations. 

Naphtha HDS Stripper Reboiler ............................................................... Current burners and operations. 

#1 Reformer Heaters ................................................................................ Current burners and operations. 

Coker Charge Heater (#1 North) .............................................................. Current burners and operations. 

Coker Charge Heater (#2 South) ............................................................. Current burners and operations. 

#1 Diesel HDS Charge Heater ................................................................. Existing ULNB and operations. 

Diesel HDS Stabilizer Reboiler ................................................................ Existing ULNB and operations. 

Steam Reforming Furnace #1 (North H2 Plant) ...................................... Current burners and operations. 

Steam Reforming Furnace #2 (South H2 Plant) ...................................... Current burners and operations. 

R–1 HC Reactor Heater ........................................................................... Existing ULNB and operations. 

R–4 HC Reactor Heater ........................................................................... Current burners and operations.

1st Stage HC Fractionator Reboiler ......................................................... Current burners and operations. 

2nd Stage HC Fractionator Reboiler ........................................................ Existing ULNB and operations. 

Refinery Fuel Gas (hydrogen sulfide) ...................................................... Currently installed fuel gas treatment system. 

SRU & TGU (Sulfur Incinerator) ............................................................... Current burners and operations. 

High and Low Pressure Flares ................................................................. NOX: Good operation and maintenance including use of the flare gas 

recovery system and limiting pilot light fuel to pipeline grade natural 

gas. 

SO2: Good operating practices, use of natural gas for pilot. 

PM. 

Good operating practices, use of a steam-assisted smokeless flare design, use of flare gas recovery system. 

Green Coke Load-out ............................................................................... Maintain as unused equipment for possible emergency use. 

Power Boilers 1 and 3 .............................................................................. Replacement with new Power Boilers 6 and 7. 

b. Intalco Aluminum Corp. 

The Alcoa, Intalco Works (Intalco) is 

a primary aluminum smelter utilizing 

the prebake process located at Cherry 

Point near Ferndale, Washington. The 

visibility impairing pollutants from the 

facility are PM, NOX and SO2. The major 

sources of these pollutants at the facility 

are the potlines and to a lesser extent, 

the anode bake furnace. 

Base year SO2 emissions from the 

potlines are 6550 t/y from sulfur in 

anode coke that is consumed in the 

smelting process. Particulate emissions 

from the potlines and the anode bake 

oven are well controlled. The primary 

air pollution control system employed 

by Intalco for control of potline 

emissions consists of dry alumina 

injection followed by fabric filtration 

which effectively controls PM. 

Emissions of NOX from the potlines are 

insignificant because the potlines are 

electrically heated (versus combustion 

of fossil fuels) and none of the raw 

materials contain significant quantities 

of nitrogen. 

Modeled visibility impacts of baseline 

emissions were over 2.0 dv at Olympic 

National Park. Impacts of greater than 

0.5 dv were shown for six other Class 

I areas. The modeling also showed that 

SO2 emissions from the exit of the 

existing dry alumina baghouse potline 

emission control system as being 

responsible for 94% of the facility’s total 

visibility impact and these emissions 

are the focus of EPA’s evaluation of 

Washington’s BART determination. 

SO2 BART Determination for Potlines 

Eight different SO2 add-on control 

options, along with pollution 

prevention, were identified in the SIP 

submittal as potential control measures. 

Six of the control options use wet 

scrubbing and two use dry scrubbing 

technology. Pollution prevention, by 

limiting the sulfur content of the coke 

used in the furnace anodes, along with 

the amount of carbon consumed in the 

process, was also evaluated. 

Wet Scrubbing Technologies: 

• Limestone slurry scrubbing with 

forced oxidation (LSFO) 

• Conventional lime wet scrubbing 

• Seawater scrubbing 

• Dual alkali sodium/lime scrubbing 

(dilute mode) 

• Conventional sodium scrubbing 

Dry Scrubbing Technologies: 

• Dry sorbent injection 

• Semi-dry scrubbing (spray dryer) 

Limestone Slurry Forced Oxidation 

(LSFO): Spray nozzles inject limestone 

slurry droplets into the exhaust gas 

stream from a spray tower. The 

limestone reacts with SO2 to form 

calcium sulfite. Liquor is collected at 

the bottom of the tower and sparged 

with air to oxidize the calcium sulfite to 

calcium sulfate to enhance the settling 

properties. Recirculation pumps 

circulate the scrubbing liquor to the 

spray nozzles. Sulfur dioxide removal 

efficiencies of 90% or greater have been 

achieved. The bleed containing calcium 

sulfate is sent to a dewatering system to 

remove excess moisture. For an 

aluminum smelter, the process will 

produce either solid gypsum waste or 

commercial-grade gypsum suitable for 

reuse as a cement additive. Only a very 

small purge or blowdown stream is 

required. A more detailed evaluation of 

LSFO for the Intalco facility is discussed 

below following the short evaluation of 

other control technologies that were 

rejected. 


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Conventional Lime Wet Scrubbing: 

Conventional lime wet scrubbing is 

similar to LSFO except that the raw 

material is hydrated lime or quick lime 

that is either slaked on-site or purchased 

in the slaked form. The system typically 

uses forced oxidation, although natural 

oxidation is possible. The process 

produces either solid gypsum waste or 

commercial-grade gypsum suitable for 

possible reuse as a cement additive. 

Seawater Scrubbing: Seawater 

scrubbing is used in Europe for control 

of SO2 emissions from primary 

aluminum smelters similar to Intalco. 

As with other wet scrubbing 

technologies, an alkaline solution (in 

this case seawater) is sprayed into the 

exhaust gas stream within one or more 

vertical towers and the seawater is used 

to absorb the SO2 in the exhaust gases. 

More specifically, by encouraging 

contact between the SO2 containing gas 

stream and the slightly alkaline 

seawater, SO2 is removed from the gas 

stream via absorption. The seawater is 

then discharged as wastewater. 

Dual Alkali/Lime Scrubbing: Dual 

alkali sodium/lime scrubbing (dilute 

mode) uses a caustic sodium solution in 

the scrubber tower. A portion of the 

scrubbing liquid is discharged to a 

neutralization stage where lime slurry is 

used to regenerate the caustic, which is 

returned to the scrubber. The bleed from 

the scrubber is sent to a dewatering 

system to produce a gypsum byproduct. 

The process will produce either solid 

gypsum waste or commercial-grade 

gypsum suitable for reuse as a cement 

additive. Dual alkali sodium/lime 

scrubbing (dilute mode) is not currently 

marketed by major FGD vendors 

because the system is too complicated 

and expensive. Washington found that 

due to lack of availability and 

anticipated excessive cost, dual alkali 

sodium/lime scrubbing is not 

technically feasible. 

Conventional Sodium Scrubbing: 

Sodium scrubbing is another wet 

scrubbing technology using scrubber 

liquor containing a sodium reagent. The 

infrastructure and associated capital 

costs for a sodium scrubber would be 

similar to that of LSFO, although 

sodium-based reagents are generally 

much more expensive than limestone or 

lime. Based on these factors, and the 

similarity to the equipment necessary 

for LSFO, further evaluation of sodium 

scrubbing is unnecessary. 

Dry Sorbent Injection: In dry 

injection, a reactive alkaline powder is 

injected into a furnace, ductwork, or a 

dry reactor. Typical removal efficiencies 

with calcium adsorbents are 50 to 60% 

and up to 80% with sodium base 

adsorbents. However, as with wet 

scrubbing, disposal of waste using 

sodium adsorbents must consider their 

high solubility in water compared to 

those from calcium adsorbents. The 

temperature range over which scrubbing 

has been used is 300 to 1,800 °F; the 

minimum temperature is 300 to 350 °F. 

Dry systems are rarely used and only 

3% of FGD systems installed in the U.S. 

are dry systems. The dry waste material 

is removed using particulate control 

devices such a fabric filter or an 

electrostatic precipitator (ESP). 

Analysis of the Available Control 

Options 

Seawater Scrubbing: As described by 

Washington, although technically 

feasible, seawater scrubbing was 

eliminated from consideration as BART 

due to water quality discharge concerns. 

See SIP submittal pages L–81 to L–83. 

Unlike aluminum plants in Europe, 

wastewater discharge from primary 

aluminum smelters in the United States 

must comply with specific limits on 

fluorides, among other pollutants (see 

40 CFR 421, Subpart B). Washington 

found that the necessary wastewater 

treatment facilities would not be costeffective, and would produce a large 

amount of wastewater treatment sludge. 

Treatment of seawater would produce 

significantly more sludge than 

freshwater since precipitation of the 

natural salts would be necessary in 

order to remove target pollutants. 

EPA conducted further analysis of 

non-air related environmental impacts 

of seawater scrubbing. The offshore 

aquatic area immediately surrounding 

the Intalco smelter has recently been 

designated as an environmental aquatic 

reserve for the protection of herring. The 

Cherry Point Environmental Aquatic 

Reserve Management Plan expressly 

prohibits new saltwater intake 

structures, which would be necessary 

for seawater scrubbing. See Cherry Point 

Environmental Aquatic Reserve 

Management Plan p. 54. Thus, seawater 

scrubbing is not a viable control option. 

Dry Sorbent Injection: Intalco’s 

potline exhaust gas stream, downstream 

of the existing baghouses is low 

temperature (less than 205 °F) with low 

SO2 concentrations of less than 105 

ppm. Washington’s analysis found that 

dry sorbent scrubbing is not effective at 

gas stream temperatures below 250 °F. 

Thus, due to the low temperatures in 

the Intalco potline exhaust gas stream, 

Washington determined dry scrubbing 

is not technically feasible. 

EPA conducted a literature review 

which generally supports this finding. 

In addition, EPA contacted a vendor of 

dry scrubbing technology who 

confirmed the importance of exhaust gas 

stream temperature, and stated that its 

dry scrubbing technology could 

successfully control SO2 emissions for 

gas stream temperatures down to 

approximately 250–260 °F. 

Upstream of the existing baghouses, 

the exhaust gas temperature would be in 

the temperature range that is technically 

feasible for DSI. However, injection of 

the alkaline reagent may render the 

baghouse catch unsuitable for recycling 

to the potlines which is the current 

practice for reclamation of the alumina 

and control of fluorides. 

Based on this research, we agree with 

Washington’s determination that with a 

flue gas temperature of ∼205 °F, dry 

scrubbing is technically infeasible for 

control of SO2. 

We did not conduct further analyses 

regarding Conventional Wet Lime 

Scrubbing, and Dual Alkali Sodium/ 

Lime Scrubbing because we agree with 

Washington’s determination that these 

technologies either had no advantages 

over LSFO, had clear disadvantages, or 

were likely to be more costly when 

compared with LSFO. 

Low Sulfur Anode Coke: Washington 

discussed the current levels of sulfur in 

petroleum coke used by other aluminum 

smelters to determine whether a 

pollution prevention option using lower 

sulfur content coke would be a feasible 

BART option for Intalco. See 

Washington SIP submittal appendix L at 

L–68 to 69. This analysis indicated that 

some smelters currently utilize coke 

with sulfur contents as low as two 2%. 

An analysis was also done by 

Washington to determine whether coke 

with sulfur levels below 3% can be 

anticipated to be available into the 

future. The primary conclusions from 

Washington’s analysis indicate that 

there will be a continuing increase in 

the sulfur content of available anode 

grade coke. The aluminum smelters that 

currently have sulfur limits below 3% 

are requesting the regulating agencies to 

relax this limit due to lack of available 

low sulfur coke. 

Coke is a relatively small, low 

revenue component of a refinery’s 

product profile. It is a low value product 

made from the thick, tar-like refinery 

wastes left over after all of the more 

valuable components have been 

removed from the petroleum crude. The 

aluminum industry has little influence 

in controlling the quantity, quality, and 

price of the coke produced by refineries. 

Washington also found that low sulfur 

crude oil supplies are becoming less 

available and more expensive for 

petroleum refineries. In the future, 

refineries with coking capacity are 

expected to minimize their raw material 

costs by using more of the higher sulfur 


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8These cost quotes have been reviewed and 

analyzed by EPA but Alcoa has claimed the cost 

quotes as confidential business information (CBI). 

Given Alcoa’s claim of CBI, the actual quotes are 

not included in the public portion of the docket for 

this proposed action. 

9 Market Review for Intalco Produced FGD 

Gypsum. Elliot Rosenberg, Senior Economist. EPA 

Region 10. March 23, 2012. 

crude oils and oil sands. Washington 

further explained that as oil fields age, 

the sulfur content of the crude oil is 

known to increase and the crude oil in 

the fields becomes more viscous and 

harder to extract. This effect is expected 

to increase the sulfur content of the 

petroleum materials available to 

produce anode grade coke. 

Global primary aluminum production 

is expected to grow, resulting in a 

commensurate growth in demand for 

anode grade coke. Growth in aluminum 

production will continue to outpace the 

growth in coke production. Coke 

providers are blending imported, high 

cost, lower sulfur coke with 

domestically sourced coke in attempts 

to meet the current specification 

requirements for coke. Removal or 

reduction of the sulfur content of the 

coke once it has been received is not 

feasible. It is the Washington’s and 

EPA’s conclusion that coke with a sulfur 

content of less than 3% is not a viable 

option due to its limited availability. 

LSFO: LSFO technology was selected 

by Intalco and Washington as the best 

option among the technically feasible 

wet scrubbing technologies. EPA agrees 

that LSFO is the best SO2 control 

technology for this facility and with 

Washington’s rationale for that 

selection. LSFO is estimated to achieve 

a 95% control for SO2 at Intalco. 

Alcoa evaluated the estimated cost of 

LSFO, based on quotes from two 

separate vendors that were prepared for 

Alcoa for their Tennessee facility that 

were then scaled to the Intalco facility.8

Both preliminary designs were based on 

a central scrubbing center as the lowest 

cost approach, where exhaust from all 

dry scrubbing systems would be ducted 

to a centralized scrubbing system. Both 

vendor quotes were based on systems 

that would provide 100% availability of 

emissions control on each day of the 

year, given that potlines cannot be 

easily shutdown and restarted for 

control system maintenance outages. In 

other words, the proposed designs 

include two scrubber towers; one 

primary tower which would operate 

most of the time and a second tower 

which could be used when the primary 

tower needed repair or maintenance. 

Washington’s cost effectiveness value 

for the proposed two-absorption tower 

design was $6,574/ton of SO2 removed. 

The capital and total annual operating 

costs were estimated to be $208.5 

million and $40.9 million per year 

respectively. Washington determined 

the cost effectiveness for the two-tower 

scrubber to be unreasonable. 

Washington’s BART Determination 

for Intalco Potlines: Washington 

determined that BART for SO2 from the 

potlines is the existing pollution 

prevention measures, including the use 

of less than 3% sulfur in the anode 

coke. 

EPA’s Determination of Cost 

Effectiveness and Visibility Impacts 

EPA independently estimated the cost 

effectiveness of LSFO. A memorandum, 

‘‘Intalco BART Technical Review 

Memo,’’ November 16, 2012, describes 

EPA’s BART evaluation and analysis, 

and is included in the docket to this 

action. EPA’s cost effectiveness 

calculations are based on the lower of 

two site-specific vendor quotes for the 

primary aluminum smelter located in 

Alcoa, Tennessee. The costs estimates 

were scaled to reflect the differences 

between the Alcoa Tennessee smelter 

and the Alcoa Intalco operations, 

including smelter size, economy of 

scale, limestone consumption and 

gypsum production (waste disposal). 

EPA’s primary concern with 

Washington’s cost estimates and the 

changes EPA made to the Washington’s 

analysis are: (1) Single tower design, 

eliminating the cost of a backup tower; 

(2) the lower of the two vendor quotes 

is used rather than the average; (3) the 

scrubber equipment life is assumed to 

be 30 years rather than 15; and (4) 

assumption that the gypsum by-product 

is re-used rather than landfilled. 

Single Tower Design: As explained 

above, Alcoa and Washington based the 

cost effectiveness calculation for LSFO 

on the assumption that two scrubber 

towers would be required so that the 

facility would have a back up scrubber 

available for use whenever the primary 

scrubber was off line for maintenance. 

In EPA’s view the redundant, second 

tower, is not necessary. Building one 

scrubber tower would reduce the capital 

and annual maintenance costs 

associated with LSFO. The BART 

emission limit could be written to 

account for periods of time with higher 

emissions such as during maintenance 

of the scrubber tower. 

