Document ID: EPA-R10-OAR-2010-1071-0001
Agency: epa
Document Type: Proposed Rule
Title: Approvals and Promulgations of Implementation Plans: Regional Haze State Implementation Plan; WA, etc.
Posted Date: 2012-12-26T05:00Z

[Federal Register Volume 77, Number 247 (Wednesday, December 26, 2012)]
[Proposed Rules]
[Pages 76173-76209]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-30090]

[[Page 76173]]

Vol. 77

Wednesday,

No. 247

December 26, 2012

Part II

Environmental Protection Agency

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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

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

[[Page 76174]]

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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.

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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:

[[Page 76175]]

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).
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    \1\ Areas 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.''
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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\
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    \2\ See 64 FR at 35715.
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    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-to-day and by 
season depending on variation in meteorology and emission rates.
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    \3\ Id.
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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

[[Page 76176]]

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.
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    \4\ Albuquerque/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).
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C. Roles of Agencies in Addressing Regional Haze

    Successful implementation of the regional haze program will require 
long-term 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 Shoshone-Bannock 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\
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    \5\ The preamble to the RHR provides additional details about 
the deciview. 64 FR 35714, 35725 (July 1, 1999).
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    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

[[Page 76177]]

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.
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    \6\ The set of ``major stationary sources'' potentially subject 
to BART is listed in CAA section 169A(g)(7).
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    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 visibility-impairing 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 
BART-eligible 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

[[Page 76178]]

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

[[Page 76179]]

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, re-entrained 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

[[Page 76180]]

the Washington SIP submittal. The source categories vary with type of 
pollutant but include: Point, area, on-road 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 on-road 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 on-road 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 off-road 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 
[mu]g/m\3\ of sulfate, for example, is more effective in scattering 
light than 1 [mu]g/m\3\ 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

[[Page 76181]]

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

[[Page 76182]]

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%

[[Page 76183]]

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        Kraft Pulp Mills.
 Pacific Corporation--Camas).
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            Petroleum Refineries.
 (Anacortes).
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 BART-eligible 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 BART-eligible 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 BART-eligible 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-
Oregon-Washington 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 BART-eligible 
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

[[Page 76184]]

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     July 7, 2010.
 for all PM, NOX, and SO2 emission
 limits.
Intalco Aluminum Corp. Compliance with   November 15, 2010.
 all PM, NOX, and SO2 emission limits.
Tesoro Refining and Marketing Company
Compliance for all PM and SO2 emission   July 7, 2010.
 limits.
Compliance with NOX emission limits      September 30, 2015.
 (unit F-103).
Port Townsend Paper Corp.
Compliance with emission limits for PM,  October 20, 2010.
 NOX, and SO2.
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,  July 7, 2010.
 NOX, and SO2.
------------------------------------------------------------------------

    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 BART-eligible 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.

[[Page 76185]]

    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 BART-eligible and 
subject to BART. These units are as follows:
    Heaters and Boilers: \7\
---------------------------------------------------------------------------

    \7\ Power 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.
---------------------------------------------------------------------------

     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:

------------------------------------------------------------------------
                                   Sources to which
                                      they would       Is it technically
           Technology               potentially be         Feasible?
                                      applicable
------------------------------------------------------------------------
Selective Catalytic Reduction     All Heaters.......  Yes.
 (SCR).
Low-NOX Burners (LNB) or Ultra    All Heaters.......  Yes.
 Low NOX Burners (ULNB).
Selective non-catalytic           All Heaters.......  No. Exhaust gas
 Reduction (SNCR).                                     temperatures vary
                                                       too much and
                                                       temperatures not
                                                       in range for SNCR
                                                       operation.
External Flue Gas Recirculation   All Heaters and     No--Potential
 (FGR).                            Boilers.            safety Issues.
Low Excess Air                    All Units.........  No--Potential
Operation--CO...................                       safety issues and
Control.........................                       small operating
                                                       range.
Steam Injection.................  All Units.........  Not feasible
                                                       except 1st Stage
                                                       HC Fractionator
                                                       Reboiler.
Lower Combustion Air              Units with air      No. cooler air is
Preheat.........................   preheat.            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          No. This technique
                                   externally scaled   is only
                                   tubes.              applicable to
                                                       units where the
                                                       heat transfer
                                                       tubes are
                                                       externally
                                                       scaled.
Modify Existing Burners to        All...............  Yes.
 Improve NOX emissions.
------------------------------------------------------------------------

