[Federal Register Volume 77, Number 247 (Wednesday, December 26, 2012)]
[Proposed Rules]
[Pages 76173-76209]
[FR Doc No: 2012-30090]

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

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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<PHONE_NUMBER> 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<EMAIL_ADDRESS>     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<EMAIL_ADDRESS>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:

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

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

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

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

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

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

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

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%

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

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.

    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

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

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

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.

    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

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

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