Low Bid: Capital equipment quotes, 

used by both Alcoa and Washington, 

were obtained from two vendors of 

LSFO systems for the Alcoa Tennessee 

smelter and were provided to EPA. The 

Alcoa and Washington analysis 

averaged these two quotes in estimating 

these capital costs for the Intalco 

potlines. This approach is unacceptable 

based on the EPA Air Pollution Control 

Cost Manual and is not in accord with 

standard contracting procedures. The 

Control Cost Manual clearly supports 

the use of the low bid. Specifically, the 

manual states that ‘‘[s]ignificant savings 

can be had by soliciting multiple quotes 

and discusses the ability to compare to 

other bids.’’ See EPA Air Pollution 

Control Cost Manual, Sixth Edition. Our 

cost effectiveness analysis uses the 

lower of the two capital equipment 

quotes, scaled from the Tennessee 

smelter to Intalco. 

Equipment Life: The Alcoa and 

Washington analysis used an expected 

equipment lifetime of 15 years for the 

LSFO system. Washington provided no 

basis for using a 15 year lifetime. Based 

on our review of available information, 

30 years rather than 15, is an 

appropriate equipment life. The 

expected service life of wet flue gas 

desulfurization (FGD) systems such as 

LSFO is cited in the literature as 30 

years. The actual life of wet FGD 

scrubbers installed at coal fired power 

plants has been demonstrated to be 30 

years or more for many plants. Industry 

reports establish scrubber longevity near 

or exceeding 30 years. See Intalco BART 

Technical Review Memo. 

Gypsum Reuse: Alcoa and 

Washington assumed the gypsum 

produced as a by-product from LSFO 

would be disposed of in a landfill at a 

cost of about $4 million per year. 

However, based on the information in 

Alcoa’s contractor BART analysis report 

and equipment vendor information, it 

appears that the gypsum produced as a 

by-product of LSFO would be suitable 

for re-use. EPA conducted an internal 

economic analysis to evaluate the 

potential for beneficial reuse of the 

gypsum by-product from LSFO 9. Our 

analysis identified several applications 

for so-called FGD gypsum in addition to 

market factors which suggest the likely 

presence of a market for the gypsum 

produced by Intalco. Specifically, we 

found that a significant price differential 

exists between FGD gypsum and natural 

(mined) gypsum favoring the former. 

Based on the design specification 

establishing that the gypsum by-product 

would be suitable for commercial reuse, 

the information suggests a likely market 

for the gypsum. A considerable financial 

incentive would exist for Intalco to sell, 

or even give away the FGD gypsum, 

rather than dispose of it in a landfill. We 

do not agree that it is reasonable to 

assume that Intalco will need to pay to 

dispose of the gypsum from the LSFO 

process in a landfill. Our cost 

effectiveness analysis therefore 

eliminates the gypsum disposal costs 


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10Free on Board, defined here where the buyer 

pays for all loading, transportation, and unloading 

costs. 

and assumes that Intalco gives the 

gypsum away ‘‘Free on Board’’ 10 from 

the facility in Ferndale. Any proceeds 

from the sale of the gypsum would 

further improve the LSFO scrubber cost 

effectiveness. 

Conclusion of Cost Effectiveness for 

LSFO at the Intalco facility: EPA 

estimates the cost effectiveness of an 

LSFO system in the range of $3875/ton 

to $4363/ton. See Intalco BART 

Technical Review Memo. 

Visibility Impacts 

EPA considered the visibility impact 

of the potline SO2 emissions and the 

resulting improvement of visibility in 

Class I areas surrounding Intalco 

expected to result from installation and 

operating LSFO. Two modeling efforts 

were conducted by an Intalco 

contractor; one analysis used 4 

kilometer (km) grid cells and the other 

used 1 km grid cells. The analysis using 

4 km grid cells considered only the 

baseline case. The analysis using 1 km 

grid cells considered both the baseline 

and the control case. The use of 1 km 

grid cells for Intalco underestimates 

visibility impacts compared to results 

using 4 km grid cells. However, 

modeling of visibility impacts after 

installation of LSFO was only 

conducted using 1 km grid cells. EPA 

believes that the 1 km grid cell results 

may provide informative insight into the 

relative visibility improvements that 

could be achieved by implementing 

LSFO. 

Both modeling results show 

significant SO2 visibility impacts from 

Intalco in several Class I areas, with the 

greatest impact at Olympic National 

Park. The tables below show these 

impacts and the expected visibility 

improvement of greater than 75% in all 

Class I areas after implementation of 

LSFO: 

Modeling With 1 km grid cells: 

Class I area 

Current impact 

(98th percentile 

dv, # of days 

>0.5 dv) 

Impact with 

LSFO (98th percentile dv, # of 

days >0.5 

dvdays) 

Percent improvement in visibility 

(%) 

Alpine Lakes .................................................................................................................... 0.742, 18 days .. 0.158, 0 days .... 79 

Glacier Peak .................................................................................................................... 0.916, 24 days .. 0.190, 0 days ... 79 

Mount Rainier .................................................................................................................. 0.660, 11 days .. 0.108, 0 days ... 83 

North Cascades ............................................................................................................... 0.986, 35 days .. 0.212, 0 days ... 78 

Olympic ............................................................................................................................ 1.527, 41 days .. 0.355, 2 days ... 77 

Modeling With 4 km grid cells: 

Class I area 

Current impact 

dv # days >0.5 dv 

Alpine Lakes Wilderness ............. 1.0 32 

Goat 

RocksWilderness 0.5 7 

Glacier Peak Wilderness ............. 1.0 33 

Mount Adams Wilderness ............. 0.4 5 

Mount Rainier NP 0.8 21 

North Cascades 

NP ..................... 1.3 51 

Olympic NP ........... 2.1 52 

Pasayten Wilderness ................... 0.8 25 

EPA believes these are significant 

impacts, not only based on the 

maximum impact at Olympic National 

Park, but also the number of days over 

0.5 dv at several Class I areas and the 

number of Class I areas with impacts 

greater than 0.5 dv. Installation and 

operation of LSFO would significantly 

improve visibility in several Class I 

areas in Washington. 

EPA’s Conclusion Regarding 

Washington’s BART Determination for 

Intalco 

EPA disagrees with Washington’s 

BART analysis for Intalco because the 

cost of compliance was improperly 

determined and proposes to disapprove 

their analysis. As discussed above, EPA 

calculated a different cost effectiveness 

value based on eliminating the cost of 

a backup tower; using the lower of the 

two vendor quotes rather than the 

average; assuming the equipment life is 

30 years rather than 15, and assuming 

the gypsum by-product is re-used rather 

than landfilled. EPA believes based on 

a cost effectiveness value in the range of 

$3875/ton to $4363/ton and the facts 

presented above and considering the 

following factors that LSFO would be 

BART: 

• While the cost effectiveness is 

relatively high in the range of $3875 to 

$4363/ton, it is in the range of other 

EPA promulgated BART determinations. 

e.g. Four Corners Power Plant (77 FR 

51619), 

• A 95% reduction in SO2 emissions 

will result in visibility improvement 

over 1 deciview at Olympic National 

Park and over 0.5 deciview at 5 other 

Class I areas, 

• There is insignificant non-air 

environmental and energy impacts, 

• The source is anticipated to remain 

in operation for the foreseeable future, 

assuming no requirement to install new 

controls, 

• The current control for SO2 on the 

potlines are the pollution prevention 

measures, including the 3% sulfur limit 

for incoming coke. 

However as discussed below, at the 

request of Alcoa, EPA considered 

whether Alcoa would be able to afford 

LSFO and remain a viable entity. 

Affordability: The BART Guidelines 

provide that even if a control technology 

is cost effective there may be some cases 

where installing the controls would 

affect the viability of continued plant 

operations. Specifically, the rule 

explains that there may be unusual 

situations that justify taking into 

consideration the condition of the plant 

and the economic effects of requiring 

the use of a given control technology. 

The economic effects could include 

effects on product prices, market share, 

and profitability of the source. See 40 

CFR 51 appendix Y, IV.D.4.k. Alcoa 

indicated to EPA that it cannot afford 

installation and operation of an LSFO 

control system and requested that 

affordability be considered. As 

summarized below EPA conducted a 

thorough ‘‘affordability assessment’’ of 

Alcoa and the Intalco operations. Based 

on that analysis, EPA proposes to 

conclude that Alcoa cannot afford to 

install LSFO at Intalco at this time. See 

‘‘Intalco BART SO2 Affordability 

Assessment’’ (Affordability Assessment) 

in the docket for this action for 


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additional detail regarding EPA’s 

affordability analysis. 

Summary of Affordability Analysis 

In June 2012, Alcoa provided EPA an 

analysis (claimed as Confidential 

Business Information) of the financial 

health of the Intalco Operations from 

2008 through 2013. Their analysis 

included financial information for both 

Alcoa as a whole, and the Intalco 

operations specifically, indicating that 

Intalco has not been a profitable 

operation in recent years and that the 

projected profits for this year and next 

are less than the annualized cost of 

LSFO. Their analysis concluded that 

during this time frame, there was 

insufficient after tax income to afford 

the annualized cost (capital and O&M) 

for LSFO of $26 million. 

EPA conducted an independent 

analysis of the financial status of the 

Alcoa Intalco operations, considering 

the current and future trends in the cost 

of raw materials, operating expenses 

(labor and electricity), revenue income, 

and increasing supply and anticipated 

demand for aluminum in the future. 

Intalco is currently operating at less 

than full capacity and is operating only 

two of its three potlines. Operating the 

third potline is not economical given 

existing market prices for aluminum 

and electricity, limited availability of 

reasonably priced power and potline 

production costs. If Intalco were to 

install the LFSO control technology, the 

annual cost of installing and operating 

the equipment would represent 

approximately 8–10% of the facility’s 

sales revenue over the 30 year lifetime 

of the equipment at current utilization 

at the facility. We recognize that the 

cost/sales ratios may be higher or lower 

depending on plant utilization and 

future aluminum prices, but they are 

substantial in even the most optimistic 

cases. 

Alcoa is unlikely to be able to pass 

these costs along to consumers, as 

shown by its historical inability to pass 

through higher electricity prices, and is 

also unlikely to operate its third potline 

to increase production in the near 

future. Additionally, as mentioned in 

the Affordability Assessment, Alcoa’s 

credit rating and low cash reserves may 

limit its ability to obtain resources to 

purchase pollution control equipment. 

Finally, the installation and operating 

cost of LSFO would represent a 

significant initial and long-term 

expenditure and a decision by Alcoa to 

close the facility rather than incur the 

pollution control equipment expense 

could be consistent with the findings of 

the independent affordability analysis. 

See Affordability Assessment for 

additional detail. 

Based on this analysis EPA concludes 

that the Alcoa Intalco operations cannot 

afford LSFO at the Intalco facility and 

remain a viable operation. 

Summary of Other, Less Costly Control 

Options for Potlines 

EPA also considered less costly 

control of partial scrubbing of the 

potline emissions. There are six 

baghouses, each with multiple exhaust 

stacks, controlling particulate from the 

three potlines. EPA considered 

controlling SO2 from two of the six, and 

four of the six baghouses. Under this 

scenario, the capital costs are reduced, 

however the cost effectiveness values 

would increase due to the economies of 

scale. At the same time, visibility 

improvement would decrease as overall 

SO2 emission reduction decreases 

proportionally. Thus, in light of the 

increased cost effectiveness values and 

decreased visibility improvement, we 

determined partial scrubbing is not 

reasonable. 

EPA SO2 BART Determination for 

Potlines 

Based on all the considerations 

summarized above, EPA believes that 

while LSFO is cost effective and would 

significantly improve visibility, it is not 

affordable at this facility. Therefore, 

EPA proposes to find that the pollution 

prevention measure of limiting the 

sulfur content of anodes to 3% is BART 

for Intalco. 

Regional Haze Rule Provision for 

Alternative BART Programs 

Pursuant to the RHR, a state may 

choose to implement measures as an 

alternative to BART so long as the 

alternative measures can be 

demonstrated to achieve greater 

reasonable progress toward the national 

visibility goal than would be achieved 

through the installation and operation of 

BART. See 40 CFR 51.308(e)(2). The 

demonstration must include, among 

other things, a requirement that all 

necessary emission reductions take 

place during the first long term strategy 

period and a demonstration that the 

emissions reductions resulting from the 

alternative measures will be surplus to 

those reductions resulting from 

measures adopted to meet requirements 

of the CAA as of the baseline date of the 

SIP. 

Better Than BART Proposal for the 

Intalco Potlines 

In the letter dated June 22, 2012, from 

Alcoa to EPA, Alcoa proposed an 

alternative that would be Better than 

BART. This alternative consists of 

implementing pollution prevention 

measures, primarily the requirement of 

3% or less sulfur in the anode coke, and 

limiting SO2 emissions from the 

potlines to 80% of the base year 

emissions of 6550 t/y. For the reasons 

explained, EPA is proposing to accept 

this Better than BART alternative and 

proposes a 5240 t/y annual SO2

emission limit on the potlines. 

Better Than BART Visibility Impact 

Alcoa modeled the visibility 

difference between base year SO2

emissions of 6550 t/y and a 20% 

reduction in emissions to 5240 t/y from 

the Intalco facility. The modeled results 

are summarized below for Olympic 

National Park. The deciview metric is 

the 98th percentile value for the year. 

BASE YEAR SO2

[6550 t/y] 

Metric 2003 2004 2005 

98th Percentile.2.36 dv 1.86 dv 2.14 dv 

Days above 

0.5 dv.

59 ........ 53 ........ 42 

Days above 

1.0 dv.

29 ........ 21 ........ 24 

20% REDUCTION OF SO2 EMISSIONS

[5240 t/y] 

Metric 2003 2004 2005 

98th Percentile.1.20 dv 1.56 dv 1.82 dv 

Days above 

0.5 dv.

50 ........ 48 ........ 41 

Days above 

1.0 dv.

23 ........ 19 ........ 21 

The 80% SO2 emissions cap, limiting 

the SO2 emission to 5240 t/y, will 

prevent visibility from degrading on the 

worst days (represented by the 98th 

percentile) and will also reduce the 

number of days with impairment greater 

than 0.5 dv and 1.0 dv. 

Anode Bake Ovens 

Intalco manufactures its own anodes 

from an on-site facility using calcined 

coke and pitch. Green anodes are baked 

to remove volatile organic impurities 

and hardened for use in the aluminum 

potlines. During the baking process, 

some of the sulfur in the coke is 

released as sulfur dioxide and emitted 

to the atmosphere. The Anode Bake 

Ovens are fueled with natural gas and 

emit visibility impairing pollutants of 

particulate matter, SO2, and NOX. 

Emissions are currently controlled with 

an alumina scrubber to remove 

hydrogen fluoride and volatile organics 


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and then the outflow from the scrubber 

is ducted to baghouses to remove 

particulate. The baghouses provide 99% 

control of particulate matter. 

Washington evaluated SO2 scrubbers 

for the anode bake oven exhaust using 

information from its evaluation of 

potline SO2 control. Costs determined 

for LSFO for the potlines were scaled to 

the lower gas flow rate of the bake oven. 

A 95% control efficiency for SO2 was 

assumed. The cost effectiveness of LSFO 

scrubbing was estimated to be $36,400/ 

ton and the visibility improvement 

would be 0.02 dv at Olympic National 

Park. Washington determined, based on 

the high cost and small visibility 

improvement that the petroleum coke 

sulfur limit of 3% is BART for anode 

bake furnace SO2 emissions. 

Washington also determined that the 

existing level of particulate matter 

control (based on baghouses on the 

alumina dry scrubbers) is BART for 

particulate emissions. 

Washington rejected using an 

advanced firing system for reduced 

energy use as BART for NOX because 

the technology would result in a 

negligible emission reduction and 

visibility improvement. Similarly, 

Washington rejected LoTOxTM as BART 

because the cost of the technology 

would be excessive and it has not been 

demonstrated in practice on aluminum 

plant anode bake ovens. 

Washington determined that BART 

for anode bake furnace NOX emissions 

is no controls. After review of available 

control technologies, EPA agrees with 

Washington’s BART determination for 

this source and is proposing to approve 

the BART determinations for the anode 

bake ovens. 

Aluminum Holding Furnaces 

The aluminum holding furnaces are 

fueled with natural gas and emit NOX. 

The emissions from the furnaces are 

small and result in negligible visibility 

impairment in any Class I area. 

Washington determined that BART for 

the aluminum holding furnaces is no 

controls. Washington rejected additional 

controls as BART because any visibility 

improvement would be negligible due to 

the low level of emissions from the 

natural gas-fired burners. EPA agrees 

that no additional control of emissions 

from the aluminum holding furnaces is 

BART. 

Material Handling and Transfer 

Operations 

The PM emissions from the BARTeligible material handling and transfer 

operations are all controlled using fabric 

filter technology, and these operations 

are a negligible source of NOX and SO2

emissions. Additional control of these 

pollutants would provide negligible 

visibility improvement. Therefore, 

Washington determined that the 

existing level of emissions control, 

fabric filters, is BART for these material 

handling and transfer operations. 

EPA agrees that fabric filter 

(baghouse) is the appropriate control 

technology and all emission units must 

meet 40 CFR part 63, Subpart RRR, and 

emissions of PM shall not exceed 0.01 

grains per dscf. 