    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 de-rate 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

[[Page 76186]]

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 (wet-FGD) 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

[[Page 76187]]

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

[[Page 76188]]

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

[[Page 76189]]

    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 [deg]F; the minimum 
temperature is 300 to 350 [deg]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 cost-effective, 
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 
[deg]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 [deg]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 [deg]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 [deg]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

[[Page 76190]]

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.
---------------------------------------------------------------------------

    \8\ These 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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \9\ Market Review for Intalco Produced FGD Gypsum. Elliot 
Rosenberg, Senior Economist. EPA Region 10. March 23, 2012.
---------------------------------------------------------------------------

    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

[[Page 76191]]

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.
---------------------------------------------------------------------------

    \10\ Free on Board, defined here where the buyer pays for all 
loading, transportation, and unloading costs.
---------------------------------------------------------------------------

    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:

----------------------------------------------------------------------------------------------------------------
                                         Current impact (98th        Impact with LSFO (98th         Percent
            Class I area             percentile dv,  of  percentile dv,  of    improvement in
                                            days >0.5 dv)              days >0.5 dvdays)         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:

------------------------------------------------------------------------
                                                      Current impact
                                                ------------------------
                  Class I area                             days
                                                   dv        >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

[[Page 76192]]

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

[[Page 76193]]

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 LoTOx\TM\ 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 BART-eligible 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.

[[Page 76194]]

 
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. Unit-specific 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 staged-air 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: Staged-fuel 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

[[Page 76195]]

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 Inter-Reactor 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

[[Page 76196]]

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 non-BART units as an alternative to emission 
limits for NOX on the BART-subject 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.

[[Page 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
----------------------------------------------------------------------------------------------------------------
                                                                    2006\*\ SO2        BART
                                                                     Baseline      alternative:
                                                                     emissions     2007 post-RFG   Reduction in
                              Unit                                (tpy), pre-RFG   SO2 emissions   SO2 emissions
                                                                  as reported by  as reported by       (tpy)
                                                                      Tesoro          Tesoro
----------------------------------------------------------------------------------------------------------------
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
----------------------------------------------------------------------------------------------------------------
                                                                                   Washington's
                                                                    2006\*\ NOX      estimated       Projected
                                                                     Baseline        emissions     reduction in
                              Unit                                   emissions     based on BART   NOX emissions
                                                                     (tpy) as       analysis in      from BART
                                                                    reported by    SIP submittal  controls (tpy)
                                                                      Tesoro       (appendix L)
----------------------------------------------------------------------------------------------------------------
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 non-BART 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

[[Page 76198]]

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- PM: End routine use of fuel
 6654, F-6655, Flare X-819, Cooling       oil. Use of refinery fuel gas
 Towers 2 and 2a.                         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

[[Page 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.

[[Page 76200]]

 
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

[[Page 76201]]

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      PM10: Existing baghouses 0.005 g/dscf.
 Plant.
------------------------------------------------------------------------

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

[[Page 76202]]

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

[[Page 76203]]

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

[[Page 76204]]

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

[[Page 76205]]

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

[[Page 76206]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

[[Page 76207]]

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 cost-effective, 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

[[Page 76208]]

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:

Sec.  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 (Sec.  51.308(e)). The EPA BART 
regulations are found in Sec. Sec.  52.2500 and 52.2501.
* * * * *
    3. Add Sec. Sec.  52.2500 and 52.2501 to read as follows:

Sec.  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) x (% sulfur in baked anodes/100) x (% sulfur 
converted to SO2/100) x (2 pounds of SO2 per 
pound of sulfur) x (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.

[[Page 76209]]

Sec.  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