Summary of Intalco BART 

Determination and EPA’s Proposed 

Action 

EPA is proposing to approve 

Washington’s BART determination for 

Intalco with the exception of the SO2

BART determination for the Intalco 

potlines. EPA is proposing a limited 

disapproval of Washington’s BART 

analysis for SO2 because, as explained 

above, Washington did not properly 

calculate the cost effectiveness value. 

Washington determined a cost 

effectiveness value of greater than 

$6000/ton for LSFO and consequently 

dismissed LSFO as BART. EPA is 

proposing a Better than BART FIP for 

control of SO2 emissions off the 

potlines. 

As described above, EPA revised 

some of the cost inputs and assumptions 

and calculated a cost effectiveness value 

in the range of $3875/ton to $4363/ton 

for LSFO. When considered in light of 

the visibility improvement in Olympic 

National Park and several other Class I 

areas surrounding Intalco, LSFO likely 

would be considered BART. However, 

as also explained above, Alcoa claimed 

it cannot afford LSFO at Intalco and still 

have it remain a viable entity. After 

investigating the affordability claim, 

including an analysis of Alcoa’s 

financial status, market conditions, and 

electricity availability, EPA agrees and 

thus rejects LSFO as BART for this 

facility. 

Washington issued Intalco a BART 

Order, (Order No. 7837, Revision 1) on 

July 7, 2010, that establishes 

Washington’s determined BART control 

technology, pollution prevention 

measures, emission limits, compliance 

dates, monitoring, and recordkeeping 

requirements. EPA is simultaneously 

issuing a limited approval of 

Washington’s SO2 BART Order for the 

potlines, as a SIP strengthening 

measure. Intalco can afford to continue 

to implement of the pollution 

prevention measures and limiting the 

sulfur content of anodes in the furnace 

to 3% as required under the 

Washington’s BART Order. Intalco is 

currently operating the potlines with 

SO2 emissions below the proposed 

Better than BART alternative. The Better 

than BART alternative makes 

Washington’s pollution prevention 

requirements, including a 3% limit on 

anode coke federally enforceable. The 

proposed alternative imposes a 5240 t/ 

y annual SO2 emission limit, makes the 

20% SO2 emission reduction from 

baseline permanent and federally 

enforceable, and prevents any future 

visibility degradation should Intalco 

decide to increase production in the 

future. Compliance with the annual SO2

emission limit will be demonstrated 

using the same information that Intalco 

is required to collect under existing 

Washington requirements. So while the 

proposed alternative would impose 

additional recordkeeping and reporting 

obligations related to the annual cap, it 

would not impose any additional 

monitoring requirements. 

The table below summarizes the 

proposed BART determination and 

Better than BART FIP for each BART 

emission unit: 

Emission unit BART technology 

Potlines ..................................................................................................... SO2: 80% emission cap from baseyear (5,240 tons for any calendar 

year) and pollution prevention limit of 3% sulfur in the coke used to 

manufacture anodes. 

PM: Use of the current level of control, which is the use of baghouses 

to control PM emissions from the alumina dry scrubbers, and wet 

roof scrubbers to control secondary PM emissions from the potroom 

roofs. 

NOX: no control. 

Anode Bake Furnace ................................................................................ SO2: pollution prevention limit of 3% sulfur in the coke used to manufacture anodes. 

PM: The current baghouse. 


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Emission unit BART technology 

Aluminum Holding Furnace ...................................................................... No control. 

Material Handling and Transfer ................................................................ PM Use of the current level of control, which is use of fabric filters. 

c. Tesoro Refining and Marketing 

The Tesoro refinery (Tesoro) near 

Anacortes, Washington, processes crude 

oil into refined oil products, including 

ultra low sulfur diesel oil, jet fuel, #6 

fuel oil, and gasoline. Modeling of 

visibility impairment was done 

following the Oregon-Idaho-Washington 

Region 10 BART modeling protocol. 

Modeled visibility impacts of baseline 

emissions show impacts on the 8th 

highest day in any year (the 98th 

percentile value) of greater than 0.5 dv 

at five Class 1 areas. The highest impact 

was 1.72 dv at Olympic National Park. 

Ten process heaters, one flare, one 

boiler, and two cooling towers at the 

plant are BART-eligible. The primary 

emission units of concern are the 

process heaters, boiler, and flares which 

have significant emissions of SO2 and 

NOX. Direct PM emissions from the 

BART-eligible units are low because 

almost all burn either refinery fuel gas 

or natural gas. Only one BART-eligible 

unit subject to BART, the crude oil 

distillation heater (unit F–103), is 

currently permitted to burn fuel oil. 

Tesoro reported 3 tons of PM2.5

emissions from this unit in 2009. 

Eleven of the 74 storage tanks at 

Tesoro emit VOCs and meet the 1962– 

1977 timeframe for BART-eligibility. 

Washington considers VOCs as visibility 

impairing pollutants (see appendix L, 

page 104 of the SIP submittal), but since 

the CALPUFF model, which is used to 

evaluate visibility impairment from 

single sources, cannot effectively model 

VOCs, Washington decided that VOC 

emissions from BART-eligible storage 

tanks and other units would not be 

evaluated for BART. Note that the 

facility’s reported total VOC emissions 

in 2008 were 1,082 tons. The BART 

determination for the Tesoro refinery 

focuses only on SO2, NOX, and PM. EPA 

agrees that it is not necessary to further 

evaluate visibility impacts from VOCs 

for this planning period since, in 

addition to the modeling uncertainties, 

the majority of VOC emissions already 

have controls in place (for example to 

meet the applicable NSPS, MACT, and 

VOC fugitive emission control 

regulations). In addition, not all of the 

VOC emitted will convert to light 

scattering particles, so visibility impact 

due to VOC emissions is expected to be 

minimal. 

The following are units at Tesoro 

subject to BART: 

F–103 Crude Oil Distillation 

F–104 Gasoline Splitter/Reboiler 

F–304 CO Boiler No. 2 

F–654 Catalytic Feed Hydrotreater 

F–6600 Naphtha Hydrotreater 

F–6601 Naphtha Hydrotreater 

F–6602 Naphtha Hydrotreater 

F–6650/6651 Catalytic Reformer 

F–6652/6653 Catalytic Reformer 

F–6654 Catalytic Reformer 

F–6655 Catalytic Reformer 

X–819 Flare 

CWT #2 Cooling Water Tower 

CWT #2a Cooling Water Tower 

NOX Controls Evaluated for All 

Combustion Units 

Tesoro evaluated available NOX

control technologies generally 

applicable to combustion units. Unitspecific evaluations were completed 

based on technologies found generally 

feasible. 

Flue Gas Recirculation: Flue gas 

recirculation was determined to be 

unacceptable due to safety factors. 

Low NOX burners: LNB and ULNB 

retrofits are commonly installed on 

combustion units, often as a result of 

BACT or LAER determinations and 

could be feasible at Tesoro depending 

on the specific unit application. 

Emission limits from EPA’s RACT/ 

BACT/LAER Clearinghouse range from 

0.08 to 0.1 lb/MMBtu (NOX) for LNBs 

and ULNBs. 

Staged Air Low NOX Burners: For this 

burner design, retrofitting heaters with 

less than three feet between the burner 

and the opposite wall of the firebox may 

not be practical due to potential flame 

impingement on the firebox refractory 

materials or heat transfer tubes. 

Emission reductions achieved by stagedair LNBs range from 30 to 40 percent 

below emissions from conventional 

burners. Tesoro used a 40 percent NOX

reduction for its initial cost analysis 

review. 

Staged-fuel, low-NOX burners: Stagedfuel LNBs have several advantages over 

staged-air LNBs. First, the improved 

fuel/air mixing reduces the excess air 

necessary to ensure complete 

combustion. The lower excess air both 

reduces NOX formation and improves 

heater efficiency. Second, for a given 

peak flame temperature, staged-fuel 

LNBs have a more compact (shorter) 

flame than staged-air LNBs. Up to 72 

percent NOX emissions reductions for 

staged-fuel LNBs have been reported 

over conventional burners based on 

vendor test data. Tesoro used a 60 

percent average NOX reduction for its 

initial cost analysis review. 

Ultra Low NOX Burners: Tesoro used 

a 75% average NOX reduction for its 

initial cost analysis based on EPA 

methods. After receiving vendor 

guaranteed average NOX emission 

reductions ranging from 60 to 73.5 

percent for specific units, Tesoro 

developed a vendor cost factor analysis 

for each unit based on the vendor 

guarantee and the unit-specific emission 

rate. 

Selective Non-Catalytic Reduction 

(SNCR): Vendor NOX reduction 

guarantees ranged from 35 to 40% based 

on Tesoro’s fuel gas compositions and 

measured bridgewall temperatures. 

EPA’s RACT/BACT/LAER 

Clearinghouse lists an emission limit of 

127 ppmdv NOX at seven percent 

oxygen for a SNCR used to control 

emissions from a Fluid Catalytic 

Cracking Regenerator unit followed by a 

CO Boiler. 

NOX tempering (steam or water 

injection): To date, NOX tempering has 

only been used on large utility boilers 

and was not considered for further 

analysis. 

Selective Catalytic Reduction (SCR): 

Typical SCR NOX removal efficiencies 

range from 70 to 90+ percent removal, 

depending on the unit being controlled. 

Tesoro used a 90 percent NOX removal 

in its cost analyses. 

SO2 Controls Evaluated for All 

Combustion Units 

Plant-Wide SO2 Control: Plant-wide 

SO2 control is accomplished by 

reducing the sulfur content of fuel 

burned in various combustion units. 

Requiring the use of ‘‘low sulfur fuel’’ 

is the most common SO2 control 

technique applied to oil refinery process 

units. ‘‘Low sulfur fuel’’ is usually 

defined as refinery fuel gas meeting the 

New Source Performance Standard 

(NSPS) requirements of 40 CFR part 60, 

Subpart J. This NSPS limits the H2S in 

fuel gas to 0.1 gr/dscf. 

Tesoro has already implemented 

improvements at the facility to reduce 

the H2S concentration in the flue gas; 

any additional reduction in refinery fuel 

gas sulfur content will require 

construction of a new sulfur recovery 

unit (SRU). Tesoro evaluated the 

construction of a new 50 ton/day SRU 

and refinery modifications to route 

sulfur streams to the new unit. The 


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capital cost is estimated to be $58 

million to continuously treat all refinery 

gas to the level of the NSPS standard 

(162 ppm of H2S). Attributing all the 

cost to the SO2 reductions to all 

combustion units (not just the BART 

eligible units) results in a plant wide 

reduction from the 2003 to 2005 average 

emissions of 395 tons of SO2 with a cost 

effectiveness of $16,100/ton of SO2 (not 

including O&M costs). Tesoro also 

evaluated the cost effectiveness of 

continuously meeting a limit of 50 ppm 

of H2S (a plant wide annual decrease of 

451 tons per year), with the use of a new 

SRU. To meet a 50 ppm H2S 

concentration would increase the cost 

effectiveness value to $14,100/ton (also 

not including O&M costs). 

Washington determined that the 

construction of a new SRU to meet 

either 162 ppm H2S or 50 ppm H2S is 

not cost effective and that SO2 BART for 

combustion units burning refinery fuel 

gas is the current H2S limit of 0.10 

percent by volume (1000 ppm) . See 

Washington’s BART Compliance Order 

7838. 

PM Controls Evaluated for All 

Combustion Units 

With the exception of emissions from 

unit F–304 (which primarily burns 

carbon monoxide from the fluid 

catalytic cracking unit and emits 

negligible amounts of PM), PM controls 

applicable to the process heaters at this 

facility are tied directly to the use of 

combustion fuel. Using low sulfur 

refinery fuel gas reduces potential 

particulate emissions. The refinery gas 

system includes process steps to remove 

particulates and some heavier 

hydrocarbons from the refinery gas prior 

to being sent to the various fuel burning 

units. 

Washington determined PM BART is 

the curtailment of fuel oil for 

combustion with the substitution of 

refinery fuel gas. The specific emission 

limit for unit F–304 is 0.11 gr/dscf, 

corrected to 7% O2. Particulate matter 

BART for all other BART units is 0.05 

gr/dscf, corrected to 7% O2. 

Unit Specific BART Determinations for 

NOX

Unit F–103, Crude Oil Distillation 

Heater: ULNB, SCR, SNCR, ULNB plus 

SCR, and ULNB plus SNCR were 

evaluated for cost effectiveness. Only 

ULNB, with a control efficiency of 75% 

had a reasonable cost effectiveness 

value at $3398/ton, using EPA 

calculation methods, and. All others 

cost effectiveness values exceeded 

$6374/ton. Washington determined 

ULNB to be BART for Unit F–103. 

Unit F–104, Gasoline Splitter Reboiler: 

This reboiler currently has ULNB 

installed. The next more efficient 

control technology would be the 

addition of SCR with a cost 

effectiveness of $100,000/ton. See Table 

2.1 of appendix L, Tesoro BART 

determination. Washington determined 

this cost to be unreasonable. 

Unit F–6650, Catalytic Reformer Feed 

Heater; Unit F–6651, Catalytic Reformer 

Inter-Reactor Heater; Unit F–6652, 

Catalytic Reformer Inter-Reactor Heater; 

Unit F–6653, Catalytic Reformer InterReactor Heater: These four heater units 

are ducted into two common exhaust 

stacks. However, the BART evaluations 

regarding burner design (e.g. LNB vs 

ULNB) and add on control (e.g. SCR) 

were made separately for each unit by 

the State, and are presented below. 

Unit F–6650: The SIP submittal 

analyzed LNB, ULNB, SCR, SCR with 

LNB, and SCR with ULNB. ULNB is not 

technically feasible since there is 

insufficient space to install it. LNB is 

estimated to achieve a 60% reduction in 

NOX, is cost effective at $3349/ton if 

installed during turnaround and over 

$10,000/ton outside normal turnaround. 

All of the SCR combinations are not cost 

effective with costs exceeding $10,000/ 

ton during turnaround and even greater 

during non-scheduled turnaround 

refinery maintenance. Washington 

determined BART for NOX emissions to 

be existing control. 

Unit F–6651: The SIP submittal 

analyzes LNB, ULNB, SCR, SCR with 

LNB and SCR with ULNB. There is 

insufficient space to install ULNB thus 

it is not technically feasible. The cost of 

installing SCR on the common exhaust 

duct in addition to LNB is not 

reasonable with a cost effectiveness of 

greater than $10,000/ton. LNB with 60% 

control efficiency and a cost 

effectiveness of $3349/ton within the 

routine maintenance turnaround was 

determined to be reasonable. 

Washington found that the cost 

effectiveness increases to over $10,000/ 

ton if the controls were required to be 

installed during non-routine turnaround 

and stated that the routine turnaround 

will be outside the BART 

implementation window requirement. 

However, as explained below this is no 

longer the case. 

Washington determined BART for 

NOX emissions to be existing control. 

Unit F–6652: The SIP submittal 

analyzes LNB, ULNB, SCR, SCR with 

LNB and SCR with ULNB. Cost 

effectiveness of SCR options exceed 

$10,000/ton and thus these options are 

not reasonable. LNB and ULNB are cost 

effective and technically feasible. ULNB 

with a control efficiency of 75% and 

cost effectiveness of $3349/ton was 

determined to be BART for NOX

emissions, if installed during routine 

turnaround. Washington found that the 

cost effectiveness values increase to 

over $10,000/ton if installed outside 

routine turnaround, and stated that the 

routine turnaround will be outside the 

BART implementation window 

requirement. However, as explained 

below this is no longer the case. 

Washington determined BART for NOX

emissions to be existing control. 

Unit F–304: The cost effectiveness of 

LNB, SCR, SNCR, LNB plus SCR, and 

LNB plus SNCR was evaluated. LNB 

with SNCR, with a control efficiency of 

39% and cost effectiveness of $4592/ton 

when installed during turnaround was 

determined to be reasonable 

Washington calculated the cost 

effectiveness to be over $10,000/ton if 

the installation was conducted outside 

of the regularly scheduled turnaround. 

SNCR without LNB has a 35% control 

efficiency at a cost of $4534/ton and was 

not considered further as the control 

efficiency is less than LNB with SNCR. 

All other options are not cost effective. 

See Table 2–3 of the Tesoro BART 

Determination, appendix L of the SIP 

submittal. 

Washington’s NOX BART 

determination for unit F–304 (CO Boiler 

No. 2) indicated that an emission limit, 

representative of the installation of LNB 

plus SNCR, would be reasonable if the 

controls could be installed during 

routine maintenance ‘‘turnaround’’ at 

Tesoro. Turnarounds are the only 

occasion when process units are 

intentionally taken out of operation, and 

during a turnaround, major maintenance 

occurs on all process units that are shut 

down. During a routine turnaround, 

low-NOX burners or other appropriate 

controls could be installed and loss of 

production would not be included in 

the cost-effectiveness calculations. 

However, for the analysis contained in 

the SIP submittal, Washington assumed 

that the date for EPA’s action to approve 

or disapprove the SIP submittal, plus 

the time allowed to comply with BART 

(i.e., as expeditiously as practicable, but 

no later than five years after SIP 

approval), would occur prior to the next 

scheduled turnaround. More 

specifically, Tesoro informed 

Washington that the next scheduled 

turnaround would not occur until 2017, 

which Washington had estimated would 

be after the date the BART controls 

would need to be installed. 

Consequently, Washington estimated 

costs for BART to include lost 

production, since, in order to comply 

within BART timeframe, the facility 

would be required to install the controls 


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76196 Federal Register / Vol. 77, No. 247 / Wednesday, December 26, 2012 / Proposed Rules 

well before the 2017 turnaround. 

Including lost production into the costs, 

results in most cases in a cost 

effectiveness figure well in excess of 

$10,000/ton and the controls are not 

cost-effective. As a result, Washington 

determined that no additional control 

was required for BART for NOX for 

boiler F–304. 

However, as it turns out, the BART 

compliance time frame (which is now 

estimated to be no later than mid-2018) 

is much later than Washington 

originally estimated and now could 

indeed accommodate the 2017 

turnaround cycle. When calculating 

cost-effectiveness without considering 

lost production, Washington concluded 

that controls for BART would in fact be 

reasonable. For example, see appendix 

L–3, Table 2–3, page L–125 of the SIP 

submittal showing a vendor cost 

estimate of $4,592/ton for installation of 

LNB plus SNCR for the boiler F–304. 

Therefore, Washington would have 

concluded that, except for the costs 

associated with taking units offline 

outside of the turnaround cycle, BART 

for NOX for unit F–304, would be an 

emission limit associated with 

installation of LNB plus SNCR. Yet, 

because of the added costs estimated for 

lost production, Washington proposed 

no add on controls in the SIP submittal. 

A similar circumstance applies to 

heaters F–6650, F–6651, F–6652, and F– 

6653. The SIP submission indicates that 

LNB would be cost-effective for F–6650 

and F–6651, while ultra-LNB would 

otherwise be cost-effective for F–6652 

and F–6653, except for the added costs 

due to lost production. Again, 

Washington determined BART was no 

add-on controls on these units, due to 

costs of lost production because of the 

assumption that Tesoro would need to 

take the units offline outside of the 

normal turnaround schedule in order to 

comply with BART. It is now evident 

however, that the BART compliance 

deadline could be structured to include 

time for the scheduled turnaround. 

Thus, Washington’s BART 

determination of no controls for these 

units is not appropriate since the 

controls are cost effective if installation 

is conducted during a scheduled 

turnaround period. 

In today’s action, we are proposing to 

disapprove Washington’s BART 

determinations for NOX for units F–304, 

F–6650, F–6651, F–6652, and F–6653. 

We are proposing to approve 

Washington’s BART determinations for 

SO2 and PM for all of Tesoro’s BART 

subject units, and for NOX for units F– 

103, F–104, F–654, F–6600, F–6601, F– 

6602, F6654, and F–6655. 

Tesoro Request for Alternative BART 

Program 

As discussed above under the Intalco 

BART section, a state may choose to 

implement measures as an alternative to 

BART, so long as the alternative 

measures can be demonstrated to 

achieve greater reasonable progress 

toward the national visibility goal than 

would be achieved through the 

installation and operation of BART. See 

40 CFR 51.308(e)(2). 

In light of the currently expected date 

estimated for EPA’s final action on the 

SIP submittal, EPA does not consider 

Washington’s BART determination for 

NOX for several units at the facility to 

be approveable. Tesoro submitted a 

request to EPA on November 5, 2012, for 

an alternative to BART for NOX for units 

F–304, F–6650, F–6651, F–6652, and F– 

6653. Based on the analysis described 

below, EPA agrees that the alternative 

proposed by Tesoro is Better than 

BART, and because we are proposing to 

disapprove Washington’s BART 

determination for NOX for those units, 

we are also proposing a FIP as an 

alternative to BART, that results in 

greater reasonable progress than BART 

would for units, F–304, F–6650, F–6651, 

F–6652, and F–6653. We believe that 

the proposed Tesoro NOX BART 

alternative meets the requirements for 

an alternative measure. 

Tesoro NOX BART Alternative 

EPA is proposing a BART alternative 

for the NOX emissions from the CO 

boiler #2 (unit F–304) and the four 

heaters, units F–6650, F–6651, F–6652, 

and F–665. This BART alternative 

achieves greater visibility progress than 

BART would for those units. 40 CFR 

51.308(e)(2) and 40 CFR 51.308(e)(3) of 

the regional haze rule specify the 

requirements that a state must meet to 

show that an alternative measure or 

alternative program achieves greater 

reasonable progress than would be 

achieved through the installation and 

operation of BART. Pursuant to those 

requirements, Tesoro has identified 

seven non-BART units at the facility 

that achieve substantially more SO2

emission reductions compared to their 

baseline emissions than the NOX

emission reductions that would be 

achieved from BART on the five BART 

subject units compared to their baseline 

emissions. The facility has requested 

SO2 emission limitations on those nonBART units as an alternative to 

emission limits for NOX on the BARTsubject units. EPA believes it is 

appropriate to consider SO2 reductions 

as a substitute for NOX reductions for 

the alternative BART scenario since the 

SO2 reductions, which are more than 

twice the NOX reductions, will likely 

result in proportionately more sulfate 

than nitrate removed from the 

atmosphere. Accordingly, visibility 

improvement would be greater under 

the alternative than under BART. The 

table below shows the seven non-BART 

eligible units for which Tesoro is 

requesting SO2 emission limits under 

the proposed alternative. 

SO2 UNITS REGULATED UNDER THE

PROPOSED BART ALTERNATIVE

Unit Description 

F–101 ...... Crude Heater, 120 MMBtu/hr. 

F–102 ...... Crude Heater, 120 MMBtu/hr. 

F–201 ...... Vacuum Flasher Heater, 96 

MMBtu/hr. 

F–301 ...... Catalytic Cracker Feed Heater, 

128 MMBtu/hr. 

F–652 ...... Heater, 67 MMBtu/hr. 

F–751 ...... Main Boiler, 268 MMBtu/hr. 

F–752 ...... Boiler, 268 MMBtu/hr. 

In 2007, Tesoro made a major capital 

investment to improve the sulfur 

removal capability of the Anacortes 

refinery fuel gas (RFG) system and 

accepted a limit on H2S in the fuel gas 

of 0.10 percent by volume, or 1,000 

parts per million (ppm). This resulted in 

a significant reduction in SO2 emissions 

as the average H2S concentration of the 

fuel gas in 2006 was 2,337 ppm. A 

requirement to combust only pipeline 

quality natural gas or RFG meeting the 

1,000 ppm limit was established on a 

number of units at the facility, including 

eleven BART-subject units as part of 

Washington’s BART determination for 

those units. Tesoro requested that the 

same requirement be extended to the 

seven additional non-BART units 

shown in the table above. In 

Washington Class I areas, sulfates 

contribute significantly more than 

nitrates to visibility impairment (see SIP 

Submittal chapter 5) and it is likely that 

for the Class I areas impacted by 

Tesoro’s SO2 and NOX emissions, more 

SO2 converts to sulfate than NOX does 

to nitrate. Limiting the SO2 emissions 

from these seven units would thereby 

result in greater reasonable progress 

than would requiring BART for NOX on 

the CO boiler #2 and four process 

heaters. 

In Washington Class I areas, sulfates 

contribute significantly more than 

nitrates to visibility impairment (see SIP 

Submittal chapter 5) and it is likely that 

more SO2 converts to sulfate than NOX

does to nitrate. Applying the SO2 limit 

to these 7 units would result in greater 

reasonable progress than would 

requiring BART for NOX on the CO 

boiler #2 and four process heaters. 


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Federal Register / Vol. 77, No. 247 / Wednesday, December 26, 2012 / Proposed Rules 76197 

Pursuant to 40 CFR 51.308(e)(2)(i)(D), 

a summary of the emission reductions 

expected from the BART alternative 

compared to emissions reductions that 

would be achieved by the application of 

Washington’s estimated limits for NOX

for five BART-subject units is shown in 

the tables below. 

SO2 EMISSIONS UNDER THE BART ALTERNATIVE

Unit 

2006* SO2

Baseline emissions (tpy), 

pre-RFG as 

reported by 

Tesoro 

BART alternative: 2007 

post-RFG SO2

emissions as 

reported by 

Tesoro 

Reduction in 

SO2 emissions 

(tpy) 

F–101 ........................................................................................................................................... 193 42 151 

F–102 ........................................................................................................................................... 178 48 130 

F–201 ........................................................................................................................................... 232 51 181 

F–301 ........................................................................................................................................... 58 11 47 

F–652 ........................................................................................................................................... 77 25 52 

F–751 ........................................................................................................................................... 291 54 237 

F–752 ........................................................................................................................................... 326 56 270 

Total ............................................................................................................................... 1,355 287 1,068 

*The baseline year of 2006 was used because it was the last year preceding installation of the RFG improvements and representative of operating conditions at the refinery at that time. 

NOX EMISSIONS WITH WASHINGTON’S DETERMINATION OF BART 

Unit 

2006* NOX

Baseline emissions (tpy) as 

reported by 

Tesoro 

Washington’s 

estimated 

emissions 

based on 

BART analysis 

in SIP submittal (appendix L) 

Projected reduction in NOX

emissions 

from BART 

controls (tpy) 

F–304 ........................................................................................................................................... 717 437 280 

F–6650 ......................................................................................................................................... 151 60 91 

F–6651 ......................................................................................................................................... 114 46 68 

F–6652 ......................................................................................................................................... 24 6 18 

F–6653 ......................................................................................................................................... 12 3 9 

Total ............................................................................................................................... 1,018 552 466 

*The baseline year of 2006 for NOX corresponds with the year the emissions were estimated for SO2. 

The projected NOX emissions are 

based on Washington’s estimates of 

appropriate control efficiencies applied 

to the 2006 emission rates. 

Washington’s estimates are: SNCR plus 

LNB for F–304 with 39% reduction in 

NOX; LNB for F–6650 and F–6651 with 

60% reduction in NOX; ULNB for F– 

6652 and F–6653 with 75% reduction in 

NOX. EPA believes that for purposes of 

estimating the NOX BART emission 

benchmark for 2006, Washington’s 

estimates are adequate. 

As the tables show, the 1,068 tpy 

reductions in SO2 from the seven nonBART units are greater than the 466 tpy 

emissions reductions expected from 

BART for NOX for the five BART-subject 

units. The reductions are surplus 

because they occurred during the first 

planning period, after the 2002 SIP 

baseline date and were not necessary to 

meet any other CAA requirements. As a 

final check, we note that SO2 emissions 

from the seven units, if calculated 

assuming that the plant is operating at 

full capacity, would be 10,147 tpy prior 

to the refinery fuel gas improvements in 

2007 and 1,127 tpy after applying the 

1000 ppm H2S limit. The net SO2

emission reduction is estimated to be 

9,020 tons, compared to 683 tons of 

NOX reductions assuming BART level 

controls for NOX were installed and the 

plant were operating at full capacity. 

For these reasons, EPA is proposing a 

BART alternative FIP that achieves 

greater reasonable progress than BART. 

The proposed emission limit for the 

seven units being considered for the 

alternative to BART is the same limit as 

the other 11 BART-subject units for 

which we are proposing to approve. 

Specifically, the refinery fuel gas may 

not contain greater than 0.10 percent by 

volume H2S on a 365-day rolling 

average basis. Setting the limit based on 

the concentration of H2S in the fuel is 

consistent with the Standards of 

Performance for Petroleum Refineries 

(See 40 CFR part 60—Subpart J) and 

51.308(e)(iii) for establishing BART. 

Since the proposed alternative would 

utilize the same requirement for 

monitoring refinery fuel gas combusted 

in the non-BART units that Washington 

has imposed for the BART-subject units, 

the proposed alternative would not 

impose any additional monitoring 

requirements. It would impose 

additional recordkeeping and reporting 

requirements related to the fuel 

combusted in the non-BART units. 

Tesoro’s November 5, 2012, letter 

actually included two options for a 

Better than BART alternative. The other 

option involved SO2 emission 

reductions from another non-BART 

unit, CO boiler #1 (Unit F–302). 

However, we did not choose that option 

for the proposed Better than BART FIP 

because CO boiler #1 shares a common 

exhaust stack with CO boiler #2 (Unit 

F–304) which is a BART-eligible unit 

and the Washington BART order 

establishes an SO2 limit for the 

combined emissions from both boilers. 

Even though Washington has not relied 


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76198 Federal Register / Vol. 77, No. 247 / Wednesday, December 26, 2012 / Proposed Rules 

on the SO2 reductions since baseline 

from CO boiler #1 in its regional haze 

plan, EPA is obliged to approve that 

limit as shown in the BART order and 

cannot use those same reductions in a 

Better than BART alternative FIP. 

However, EPA does want to point out 

that, when approved, the BART order 

will actually result in greater visibility 

improvements than projected in the 

regional haze reasonable progress 

demonstration. 

Summary of Tesoro BART 

The Table below is a summary of the 

proposed BART and Proposed Better 

than BART Technology for Tesoro. 

Emission unit BART technology 

F–103 ........................................................................................................ PM: End routine use of fuel oil. Use of refinery fuel gas or natural gas 

as primary fuel. 

SO2: End routine use of fuel oil. Use of refinery fuel gas or natural gas 

as primary fuel. 

NOX: Ultra-low-NOX burners. 

F–304, F–6650, F–6651, F–6652, F6653 ................................................ SO2 & PM: End routine use of fuel oil. Use of refinery fuel gas or natural gas as primary fuel. 

Proposed Better than BART Alternative Federal Implementation Plan: 

SO2 limitations on units F–101, F–102, F–201, F–301, F–652, F– 

751, F–752 fuel gas of 1000 ppmv H2S. 

F–104, F–654, F–6600, F–6601, F–6602, F–6654, F–6655, Flare X– 

819, Cooling Towers 2 and 2a.

PM: End routine use of fuel oil. Use of refinery fuel gas or natural gas 

as primary fuel. 

SO2: End routine use of fuel oil. Use of refinery fuel gas or natural gas 

as primary fuel. 

d. Port Townsend Paper Company 

Port Townsend Paper Company 

(PTPC) operates a kraft pulp and paper 

mill in Port Townsend, Washington that 

manufactures kraft pulp, kraft papers, 

and lightweight liner board. The four 

BART eligible emission units at the 

facility are: the recovery furnace, smelt 

dissolving tank, No. 10 power boiler, 

and lime kiln. PTPC visibility impacts 

are greatest at Olympic National Park. 

The 98th percentile impact during 2003 

to 2005 at Olympic National Park is 1.9 

dv. Impacts at all other Class I areas 

within 300 km of PTPC were less than 

0.5 dv. 

An electrostatic precipitator (ESP) 

currently controls PM from the recovery 

furnace, a wet scrubber currently 

controls PM and SO2 from the smelt 

dissolving tank, a multiclone and wet 

scrubber control PM emissions from the 

No. 10 power boiler, and a wet venturi 

scrubber controls PM and SO2 from the 

lime kiln. On October 20, 2010, 

Washington issued PTPC BART Order 

7839 Revision 1 which establishes 

emission limits for these existing 

controls for the emission units subject to 

BART. 

Recovery Furnace: The recovery 

furnace primarily burns black liquor 

solids with some recycled fuel oil. It 

emits SO2, NOX, and PM. The recovery 

furnace is intended to recover sulfur for 

use in the pulping process and the loss 

of sulfur through emissions of SO2 is a 

loss of process chemical and therefore is 

undesirable for business reasons. The 

recovery furnace operations are 

optimized to minimize sulfur loss. 

Particulate matter is currently 

controlled with three dry electrostatic 

precipitators (ESPs). Current SO2 and 

PM emissions are regulated by 

NESHAPS Subpart MM, and a PSD 

permit. NOX emissions from recovery 

furnaces are generally low. Currently, 

there is no emission limit for NOX. 

NOX: The recovery furnace inherently 

uses staged combustion to optimize 

combustion of black liquor (mostly 

lignins) to recover the sulfur. Also due 

to the unique nature of the recovery 

process, special safety precautions must 

be considered as explosion can occur. 

Washington and PTPC evaluated 

alternative NOX control technologies 

and found them technically infeasible. 

See SIP submittal pages L–206 and L– 

207. Washington determined that the 

existing level of control provided by the 

existing staged combustion system is 

BART for NOX for the recovery furnace. 

SO2: Washington and PTPC 

considered the Wet FGD, Dry FGD and 

low sulfur fuel as possible control 

technologies for the recovery furnace 

SO2 emissions. Wet FGD is considered 

cost prohibitive by the National Council 

for Air and Stream Improvement 

(NCASI). See Information on Retrofit 

Control Measures for Kraft Pulp Mill 

Sources and Boilers for NOX, SO2, and 

PM Emissions, June 4, 2006. 

Additionally, due in part to the nature 

of the SO2 emissions from a kraft 

recovery furnace, and related technical 

difficulties, this technology is 

considered technically infeasible for 

control of SO2 emissions at this facility. 

Table 2–4, PTPC BART determination, 

appendix L of the SIP submittal. 

Dry FGD is also not technically 

feasible as injection of a sorbent 

material disrupts the chemical reactions 

in the furnace and the sulfur content of 

the gas stream is too low for effective 

control of SO2. The analysis also found 

that low sulfur fuel is not an option as 

the main fuel source is the black liquor 

from which sulfur is recovered. In 

essence, the recovery furnace is a 

control device to recover sulfur from the 

black liquor. Supplemental fuel oil is 

currently limited to a maximum of 

0.75% sulfur content. Switching to a 

lower sulfur content fuel oil would cost 

$15,702/ton of SO2 removed and is 

deemed not cost effective. Washington 

determined that the current level of 

controls provided by the existing staged 

combustion system and regulated by the 

PSD permit is BART for SO2, with an 

emission limit of 200 ppm at 8% O2. 

PM: The PM emissions from the 

recovery furnace are currently 

controlled by an ESP. The existing ESP 

at the furnaces reduces actual PM 

emissions to an average of less than 

50% of the MACT limit of 0.044 gr/dcsf, 

at 8% O2. The BART Guidelines, section 

IV, states that ‘‘Unless there are new 

technologies subsequent to the MACT 

Standards which would lead to cost 

effective increases in the level of 

control, [state agencies] may rely on 

MACT standards for purposes of 

BART.’’ No new control technologies 

have been identified for recovery 

furnaces, thus Washington determined 

that the dry ESP meeting MACT limits 

is BART. Thus, the BART limit is the 

NESHAP Subpart MM limit of 0.044 gr/ 

dscf at 8% oxygen. 

Smelt Dissolving Tank 

NOX control: There are no NOX

emissions from the smelt dissolving 


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Federal Register / Vol. 77, No. 247 / Wednesday, December 26, 2012 / Proposed Rules 76199 

tank thus a BART determination for 

NOX is not necessary. 

SO2 Control: Sulfur dioxide emissions 

are currently controlled by a wet 

scrubber. The only other available 

control option is either semi-dry or dry 

FGD. However, due to the very low 

exhaust flow rate, semi-dry or dry FGD 

with a dry ESP is technically infeasible. 

Adding an alkaline solution to the 

exhaust gas stream could provide 

additional SO2 control. Washington’s 

analysis found cost effectiveness of 

adding the alkaline solution to both is 

$16,247/ton and is not cost effective. 

Washington found BART for SO2 is the 

existing wet scrubber for PM control. 

PM Control: PM emissions are 

currently controlled by a dry ESP. 

Washington evaluated the cost of 

upgrading the current ESP to reduce 

existing PM emission by 50%. The cost 

effectiveness of this upgrade is $5,100/ 

ton with a visibility improvement of 

0.07 dv. In light of the cost and minimal 

visibility improvement, Washington 

determined the upgrades are not 

reasonable. The BART emission limit 

for PM is the NESHAP Subpart MM 

limit of 0.20 lb PM10 per ton black 

liquor solids (BLS). 

No. 10 Power Boiler: The No. 10 

power boiler currently burns a variety of 

fuels from wood waste to fuel oil and 

uses overfire air to reduce NOX

emissions. A multiclone followed by a 

wet scrubber reduces PM emissions. 

NOX: The design of the No. 10 power 

boiler which primarily burns wood 

waste results in a low flame temperature 

and minimal NOX formation. Appendix 

C of the PTPC BART Determination 

report (appendix L of the SIP submittal) 

contains a lengthy discussion of why 

alternative control technologies are not 

technically feasible including; flue gas 

recirculation, LNBs, fuel staging, SNCR, 

and SCR. Washington determined that 

the existing NOX emission limit of 0.80 

lb/MMBtu (current NSPS Subpart D 

limit) is BART for this unit. 

PM control: PM emissions from the 

No. 10 power boiler are currently 

controlled with a multiclone followed 

by a wet scrubber. The BART analysis 

evaluated fabric filters and the 

substitution of a wet ESP for the wet 

scrubber. The evaluation found that 

installation of a baghouse is technically 

infeasible for wood fired boilers due to 

the potential fire hazard. The addition 

of a wet ESP is technically feasible for 

this facility but is not cost effective at 

$11,249/ton of PM10 removed. The 

substitution of a wet ESP was also 

evaluated and it was found that due to 

the low emission rate and the small 

potential visibility improvement from 

upgrading to a wet ESP did not justify 

further study. Washington determined 

BART is the existing level of control as 

provided by the wet scrubber with a PM 

emission limit of 0.10 lb/MMBtu (the 

current NSPS Subpart D limit). 

SO2 Control: PTPC analysis found that 

FGD technology with wet injection 

using a wet scrubber would reduce SO2

emissions but would also require the 

addition of alkaline chemicals which 

would change the chemical 

characteristics of the effluent and render 

it classified under Washington as 

‘Dangerous Waste’ and as a hazardous 

waste under the federal Resource 

Conservation and Recovery Act, thus 

raising the cost and complexity of 

disposal. Fly ash from the boiler already 

aids in scrubbing SO2 and adding an 

alkaline solution would only provide a 

small increment of control, but with 

increased problems with sludge 

disposal. The analysis concluded that 

implementation of wet FGD on the No. 

10 power boiler is considered 

technically infeasible. Lowering the 

sulfur content of the fuel oil burned to 

0.5%, while technically feasible, would 

cost $15,702/ton of SO2 reduced. This 

was determined to not be cost effective. 

Washington determined that BART for 

SO2 control on the No. 10 power boiler 

is the continued operation of the 

existing wet scrubber, continued use of 

the current low sulfur fuel and 

implementing good combustion 

practices aimed at minimizing recycled 

fuel oil firing as BART. The existing SO2

emission limit is 0.30 lb/MMBtu. 

Lime Kiln 

PM: Currently the lime kiln uses wet 

venturi scrubber to capture PM 

emissions to meet the PM emission 

limits as specified in 40 CFR 63, 

Subpart MM. No new control 

technologies have been developed since 

the rule was promulgated therefore as 

explained above, Washington 

determined that wet venturi scrubber is 

BART. BART for PM is the same as 40 

CFR 63, Subpart MM, with an emission 

limit of 0.064 gr/dscf at 10% O2.

NOX: The lime kiln is operated using 

a minimum of excess air. Washington’s 

review determined that no add-on 

control technology was indicated for 

lime kilns in the EPA RBLC which lists 

‘‘good combustion’’ and ‘‘proper kiln 

design’’ as BACT for lime kilns. 

However, as described in the SIP 

submittal, PTPC investigated ten other 

possible control options. Each of these 

control options were determined to be 

infeasible. See Washington Regional 

Haze SIP submittal L–190. Therefore 

Washington determined that BART for 

NOX for the lime kiln is proper kiln 

design and good operating practices. 

SO2: The existing wet venturi 

scrubber captures lime dust and thereby 

also reduces SO2 emissions. Washington 

and PTPC considered several additional 

SO2 control technologies including 

increasing the alkalinity. See SIP 

submittal Table 2–3. However, the 

visibility improvement from increasing 

the alkalinity of the wet scrubber was 

estimated to be only 0.004 dv and did 

not warrant further consideration. As for 

other units in the facility, lower sulfur 

fuel oil was determined to not be cost 

effective due to the increased fuel cost 

and resulting cost effectiveness value of 

$15,702/ton. As documented in the SIP 

submittal each of the other technologies 

considered was rejected due to technical 

difficulties. See Washington Regional 

Haze SIP submittal L–213. Washington 

determined that BART for SO2 for the 

lime kiln is the current level of control 

provided by the wet venturi scrubber. 

The SO2 emission limit is continued use 

of the existing wet scrubber with 

inherently alkaline scrubber solution 

and 500 ppm at 10% O2 (current 

Washington limit). 

For of the reasons summarized above, 

Washington determined that the 

existing controls, techniques and 

emission limits constitute BART for 

NOX, SO2, and PM at the facility. The 

SIP submittal includes BART 

Compliance Order No. 7839, Revision 1, 

issued to Port Townsend Paper 

Corporation on October 20, 2010. 

EPA finds after review of the SIP 

submittal that the BART determination 

and BART compliance order for PTPC is 

reasonable and proposes to approve it. 

Summary of Port Townsend Paper 

Company BART 

The table below summarizes the 

proposed BART technology for PTPC: 

Emission Unit BART Technology 

Recovery Furnace .................................................................................... PM: Existing ESP. 

NOX: Existing staged combustion system. 

SO2: Good Operating Practices and limit of 200 ppm at 8% O2. 


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Emission Unit BART Technology 

Smelt Dissolving Tank .............................................................................. PM: Existing wet scrubber NESHAP Subpart MM limit of 0.20 lb PM10

per ton BLS. 

SO2: Existing wet scrubber. 

No. 10 Power Boiler ................................................................................. PM10: Existing multiclone and wet scrubber NSPS Subpart D limit of 

0.10 lb/MMBtu. 

NOX: Existing staged combustion system NSPS Subpart D limit of 0.30 

lb/MMBtu. 

SO2 Good Operating Practices NSPS Subpart D limit of 0.80 lb/ 

MMBtu. 

Lime Kiln ................................................................................................... PM10: Existing venturi wet scrubber NESHAP Subpart MM limit of 

0.064 gr/dscf at 10% O2. 

NOX: Good Operating Practices. 

SO2: Existing wet scrubber 500 ppm at 10% O2. 

e. Lafarge North America 

Lafarge North America is located in 

Seattle, Washington and produces 

Portland cement by the wet kiln 

process. The facility consists of 18 

emission units of which 16, in 

combination, meet the requirements as 

eligible for BART. Dispersion modeling 

of these16 emission units show 

emissions from these units exceed the 

visibility threshold of 0.5 dv for being 

subject to BART and thus are subject to 

BART. The largest sources of concern 

that are subject to BART are the rotary 

kiln and the clinker cooler. The other 

BART units include raw material 

handling, finished product storage bins, 

finish mill conveying system, bagging 

system, and bulk loading/unloading 

system baghouses, with a total of just 

480 t/y emissions of PM. 

Lafarge North America is subject to 

the terms and conditions specified in a 

consent decree resolving alleged Clean 

Air Act violations. United States v. 

LaFarge North American Inc, Civ. 3:10– 

cv–00044–JPG–CJP (S.D. Ill.). This 

consent decree established emission 

limitations and compliance dates for a 

number of cement plants owned and 

operated by Lafarge North America, 

including the Seattle plant. 

Rotary Wet Process Kiln 

SO2: There is currently no control for 

SO2 from the kiln at the Lafarge facility. 

The alkaline nature of the clinker 

formed in the kiln reduces SO2

emissions to some extent. Additional 

control options evaluated were: dry 

sorbent injection (lime or sodium), 

semi-dry FGD, wet limestone forced 

oxidation, wet lime, ammonia forced 

oxidation, and alternative fuels and raw 

materials. See SIP Submittal appendix 

L, L–231,Table 2–2, Lafarge BART 

determination. The analysis found that 

dry sorbent injection (DSI) is technically 

feasible with a 25% removal efficiency 

for SO2 at an estimated the cost 

effectiveness of $4034/ton. See Table 2– 

3 of appendix L, Lafarge BART 

determination. Washington determined 

that while the cost effectiveness value 

for DSI at this facility is relatively high 

compared to other cost effectiveness 

values that are considered BART, the 

visibility improvement at Olympic 

National Park is significant (0.8 dv) and 

warrants this control as BART. 

Washington determined dry sorbent 

injection with emission limit of not to 

exceed 8620 lb/day as BART. 

Limestone slurry forced oxidation 

(LSFO) is a technically feasible control 

option with a control efficiency of 95% 

for SO2. Cost effectiveness is $32,920/ 

ton and is considered not reasonable for 

this facility. Lafarge considered, but 

rejected, wet lime scrubbing, which is 

similar to LSFO, but uses lime instead 

of limestone. The resulting waste 

product cannot be recycled into the 

process and would incur the additional 

cost to landfill. Also the cost of lime is 

considerably more than limestone. Both 

these factors would increase the cost 

effectiveness values even higher than 

LSFO. 

NOX: Currently NOX emissions from 

the kiln are controlled by combustion 

control. As explained in greater detail in 

the Washington Regional Haze 

Submittal appendix L, Washington 

evaluated additional control options. In 

summary its analysis found that LNB 

with indirect firing is a technically 

feasible control option with a 15% 

control efficiency and cost effectiveness 

of $19,246/ton of NOX reduced. The 

analysis determined that SCR has not 

proven effective in other wet process 

kiln cement plants that have used SCR. 

Thus SCR is not considered an available 

technology for this unit. 

Washington found that SNCR is 

technically feasible at the facility with 

a 40% control efficiency and cost 

effectiveness value of $1409/ton. 

Washington has determined SNCR to be 

one option available to comply with 

BART at this facility. As part of their 

BART analysis, Washington also 

considered mid-kiln firing with whole 

used tires. Mid-kiln firing changes the 

combustion characteristics and provides 

a 40% control of NOX. As Lafarge has 

already installed, but currently does not 

use the equipment for mid-kiln firing 

with whole tires, the cost effectiveness 

is low. Washington has determined that 

mid-kiln firing with whole tires is an 

available option to comply with BART. 

Finally, low NOX burners with indirect 

firing and SNCR were evaluated. LNB 

with SNCR is technically feasible with 

a control efficiency of 55%. Cost 

effectiveness is determined by 

Washington to be $6247/ton. The 

incremental cost of adding LNB to 

SNCR is $14,900/ton. Washington 

determined that the incremental cost of 

adding LNB to SNCR is not cost 

effective. Thus, Washington determined 

that BART for NOX to be either SNCR 

or mid-kiln firing of whole tires with an 

emission limit of 22,960 lb/day. 

PM: The initial design of the Lafarge 

facility was for two kilns, but only one 

was built. Two ESPs were constructed, 

assuming a second kiln would be built. 

Currently, the exhaust gasses are ducted 

to both ESPs which decreases the flow 

rate by half and increases the control 

efficiency to 99.95%. This control 

efficiency is equal to that of a baghouse. 

Washington determined the existing 

ESPs are BART for PM with an emission 

limit of 0.05 g/dscf. 

Clinker Cooler: There are no SO2 or 

NOX emissions from the Clinker Cooler 

and a BART determination for these 

pollutants was not conducted. Currently 

PM emissions from the clinker cooler 

are controlled by baghouses. The 

current baghouses control 99.8% of PM 

emissions, which is equal to an ESP. 

While other controls such as wet 

scrubbers or wet venture scrubbers are 

available, the analysis completed by 

Lafarge found that these other 

technologies did not control PM 

emissions as well as the baghouses 

currently in use at the facility. 

Therefore, Washington determined the 

existing primary and backup baghouses 


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and the emissions limitations for these 

units contained in Regulation 1, section 

9.09 (as in effect on June 30, 2008) and 

Order of Approval No. 5627 as BART. 

All other sources: Existing baghouses 

were determined to be BART for PM 

with an emission limit of 0.005 g/dscf. 

Washington on July 28, 2010 issued 

Lafarge a revised BART Order No. 7841 

requiring compliance with BART, 

including monitoring, recordkeeping 

and reporting requirements. See 

appendix L of the SIP submittal, Lafarge 

BART determination. Washington’s 

BART determination and required 

controls for Lafarge is expected to result 

in approximately 1.1 dv visibility 

improvement in Olympic National Park 

and 0.2 to 0.8 dv improvement at the 

other affected Class I areas. 

Summary of Proposed Lafarge BART 

Technology 

The table below summarizes the 

proposed BART technology for Lafarge. 

Emission unit BART technology 

Clinker Cooler ..................................................... PM/PM10/PM2.5: Existing baghouses 0.025 g/dscf for the primary baghouse 0.005 g/dscf for 

backup baghouse. 

Rotary Kiln .......................................................... PM/PM10/PM2.5: Existing electrostatic precipitators 0.05 g/dscf. 

NOX: SNCR or Mid-kiln firing of whole tires not to exceed 22960 lb/day. 

SO2: Dry sorbent injection with lime plus currently permitted fuels and the cement kiln process 

not to exceed 8620 lb/day. 

All Other PM10 Sources at Plant ........................ PM10: Existing baghouses 0.005 g/dscf. 

f. TransAlta Centralia Generation, LLC 

TransAlta Centralia Generation LLC, 

located in Centralia, Washington 

operates a two unit coal-fired power 

plant rated at 702.5 megawatt each, 

when burning coal from the Centralia 

coalfield as originally designed. These 

units are BART eligible and subject to 

BART as described in the SIP submittal, 

Supplement to appendix L. The units 

now burn Powder River Basin coal and 

are each rated at 670 MW. On June 11, 

2003, EPA approved a revision to the 

Washington Visibility SIP which 

included controls for NOX, SO2, and 

PM. In the action approving these 

provisions of the Visibility SIP, EPA 

determined the controls to be BART for 

SO2 and PM but not for NOX. The NOX

controls included in the November 1999 

Visibility SIP revision, which EPA 

approved into the SIP, were Alstrom 

concentric low NOX burners with 

overfire air. TransAlta continues to be a 

BART eligible source for NOX. 

Washington’s December 22, 2010 

Regional Haze SIP submittal included a 

BART determination for TransAlta 

which was updated on December 29, 

2011. EPA approved the updated 

TransAlta NOX BART determination on 

August 20, 2012. The SIP approved 

BART determination imposes a NOX

emission limitation of 0.21 lb/MMBtu 

for each unit based on the installation 

of SNCR on both coal-fired units plus 

Flex Fuel. It also requires a one year 

performance optimization study and 

lowering the emission limits based on 

the study results. Additionally, the 

BART determination requires one unit 

to cease burning coal by December 31, 

2020 and the second unit by December 

31, 2025 unless Washington determines 

that state or federal law requires SCR to 

be installed on either unit. 

g. Weyerhaeuser Company-Longview 

Weyerhaeuser operates a Kraft pulp 

and paper mill in Longview, 

Washington. The facility has three 

emission units subject to BART: the No. 

10 recovery furnace, No. 10 smelt 

dissolver tank and No. 11 power boiler. 

The recovery furnace currently controls 

PM emissions with an ESP. It also 

employs tertiary over fire air to control 

combustion and maximize chemical 

recovery. The recovery furnace 

currently is regulated by a PSD permit 

requiring BACT and 40 CFR part 63 

Subpart MM. The smelt dissolver tank 

emits PM controlled with a high 

efficiency wet scrubber which was 

permitted as BACT in 1993 and is 

subject to 40 CFR part 63 Subpart MM. 

The No. 11 power boiler provides 

steam for electricity generation and 

plant operations. It burns a combination 

of wood waste, dewatered waste water 

treatment sludge, and supplemental low 

sulfur coal (<2% sulfur by weight). 

Emissions from the No.11 power boiler 

are subject to BACT in the facility’s New 

Source Review (NSR) permit and 40 

CFR part 60 Subpart D NSPS and are 

controlled by: 1) a multiclone to remove 

large particulate, 2) dry trona injection 

to remove SO2, and 3) a dry ESP for 

additional particulate control. NOX

emissions are controlled with good 

combustion practices. 

Recovery Furnace BART Options 

PM: Washington evaluated two 

technically feasible control options for 

increased PM control: wet ESP and 

venturi scrubber. A wet ESP would not 

provide any additional reduction in PM 

over the current dry ESP. A venturi 

scrubber added after the dry ESP would 

cost $28,000/ton of PM removed and is 

not cost effective. Additionally this cost 

effectiveness calculation did not include 

impacts of increased waste water to the 

treatment system which if included 

would only increase the cost. Adding an 

additional field to the existing dry ESP 

is not cost effective at $122,000/ton. 

Washington determined that PM BART 

is the existing BACT dry ESP with an 

emission limit of 0.027 gr/dscf at 8% O2,

and 0.020 gr/dscf at 8% O2 annual 

average. 

NOX: The analysis of NOX controls for 

this unit found that SCR and SNCR do 

not appear to be technically feasible due 

to the nature and purpose of the 

recovery boiler. As particulate matter 

captured from the exhaust gas stream is 

used in creating green liquor, the 

addition of ammonia upsets the delicate 

chemical make-up of the recovered 

salts. The catalyst used in SCR would be 

‘‘poisoned’’ by the alkaline salts in the 

exhaust gas stream. Washington 

determined that NOX BART for this 

furnace is the current staged combustion 

system with an emission limit of 140 

ppm at 8% O2.

SO2: Wet and dry sorbent injection 

systems were considered as control 

options for SO2. However, since the 

recovery furnace is intended to recover 

sodium and sulfur for reuse in the 

pulping process, the recovery furnace is 

designed to capture these chemical 

compounds and thus emits little SO2

emissions. Weyerhaeuser and 

Washington’s analysis found that 


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neither a wet lime scrubber, a limestone 

scrubber nor semi-dry or dry sorbent 

injection system are likely to reduce 

much SO2 from this unit. Washington 

determined that BART is the current 

operation of the furnace using a tertiary 

air system, use of good operating 

practices and meeting the emission 

limitation in PSD permit 92–03 

Amendment 4, of 75 ppm at 8% O2. 

No. 10 Smelt Dissolver Tank 

The smelt tank only emits PM and is 

currently regulated by the most 

stringent BACT emission limit in the 

EPA RBLC, which is more stringent than 

the MACT standard. Because this unit is 

not a source of NOX emission and only 

a negligible source of SO2 emissions no 

additional controls are necessary for 

these pollutants. Washington 

determined that PM BART for this unit 

is current level of control provided by 

the existing wet scrubber and an 

emission limit of 0.12 lb/ton black 

liquor. 

No. 11 Power Boiler 

This power boiler currently uses 

overfire air to provide efficient 

combustion, a multiclone followed by 

an ESP for control of PM, and trona 

injection after the multiclone and before 

the ESP to control SO2. 

PM: Alternative control options were 

considered for PM control on the power 

boiler. Fabric filters are not feasible due 

to the fire hazard from burning wood 

chips. Wet ESPs are no more efficient 

than the existing dry ESP. Washington 

also found that space constraints on the 

No. 11 power boiler would prevent or 

require expensive infrastructure 

modifications to provide the space 

necessary for modifications to either the 

PM or SO2 controls currently in place. 

Washington determined that BART for 

PM at the No. 11 power boiler is the 

existing multiclone followed by dry ESP 

with an emission limit of 0.10 lb/ 

MMBtu. 

NOX: SCR and SNCR were evaluated 

for NOX control. SCR with a control 

efficiency of 75% is not cost effective at 

$13,000/ton. SNCR with a control 

efficiency of 25% is not cost effective at 

$6686/ton. As described in the SIP 

submittal, Washington agreed with 

Weyerhaeuser’s analysis finding that 

there is no other NOX reduction 

technology that is technically and 

economically feasible for this unit. 

Washington determined that BART is 

the existing combustion system with an 

emission limit of (0.30x + 0.70y)/(x + y) 

lb per MMBtu (derived from solid fossil 

fuel, liquid fossil fuel and wood 

residue) where 40 CFR 60.44(b) defines 

the variables. 

SO2: The current dry sorbent (trona) 

injection system has a control efficiency 

of 25%. Additional control options 

including low sulfur fuel oil or coal and 

wet calcium scrubbing were evaluated. 

Due to the limited use of either oil or 

coal, emission reductions from changing 

to low sulfur coal would provide 

negligible SO2 reductions and limited 

improvement in visibility. Hydrated 

lime injection is technically infeasible 

due to lime build-up on the ID fan 

blades causing potential fan failure and 

unsafe explosion conditions. LSFO and 

lime spray dryer control technologies 

are not cost effective at over $17,000/ 

ton. Washington determined SO2 BART 

for the No. 11 power boiler is the 

continued use of low sulfur fuels and 

dry trona sorbent injection with an 

emission limit of 1000 ppm at 7% O2, 

1-hour average, (0.8y +1.2z)/(y +z) lb per 

MMBtu. (derived from burning a 

mixture of liquid and solid fossil fuel) 

where 40 CFR 60.43(b) defines the 

variables). 

Summary and Conclusion for 

Weyerhaeuser BART: 

In conclusion for the Weyerhaeuser 

Company, Longview, for all of the 

reasons summarized above, Washington 

determined that the existing controls, 

techniques and emission limits 

constitute BART for NOX, SO2, and PM 

at the facility. On July 7, 2010, 

Washington issued Weyerhaeuser 

Company Order No. 7840 containing the 

BART requirements. After review of the 

SIP submittal, EPA proposes to find that 

the BART determination and BART 

compliance order for Weyerhaeuser is 

reasonable and proposes to approve it. 

Summary of Weyerhaeuser Proposed 

BART Technology 

The table below summarizes the 

proposed BART technology for 

Weyerhaeuser. 

Emission unit BART technology 

No. 11 Power Boiler ........................................... PM: Existing ESP 0.050 grain/dscf at 7% O2 (current limit). 

NOX: Existing Combustion System (0.30x + 0.70y)/(x + y) lb per MMBtu (derived from solid 

fossil fuel, liquid fossil fuel and wood residue) (40 CFR 60.44(b) which also defines the variables) 

SO2: Fuel mix and trona injection system 1000 ppm at 7% O2, 1-hour average, (0.8y + 1.2z)/(y 

+ z) lb per MMBtu (derived from burning a mixture of liquid and solid fossil fuel) (40 CFR 

60.43(b) which also defines the variables). 

No. 10 Recovery Furnace .................................. PM: Existing ESP 0.027 gr/dscf, per test, and 0.020 grain/dscf, annual average (current BACT 

limits in PSD 92–03, Amendment 4). 

NOX: Existing Staged Combustion System 140 ppm at 8% O2 (current BACT limit in PSD 92– 

03, Amendment 4). 

SO2: Good Operating Practices 75 PPM at 8% O2 (current BACT limit in PSD 92–03, Amendment 4). 

Smelt Dissolver Tank .......................................... PM: Existing High Efficiency Wet Scrubber 0.120 lb/BLS (current BACT limit in PSD 92–03, 

Amendment 4). 

NOX: No limit required. 

SO2: No limit required. 

F. Determination of Reasonable Progress 

Goals 

The RHR requires states to show 

‘‘reasonable progress’’ toward natural 

visibility conditions over the time 

period of the SIP, with 2018 as the first 

milestone year. The RHR also requires 

that the state establish an RPG, 

expressed in deciviews (dv), for each 

Class I area within the state that 

provides for reasonable progress 

towards achieving natural visibility 

conditions by 2064. As such, the state 

must establish a Reasonable Progress 

Goals (RPGs) for each Class I area that 

provides for visibility improvement for 

the most-impaired (20% worst) days 

and ensures no degradation in visibility 

for the least-impaired (20% best) days in 

2018. 

RPGs are estimates of the progress to 

be achieved by 2018 through 

implementation of the LTS which 

includes anticipated emission 


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reductions from all state and federal 

regulatory requirements implemented 

between the baseline and 2018, 

including but not limited to BART and 

any additional controls for non-BART 

sources or emission activities including 

any federal requirements that reduce 

visibility impairing pollutants. As 

explained above, the rate needed to 

achieve natural conditions by 2064 is 

referred to as the uniform rate of 

progress or URP. 

If the state establishes a reasonable 

progress goal that provides for a slower 

rate of improvement than the rate that 

would be needed to attain natural 

conditions by 2064, the state must 

demonstrate, based on the factors in 40 

CFR 51.308(d)(l)(i)(A), that the rate of 

progress for the implementation plan to 

attain natural conditions by 2064 is not 

reasonable; and the progress goal 

adopted by the state is reasonable. The 

state must provide to the public for 

review as part of its implementation 

plan an assessment of the number of 

years it would take to attain natural 

conditions if visibility continues at the 

rate of progress selected by the state. 40 

CFR 51.308(d)(B)(ii). 

Washington identified the visibility 

improvement by 2018 in each of the 

mandatory Class I areas as a result of 

implementation of the SIP submittal 

BART emission limits, using the results 

of the Community Multi-Scale Air 

Quality (CMAQ) modeling conducted by 

WRAP. CMAQ modeling identified the 

extent of visibility improvement for 

each Class I area by pollutant specie. 

The WRAP CMAQ modeling predicted 

visibility impairment by Class I area 

based on 2018 projected source 

emission inventories, which included 

federal and state regulations already in 

place (‘‘on the books’’) and BART 

limitations. A more detailed description 

of the CMAQ modeling performed by 

the WRAP can be found in the WRAP 

TSD. The modeling projected that 

statewide emissions of SO2 will decline 

by almost 40% between the baseline 

period and 2018 attributable to a 29% 

reduction in point source emissions and 

a 95% reduction in on and off-road 

mobile sources. See e.g. SIP submittal at 

9–3. Additionally, the WRAP’s 

Particulate Matter Source 

Apportionment Technology (PSAT) 

analysis for 2018 indicates that sources 

beyond the control of the state that are 

outside the modeling domain, Canada or 

Pacific offshore that will contribute 

about two-thirds or more of the sulfate 

concentrations in many of the Class I 

areas. The modeling projected that 

nitrate concentrations will decrease by 

46% between the baseline and 2018 

primarily due to reductions in NOX

emissions from on-road and off-road 

mobile sources. Again, the PSAT 

analysis indicates the majority of the 

remaining nitrate in 2018 will come 

from sources in Canada, Pacific offshore 

or outside the modeling domain. See 

e.g. SIP submittal 9–4. 

Chapter 9 of the SIP submittal 

discusses the establishment of the RPGs 

for 2018 for each Class I area in 

Washington. Table 9–4 of the SIP 

submittal presents the RPG’s for each 

Class I area in Washington. These goals 

provide for modest improvement in 

visibility on the 20% most impaired 

days, but not to the level of 2018 URP 

in any of the Class I areas. The goals also 

provide for no degradation on the 20% 

least impaired days. 

Washington relied on the regional 

modeling conducted by the WRAP in 

establishing the RPGs. The WRAP ran 

several emission scenarios representing 

base case and 2018 emissions. 

Washington elected to use the model 

run with emissions in the ‘‘Preliminary 

Reasonable Progress’’ emission 

estimates for 2018 (PRP18a). The WRAP 

modeling for the 2018 RPGs does not 

account for a number of changes in 

projected emissions that occurred 

subsequent to completion of the model 

runs including reductions that are 

expected to occur as a result of the 

proposed FIP. These include: 

• Emission reductions resulting from 

final SIP and FIP BART determinations 

• Emission reductions from 

International Maritime Organization 

Emission Control Area for the west coast 

of the U.S. and Canada 

• Reductions in SO2 emissions from 

SO2 control measures on three oil 

refineries: TSEORO, Shell (Puget Sound 

Refining) and Conoco-Phillips 

• Proposed Better than BART 

alternative federal emission limitations 

on Intalco 

• Proposed Better than BART 

alternative federal program for Tesoro 

• Additional NOX emission 

reductions of 8022 t/y from the 

TransAlta BART determination 

Therefore, the RPGs established by 

Washington are conservative and do not 

account for the above additional 

emission reductions that have already 

been, or are expected to be achieved by 

2018. 

As part of its reasonable progress 

analysis, Washington conducted a 

generalized four-factor analysis on those 

source categories that have the greatest 

visibility impact and determined that it 

should focus on the SO2 and NOX

emissions and the source categories that 

emit more than 1000 t/y. Specific 

analysis was completed on the 

following three source categories: (1) 

Industrial processes, (2) external 

combustion boilers, and (3) stationary 

internal combustion engines. 

Industrial processes account for 

22,112 t/y of SO2 emissions, primarily 

from aluminum smelting, petroleum 

processing (process heaters, catalytic 

cracking units, and flares), sulfate 

(Kraft) pulping, and wet process cement 

manufacturing. Of these industrial 

processes, external combustion boilers 

account for 13,783 t/y of SO2 emissions 

primarily from burning process gas, 

wood waste, residual oil, and 

bituminous and sub-bituminous coal for 

electricity generation. Stationary 

internal combustion engines fueled by 

natural gas account for 911 t/y of SO2

emissions. 

Other industrial processes account for 

19,070 t/y NOX emissions primarily 

from wet and dry process cement 

manufacturing, glass manufacturing, 

sulfate (Kraft) pulping, sulfite pulping, 

and petroleum process heaters. External 

combustion boilers account for 26,895 

t/y NOX emissions primarily from 

burning bituminous and sub-bituminous 

coal for electricity generation, wood 

waste, process gas, and natural gas. 

Internal combustion engines account for 

2,544 t/y NOX emissions fueled by 

natural gas. 

There are five crude oil refineries 

located in Washington. Process heaters 

are fueled with waste refinery gas, using 

natural gas as back-up. Two of the five 

refineries are subject to BART (BP 

Cherry Point and Tesoro) and BART 

determinations were made for them. See 

the previous BART discussion. The 

three other meet the NSPS limit for 

sulfur in refinery fuel gas. 

Washington also considered the 

significant visibility impact caused by 

natural fire in three of the Class I Areas: 

North Cascades National Park, Glacier 

Peak Wilderness Area, and Pasayten 

Wilderness Area. The WRAP’s analysis 

found that emissions attributable to 

natural fire are not expected to 

significantly change between the 

baseline and 2018. Washington found 

that if these projections are correct, the 

impact of natural fire is so great in these 

three areas that they will not be able to 

achieve the estimated natural 

conditions. 

Washington’s reasonable progress 

analysis found that emissions, 

particularly SO2 and NOX, from Canada 

result in significant impact on visibility 

in the Class I areas. Additionally, Pacific 

offshore emissions are significant in all 

areas except the Pasayten Wilderness 

Area. Of the sulfate impairment in 

Olympic National Park on the most 

impaired days, 73% originates from a 


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combination of sources located outside 

the modeling domain, Canada, and 

Pacific offshore. Of the nitrate 

impairment in Olympic National Park 

on the most impaired days, 43% 

originates from sources in these areas. 

Similar impairment profiles exist in the 

other Class I areas in Washington. In 

Washington’s view, Washington’s 

mandatory Class I areas will not be able 

to attain natural conditions without 

further controls on Canadian and Pacific 

offshore emissions and the lack of 

controls inhibits these Class I areas’ 

ability to achieve the URP and lengthens 

the time it will take to achieve natural 

conditions. 

In establishing the 2018 RPGs, 

Washington did not account (or take 

credit) for almost 10,000 tons of SO2

reductions that occurred in the 2003 to 

2005 timeframe from implementation of 

various control technologies from the 

Tesoro, ConocoPhillips, and Shell 

refineries. Tesoro installed wet FGD on 

the CO Boiler (Fluidized Catalyst 

Cracker) in 2005 for a reduction of 4740 

t/y SO2 and is considered BART in 

Washington’s BART determination. 

Conoco-Phillips installed wet-FGD on 

its CO boiler for a reduction of 2041 

t/y SO2 which was not included in the 

WRAP modeling for RPGs. Shell Puget 

Sound Refining installed wet-FGD on 

their CO boiler for a reduction of 3045 

t/y SO2 which was not included in the 

WRAP modeling. Washington relied on 

the WRAP modeling in establishing the 

RPG’s, thus the goals of the SIP 

submittal underestimate actual 

improvement that is anticipated. 

EPA proposes to find that the 

Washington Regional Haze SIP 

submittal meets the requirements of 40 

CFR 51.308(d)(1). As discussed above, 

the RPGs established by Washington are 

conservative and do not account for a 

significant amount of additional 

emission reductions that have already 

been, or are anticipated to be achieved 

by 2018. These include the emission 

reductions expected from the BART 

determinations and Better than BART 

determinations proposed today and the 

almost 10,000 t/y SO2 emission 

reductions from three refineries in 

northwest Washington. 

As explained in EPA’s RPG Guidance, 

the 2018 URP estimate is not a 

presumptive target and the 

Washington’s RPGs may be lesser, 

greater or equivalent to the glide path. 

The glide path to 2064 represents a 

linear rate of progress to be used for 

analytical comparison to the amount of 

progress expected to be achieved. EPA 

believes that the RPGs established by 

Washington for the Class I areas in 

Washington, although not achieving the 

URP, are reasonable when considering 

the additional emission reductions 

expected to result from the BART 

controls, additional reductions on 

refineries not included in the reasonable 

progress demonstration and the 

significant contributions to visibility 

impairment from natural fire and from 

sources beyond Washington’s regulatory 

jurisdiction. Additional controls on 

point sources or other source categories 

at this time is not likely to result in 

substantial visibility improvement in 

the first planning period due to the 

significant contribution from emissions 

from natural fire, the Pacific offshore, 

Canada, and outside the modeling 

domain. 

EPA believes that actual visibility 

improvement in all Class I areas by 2018 

will be significantly better than the 

RPGs established in the SIP submittal 

would suggest. The RPG’s established in 

the SIP for the Class I areas in 

Washington meet the federal 

requirements by showing visibility 

improvement on the 20% worst days 

and no degradation on the 20% best 

days. EPA is proposing to find that 

Washington has demonstrated that its 

2018 RPGs are reasonable for the first 

planning period and meet the 

requirements of 40 CFR 51.308(d)(1). 

G. Long Term Strategy 

The Long Term Strategy required by 

40 CFR 51.308(d)(3) is a compilation of 

all existing and anticipated new air 

pollution control measures (both those 

identified in this SIP submittal as well 

as measures resulting from other air 

pollution requirements.) The LTS must 

include ‘‘enforceable emission 

limitations, compliance schedules, and 

other measures as necessary to achieve 

the reasonable progress goals’’ for all 

Class I areas within or affected by 

emissions from the state. 40 CFR 

51.308(d)(3). In developing a LTS, 

Washington identified existing 

programs and rules, and additional new 

controls that may be needed for other 

CAA requirements. 

The Regional Haze Rule requires that 

states consider seven topics: (1) Ongoing 

air pollution control programs including 

measures to address RAVI, (2) measures 

to mitigate impacts of construction 

activities, (3) emission limitations and 

schedules for compliance, (4) source 

retirement and replacement schedules, 

(5) smoke management techniques for 

agricultural and forestry burning, (6) 

enforceability of emission limitations 

and control measures, and (7) the 

anticipated net effects on visibility due 

to projected changes in point, area and 

mobile source emissions over the first 

planning period which ends in 2018. 40 

CFR 50.308(d)(3). In their reasonable 

progress analysis, Washington 

addressed each of these topics and 

added two additional factors; 

commercial marine shipping and 

residential wood combustion. 

1. Emission reductions due to ongoing 

air pollution control programs. 

Washington discussed a number of 

current federal, state, and local permit 

programs and regulations that limit 

visibility impairing emissions from 

point, area, on-road and non-road 

mobile sources. The programs and 

requirements include for example the 

New Source Review and Washington’s 

Reasonable Available Control 

technology (RACT) permitting 

requirements, the BART requirements 

and Washington’s Smoke Management 

Plan. 

2. Measures to mitigate impacts of 

construction activities. Washington 

explained that due to the location of the 

Class I areas relative to the urban areas 

in Washington, construction activities 

have not been identified as contributing 

to visibility impairment in the Class I 

areas. Washington also explained 

however, that construction activities are 

regulated under Washington or under 

local air quality authority rules and 

policies governing mitigation of air 

pollution from construction activities. 

3. Emission limitations and schedules 

for compliance. The submission states 

that in addition to current state and 

federal rules, the BART requirements 

are important to achieving the estimated 

emission reductions necessary to meet 

the 2018 RPG. To this end, Washington 

issued enforceable BART Orders 

containing compliance schedules to 

each source subject to BART. The BART 

Orders are included as part of the SIP 

submittal. 

4. Source retirement and replacement 

schedules. Washington is not aware of 

any scheduled and documented 

retirement or replacement of point 

sources emitting visibility impairing 

pollutants so source retirement and 

replacement schedules are not included 

as part of Washington’s long term 

strategy. However, if Washington 

receives notice of source retirement or 

replacement in the future it commits to 

including the emission reductions into 

the long term strategy in its periodic 

updates. 

5. Smoke management techniques for 

agricultural and forestry burning. In 

Washington agricultural burning is 

regulated by Washington and local 

agencies which establish controls for 

agricultural burning to minimize 

adverse health effects and 

environmental effects, including 

visibility. Washington’s silvicultural 


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Smoke Management Plan was 

incorporated into the Washington RAVI 

SIP on June 11, 2003. See 68 FR 3482. 

6. Enforceability of emission 

limitations and control measures. 

Emission limits on stationary sources 

are enforceable as a matter of state law 

under chapter 173–400 Washington 

Administrative Code, General 

Regulations for Air pollution Sources. 

Additionally, as mentioned above, 

Washington issued enforceable BART 

Orders to each BART source which will 

later be incorporated into the source’s 

Title 5 permit. 

7. Anticipated net effects on visibility 

due to projected changes in point, area 

and mobile source emissions over the 

first planning period. Washington relied 

on modeling results from the WRAP 

projecting the anticipated visibility 

improvement in 2018 for the LTS. See 

SIP submittal, Table 10–3. As explained 

above, in the discussion regarding the 

reasonable progress demonstration, due 

to the fact that the WRAP modeling was 

conducted prior to many emission 

reduction activities that have, or will 

occur, the projections in Table 10–3 of 

the SIP submittal are conservative. 

Thus, the actual visibility improvement 

is likely to be better than projected. 

In addition to the seven factors 

discussed above, Washington also 

included two additional elements in 

their long term strategy; residential 

wood combustion program and 

woodstove change-outs and controls on 

emissions from commercial marine 

shipping. EPA acknowledges these 

additional measures, but it is not 

necessary to take these specific 

activities into account at this time in 

evaluating whether the enforceable 

measures contained in Washington’s 

LTS satisfy the RHR requirements. 

Washington consulted with 

surrounding states through participation 

in the WRAP to ensure that Washington 

would achieve its fair share of 

reductions so that Class I areas in other 

states can meet their RPGs. No state 

specifically requested Washington for 

emission reductions beyond those 

assumed by the WRAP when it 

completed its modeling of 2018 

visibility conditions. Additionally, 

Washington commits to updating its 

comprehensive LTS on the schedule set 

by the RHR for the Regional Haze SIP 

updates. 

EPA is proposing to find that 

Washington adequately addressed the 

RHR requirements in developing its LTS 

because it includes all the control 

measures that were anticipated at the 

time of the SIP development. The SIP 

submittal contains sufficient 

documentation to ensure that 

Washington’s LTS will enable it to 

achieve the RPGs established for the 

mandatory Class I areas in Washington 

as well as the RPGs established by other 

states for the Class I areas where 

Washington sources are reasonably 

anticipated to contribute to visibility 

impairment. 

Washington’s analysis included 

consideration of all anthropogenic 

sources of visibility impairment 

including major and minor stationary 

sources, mobile sources and area 

sources. The anticipated net effect on 

visibility over the first planning period 

due to changes in point, area and mobile 

source emissions is an improvement in 

visibility in all Class I areas in 

Washington on the worst 20% days and 

no degradation of visibility on the 20% 

best days. EPA proposes to approve the 

Long Term Strategy (LTS) contained in 

the SIP submittal because it includes all 

the control measures that were 

anticipated at the time of the SIP 

development and the LTS as a whole 

provides sufficient measures to ensure 

that Washington will meet its emission 

reduction obligations. 

H. Monitoring Strategy and Other 

Implementation Requirements 

The primary monitoring network for 

regional haze in Washington is the 

IMPROVE network. As discussed 

previously, there are currently 

IMPROVE sites that represent 

conditions for all mandatory Class I 

areas in Washington. 

IMPROVE monitoring data from 

2000–2004 serves as the baseline for the 

regional haze program, and is relied 

upon in the Washington SIP submittal. 

In the SIP submittal, Washington 

commits to rely on the IMPROVE 

network for complying with the regional 

haze monitoring requirement in EPA’s 

RHR for the current and future regional 

haze implementation periods. See 

chapter 12 of the SIP submittal. 

Washington will also rely on the 

continued existence of the WRAP and 

on the WRAP’s work to provide 

adequate technical support to meet its 

commitment to conduct the analyses 

required under the 40 CFR 51.308(d)(4) 

and will collaborate with the WRAP 

members to ensure the continued 

operation of the technical support tools. 

Data produced by the IMPROVE 

monitoring network will be used for 

preparing the 5-year progress reports 

and the 10-year SIP revisions, each of 

which relies on analysis of the 

preceding 5 years of data. Washington 

also commits to updating its statewide 

emissions inventory periodically. 

I. Consultation With States and Federal 

Land Managers 

Through the WRAP, member states 

and Tribes worked extensively with the 

FLMs from the U.S. Departments of the 

Interior and Agriculture to develop 

technical analyses that support the 

regional haze SIPs for the WRAP states. 

Washington provided the proposed 

Regional Haze plan for Washington to 

the FLMs for comment in March 2010. 

See appendix B of the SIP submittal. 

Washington also consulted with the 

states of Idaho and Oregon, and all 

WRAP member states and Tribes. 

J. Periodic SIP Revisions and 5-Year 

Progress Reports 

Section 51.308(f) of the RHR requires 

that the regional haze plans be revised 

and submitted to EPA by July 31, 2018 

and every 10 years thereafter. 40 CFR 

51.308(g) requires the state to submit a 

progress report to EPA every 5 years 

evaluating the progress made towards 

the reasonable progress goals for each 

Class I area in the state and each Class 

I area located outside the state which 

may be affected by emissions from 

within the state. Washington commits to 

evaluate and assess each of the elements 

required under 40 CFR 51.308(f) and to 

submit a comprehensive Regional Haze 

SIP revision to EPA by July 31, 2018, 

and every 10 years thereafter. 

Washington also commits to submitting 

a report on its reasonable progress to 

EPA every 5 years to evaluate the 

progress made towards the RPGs and to 

address each of the elements specified 

in 40 CFR 51.308(g). See chapter 12 of 

the SIP submission. 

V. What action is EPA proposing? 

EPA is proposing a partial approval 

for most elements of the Washington 

Regional Haze SIP submittal. EPA is 

proposing a limited approval and 

limited disapproval of the State’s SO2

BART determinations for the Intalco 

potlines, and proposes a Better than 

BART alternative. The limited approval 

of the State’s BART Order for Intalco is 

strengthening the SIP and the Better 

than BART FIP limiting annual SO2

emissions to 5240 t/y is a BART 

alternative. This Better than BART 

alternative, as offered by Alcoa, will 

incur no cost to Alcoa as it currently 

operates within this emission limit. EPA 

is also proposing to disapprove the 

Tesoro NOX BART determinations for 

emission units F–304, F–6650, F–6651, 

F–6652, and F–6653 and proposes a FIP 

for an alternative Better than BART. 

This Better than BART alternative, as 

offered by Tesoro, will incur no cost to 


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11 ’’Indian country’’ is defined under 18 U.S.C. 

1151 as: (1) All land within the limits of any Indian 

reservation under the jurisdiction of the United 

States Government, notwithstanding the issuance of 

any patent, and including rights-of-way running 

through the reservation, (2) all dependent Indian 

communities within the borders of the United 

States, whether within the original or subsequently 

acquired territory thereof, and whether within or 

without the limits of a State, and (3) all Indian 

allotments, the Indian titles to which have not been 

extinguished, including rights-of-way running 

through the same. Under this definition, EPA treats 

as reservations trust lands validly set aside for the 

use of a Tribe even if the trust lands have not been 

formally designated as a reservation. 

Tesoro as they currently operate within 

these emission limits. 

VI. Washington Notice 

Washington’s Regulatory Reform Act 

of 1995, codified at chapter 43.05 

Revised Code of Washington (RCW), 

precludes ’’regulatory agencies’’, as 

defined in RCW 43.05.010, from 

assessing civil penalties under certain 

circumstances. EPA has determined that 

chapter 43.05 of the RCW, often referred 

to as ‘‘House Bill 1010,’’ conflicts with 

the requirements of CAA section 

110(a)(2)(A) and (C) and 40 CFR 

51.230(b) and (e). Based on this 

determination, Ecology has determined 

that chapter 43.05 RCW does not apply 

to the requirements of chapter 173–422 

WAC. See 66 FR 35115, 35120 (July 3, 

2001). The restriction on the issuance of 

civil penalties in chapter 43.05 RCW 

does not apply to local air pollution 

control authorities in Washington 

because local air pollution control 

authorities are not ‘‘regulatory agencies’’ 

within the meaning of that statute. See 

66 FR 35115, 35120 (July 3, 2001). 

In addition, EPA is relying on the 

State’s interpretation of another 

technical assistance law, RCW 

43.21A.085 and .087, to conclude that 

the law does not impinge on the State’s 

authority to administer Federal Clean 

Air Act programs. The Washington 

Attorney Generals’ Office has concluded 

that RCW 43.21A.085 and .087 do not 

conflict with Federal authorization 

requirements because these provisions 

implement a discretionary program. 

EPA understands from the State’s 

interpretation that technical assistance 

visits conducted by the State will not be 

conducted under the authority of RCW 

43.21A.085 and .087. See 66 FR 16, 20 

(January 2, 2001); 59 FR 42552, 42555 

(August 18, 1994). 

VII. Scope of Action 

This proposed SIP approval does not 

extend to sources or activities located in 

’’Indian Country’’ as defined in 18 

U.S.C. 1151.11 Consistent with previous 

Federal program approvals or 

delegations, EPA will continue to 

implement the Act in Indian Country 

because Washington did not adequately 

demonstrate authority over sources and 

activities located within the exterior 

boundaries of Indian reservations and 

other areas of Indian Country. The one 

exception is within the exterior 

boundaries of the Puyallup Indian 

Reservation, also known as the 1873 

Survey Area. Under the Puyallup Tribe 

of Indians Settlement Act of 1989, 25 

U.S.C. 1773, Congress explicitly 

provided state and local agencies in 

Washington authority over activities on 

non-trust lands within the 1873 Survey 

Area. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). The proposed FIP 

applies to only two facilities and is not 

a rule of general applicability. 

B. Paperwork Reduction Act 

This proposed action does not impose 

an information collection burden under 

the provisions of the Paperwork 

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

Under the Paperwork Reduction Act, a 

‘‘collection of information’’ is defined as 

a requirement for ‘‘answers to * * * 

identical reporting or recordkeeping 

requirements imposed on ten or more 

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

Because the proposed FIP applies to just 

two facilities, the Paperwork Reduction 

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

Burden means the total time, effort, or 

financial resources expended by persons 

to generate, maintain, retain, or disclose 

or provide information to or for a 

Federal agency. This includes the time 

needed to review instructions; develop, 

acquire, install, and utilize technology 

and systems for the purposes of 

collecting, validating, and verifying 

information, processing and 

maintaining information, and disclosing 

and providing information; adjust the 

existing ways to comply with any 

previously applicable instructions and 

requirements; train personnel to be able 

to respond to a collection of 

information; search data sources; 

complete and review the collection of 

information; and transmit or otherwise 

disclose the information. An agency 

may not conduct or sponsor, and a 

person is not required to respond to a 

collection of information unless it 

displays a currently valid Office of 

Management and Budget (OMB) control 

number. The OMB control numbers for 

our regulations in 40 CFR are listed in 

40 CFR part 9. 

C. Regulatory Flexibility Act 

The Regulatory Flexibility Act (RFA) 

generally requires an agency to prepare 

a regulatory flexibility analysis of any 

rule subject to notice and comment 

rulemaking requirements under the 

Administrative Procedure Act or any 

other statute unless the agency certifies 

that the rule will not have a significant 

economic impact on a substantial 

number of small entities. Small entities 

include small businesses, small 

organizations, and small governmental 

jurisdictions. For purposes of assessing 

the impacts of today’s proposed rule on 

small entities, small entity is defined as: 

(1) A small business as defined by the 

Small Business Administration’s (SBA) 

regulations at 13 CFR 121.201; (2) a 

small governmental jurisdiction that is a 

government of a city, county, town, 

school district or special district with a 

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

a small organization that is any not-for 

profit enterprise which is independently 

owned and operated and is not 

dominant in its field. After considering 

the economic impacts of this proposed 

action on small entities, I certify that 

this proposed action will not have a 

significant economic impact on a 

substantial number of small entities. 

The FIP for the two Washington 

facilities being proposed today does not 

impose any new requirements on small 

entities. The proposed partial approval 

of the SIP, if finalized, merely approves 

state law as meeting Federal 

requirements and imposes no additional 

requirements beyond those imposed by 

state law. See Mid-Tex Electric 

Cooperative, Inc. v. FERC, 773 F.2d 327 

(DC Cir. 1985). 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), Public 

Law 104–4, establishes requirements for 

Federal agencies to assess the effects of 

their regulatory actions on state, local, 

and Tribal governments and the private 

sector. Under section 202 of UMRA, 

EPA generally must prepare a written 

statement, including a cost-benefit 

analysis, for proposed and final rules 

with ‘‘Federal mandates’’ that may 

result in expenditures to state, local, 

and Tribal governments, in the 

aggregate, or to the private sector, of 

$100 million or more (adjusted for 


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inflation) in any 1 year. Before 

promulgating an EPA rule for which a 

written statement is needed, section 205 

of UMRA generally requires EPA to 

identify and consider a reasonable 

number of regulatory alternatives and 

adopt the least costly, most costeffective, or least burdensome 

alternative that achieves the objectives 

of the rule. The provisions of section 

205 of UMRA do not apply when they 

are inconsistent with applicable law. 

Moreover, section 205 of UMRA allows 

EPA to adopt an alternative other than 

the least costly, most cost-effective, or 

least burdensome alternative if the 

Administrator publishes with the final 

rule an explanation why that alternative 

was not adopted. Before EPA establishes 

any regulatory requirements that may 

significantly or uniquely affect small 

governments, including Tribal 

governments, it must have developed 

under section 203 of UMRA a small 

government agency plan. The plan must 

provide for notifying potentially 

affected small governments, enabling 

officials of affected small governments 

to have meaningful and timely input in 

the development of EPA regulatory 

proposals with significant Federal 

intergovernmental mandates, and 

informing, educating, and advising 

small governments on compliance with 

the regulatory requirements. 

Under Title II of UMRA, EPA has 

determined that this proposed rule does 

not contain a Federal mandate that may 

result in expenditures that exceed the 

inflation-adjusted UMRA threshold of 

$100 million by state, local, or Tribal 

governments or the private sector in any 

1 year. In addition, this proposed rule 

does not contain a significant Federal 

intergovernmental mandate as described 

by section 203 of UMRA nor does it 

contain any regulatory requirements 

that might significantly or uniquely 

affect small governments. 

E. Executive Order 13132: Federalism 

Federalism (64 FR 43255, August 10, 

1999) revokes and replaces Executive 

Orders 12612 (Federalism) and 12875 

(Enhancing the Intergovernmental 

Partnership). Executive Order 13132 

requires EPA to develop an accountable 

process to ensure ‘‘meaningful and 

timely input by state and local officials 

in the development of regulatory 

policies that have federalism 

implications.’’ ‘‘Policies that have 

federalism implications’’ is defined in 

the Executive Order to include 

regulations that have ‘‘substantial 

direct-effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government.’’ Under Executive 

Order 13132, EPA may not issue a 

regulation that has federalism 

implications, that imposes substantial 

direct compliance costs, and that is not 

required by statute, unless the Federal 

government provides the funds 

necessary to pay the direct compliance 

costs incurred by state and local 

governments, or EPA consults with state 

and local officials early in the process 

of developing the proposed regulation. 

EPA also may not issue a regulation that 

has federalism implications and that 

preempts state law unless the Agency 

consults with state and local officials 

early in the process of developing the 

proposed regulation. This rule will not 

have substantial direct effects on the 

states, on the relationship between the 

national government and the states, or 

on the distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132, because it 

merely addresses the state not fully 

meeting its regional haze SIP obligations 

established in the CAA. Thus, Executive 

Order 13132 does not apply to this 

action. In the spirit of Executive Order 

13132, and consistent with EPA policy 

to promote communications between 

EPA and State and local governments, 

EPA specifically solicits comment on 

this proposed rule from State and local 

officials. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

Executive Order 13175, Entitled 

Consultation and Coordination with 

Indian Tribal Governments (65 FR 

67249, November 9, 2000), requires EPA 

to develop an accountable process to 

ensure ‘‘meaningful and timely input by 

tribal officials in the development of 

regulatory policies that have tribal 

implications.’’ This proposed rule does 

not have tribal implications, as specified 

in Executive Order 13175 because the 

SIP and FIP do not have substantial 

direct effects on tribal governments. 

Thus, Executive Order 13175 does not 

apply to this rule. EPA specifically 

solicits additional comment on this 

proposed rule from tribal officials. 

Consistent with EPA policy, EPA 

nonetheless provided a consultation 

opportunity to Tribes in Idaho, Oregon 

and Washington in letters dated January 

14, 2011. EPA received one request for 

consultation, and we have followed-up 

with that Tribe. On September 20, 2012, 

EPA provided an additional 

consultation opportunity to 7 Tribes in 

Washington specific to the Washington 

regional haze plan. We received no 

requests for consultation. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks (62 FR 19885, 

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

(1) Is determined to be economically 

significant as defined under Executive 

Order 12866; and (2) concerns an 

environmental health or safety risk that 

we have reason to believe may have a 

disproportionate effect on children. EPA 

interprets EO 13045 as applying only to 

those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it implements 

specific standards established by 

Congress in statutes. However, to the 

extent this proposed rule will limit 

emissions of NOX, SO2, and PM10 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. 

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. 

The EPA believes that VCS are 

inapplicable to the proposed partial 

approval of the SIP that if finalized, 

merely approves state law as meeting 

Federal requirements and imposes no 

additional requirements beyond those 

imposed by state law. The FIP portion 


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of this proposed rulemaking involves 

technical standards. EPA proposes to 

use American Society for Testing and 

Materials (ASTM) Methods and 

generally accepted test methods 

previously promulgated by EPA. 

Because all of these methods are 

generally accepted and are widely used 

by State and local agencies for 

determining compliance with similar 

rules, EPA believes it would be 

impracticable and potentially confusing 

to put in place methods that vary from 

what is already accepted. As a result, 

EPA believes it is unnecessary and 

inappropriate to consider alternative 

technical standards. EPA welcomes 

comments on this aspect of the 

proposed rulemaking and, specifically, 

invites the public to identify 

potentially-applicable voluntary 

consensus standards and to explain why 

such standards should be used in this 

regulation. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

February 16, 1994), establishes federal 

executive policy on environmental 

justice. Its main provision directs 

federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. We 

have determined that this proposed 

rule, if finalized, will not have 

disproportionately high and adverse 

human health or environmental effects 

on minority or low-income populations 

because it increases the level of 

environmental protection for all affected 

populations without having any 

disproportionately high and adverse 

human health or environmental effects 

on any population, including any 

minority or low income populations. 

This proposed FIP limits emissions of 

SO2 from two facilities in Washington. 

The partial approval of the SIP, if 

finalized, merely approves state law as 

meeting Federal requirements and 

imposes no additional requirements 

beyond those imposed by state law. 

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, Visibility, 

and Volatile organic compounds. 

Dated: November 30, 2012. 

Dennis J. McLerran, 

Regional Administrator, Region 10. 

40 CFR part 52 is proposed to be 

amended as follows: 

PART 52—[AMENDED] 

1. The authority citation for part 52 

continues to read as follows: 

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

Subpart WW—Washington 

2. Section 52.2498 is amended by 

adding paragraph (c) to read as follows: 

§ 52.2498 Visibility protection. 

* * * * * 

(c) The requirements of sections 169A 

and 169B of the Clean Air Act are not 

met because the plan does not include 

approvable provisions for protection of 

visibility in mandatory Class I Federal 

areas, specifically the Best Available 

Retrofit Technology (BART) 

requirement for regional haze visibility 

impairment (§ 51.308(e)). The EPA 

BART regulations are found in 

§§ 52.2500 and 52.2501. 

* * * * * 

3. Add §§ 52.2500 and 52.2501 to read 

as follows: 

§ 52.2500 Best available retrofit 

technology requirements for the Intalco 

Aluminum Corporation (Intalco Works) 

primary aluminum plant—Better than BART 

Alternative. 

(a) Applicability. This section applies 

to the Intalco Aluminum Corporation 

(Intalco Works) primary aluminum 

plant located in Ferndale, Washington 

and to its successors and/or assignees. 

(b) Better than BART Alternative— 

Sulfur dioxide (SO2) emission limit for 

potlines. Starting January 1, 2014, SO2

emissions from all pot lines in aggregate 

must not exceed a total of 5,240 tons for 

any calendar year. 

(c) Compliance demonstration. (1) 

Intalco shall determine on a calendar 

month basis, SO2 emissions using the 

following formula: 

SO2 emissions in tons per calendar 

month = (carbon consumption ratio) 

× (% sulfur in baked anodes/100) × 

(% sulfur converted to SO2/100) × 

(2 pounds of SO2 per pound of 

sulfur) × (tons of aluminum 

production per calendar month). 

(i) Carbon consumption ratio is the 

calendar month average of tons of baked 

anodes consumed per ton of aluminum 

produced as determined using the baked 

anode consumption and production 

records required in paragraph (e)(2) of 

this section. 

(ii) % sulfur in baked anodes is the 

calendar month average sulfur content 

as determined in paragraph (d) of this 

section. 

(iii) % sulfur converted to SO2 is 

95%. 

(2) Calendar year SO2 emissions shall 

be calculated by summing the 12 

calendar month SO2 emissions for the 

calendar year. 

(d) Emission monitoring. (1) The % 

sulfur of baked anodes shall be 

determined using ASTM Method D6376 

or an alternative method approved by 

EPA Region 10. 

(2) Intalco shall collect at least four 

anode core samples during each 

calendar week. 

(3) Calendar month average sulfur 

content shall be determined by 

averaging the sulfur content of all 

samples collected during the calendar 

month. 

(e) Recordkeeping. (1) Intalco shall 

record the calendar month SO2

emissions and the calendar year SO2

emissions determined in paragraphs 

(c)(1) and (c)(2) of this section. 

(2) Intalco shall maintain records of 

the baked anode consumption and 

aluminum production data used to 

develop the carbon consumption ratio 

used in paragraph (c)(i) of this section. 

(3) Intalco shall retain a copy of all 

calendar month carbon consumption 

ratio and potline SO2 emission 

calculations. 

(4) Intalco shall record the calendar 

month net production of aluminum and 

tons of aluminum produced each 

calendar month. Net production of 

aluminum is the total mass of molten 

metal produced from tapping all pots in 

all of the potlines that operated at any 

time in the calendar month, measured at 

the casthouse scales and the rod shop 

scales. 

(5) Intalco shall record the calendar 

month average sulfur content of the 

baked anodes. 

(6) Records are to be retained at the 

facility for at least five years and be 

made available to EPA Region 10 upon 

request. 

(f) Reporting. (1) Intalco shall report 

the calendar month SO2 emissions and 

the calendar year SO2 emissions to EPA 

Region 10 at the same time as the 

annual compliance certification 

required by the Part 70 operating permit 

for the Intalco Works is submitted to the 

Title V permitting authority. 

(2) All documents and reports shall be 

sent to EPA Region 10 electronically, in 

a format approved by the EPA Region 

10, to the following email address: R10- 

AirPermitReports@epa.gov. 


sroberts on DSK5SPTVN1PROD with 
Federal Register / Vol. 77, No. 247 / Wednesday, December 26, 2012 / Proposed Rules 76209 

§ 52.2501 Best available retrofit 

technology (BART) requirement for the 

Tesoro Refining and Marketing Company oil 

refinery—Better than BART Alternative. 

(a) Applicability. This section applies 

to the Tesoro Refining and Marketing 

Company oil refinery located in 

Anacortes, Washington and to its 

successors and/or assignees. 

(b) Better than BART alternative. The 

Sulfur dioxide (SO2) emission limitation 

for non-BART eligible process heaters 

and boilers (Units F–101, F–102, F–201, 

F–301, F–652, F–751, and F–752) 

follows. 

(1) Compliance date. Starting no later 

than [60 DAYS AFTER PUBLICATION 

OF THE FINAL RULE], Units F–101, F– 

102, F–201, F–301, F–652, F–751, and 

F–752 shall only fire refinery gas 

meeting the criteria in paragraph (b)(2) 

of this section or pipeline quality 

natural gas. 

(2) Refinery fuel gas requirements. In 

order to limit SO2 emissions, refinery 

fuel gas used in the units from blend 

drum V–213 shall not contain greater 

than 0.10 percent by volume hydrogen 

sulfide (H2S), 365-day rolling average, 

measured according to paragraph (d) of 

this section. 

(c) Compliance demonstration. 

Compliance with the H2S emission 

limitation shall be demonstrated using a 

continuous emissions monitoring 

system as required in paragraph (d) of 

this section. 

(d) Emission monitoring. (1) A 

continuous emissions monitoring 

system (CEMS) for H2S concentration 

shall be installed, calibrated, 

maintained and operated measuring the 

outlet stream of the fuel gas blend drum 

subsequent to all unmonitored incoming 

sources of sulfur compounds to the 

system and prior to any fuel gas 

combustion device. The monitor shall 

be certified in accordance with 40 CFR 

part 60 appendix B and operated in 

accordance with 40 CFR part 60 

appendix F. 

(2) Record the calendar day average 

H2S concentration of the refinery fuel 

gas as measured by the CEMS required 

in paragraph (d)(1) of this section. The 

daily averages shall be used to calculate 

the 365-day rolling average. 

(e) Recordkeeping. Records of the 

daily average H2S concentration and 

365-day rolling averages are to be 

retained at the facility for at least five 

years and be made available to EPA 

Region 10 upon request. 

(f) Reporting. (1) Calendar day and 

365-day rolling average refinery fuel gas 

H2S concentrations shall be reported to 

EPA Region 10 at the same time that the 

semi-annual monitoring reports 

required by the Part 70 operating permit 

for the Tesoro oil refinery are submitted 

to the Title V permitting authority. 

(2) All documents and reports shall be 

sent to EPA Region 10 electronically, in 

a format approved by the EPA Region 

10, to the following email address: R10- 

AirPermitReports@epa.gov. 

[FR Doc. 2012–30090 Filed 12–21–12; 4:15 pm] 

BILLING CODE 6560–50–P 


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