Approval and Promulgation of Implementation Plans: Revision of the Visibility FIP for Nevada

Related Material

Other Related Documents
Note: EPA no longer updates this information, but it may be useful as a reference or resource.
 


[Federal Register: July 20, 2000 (Volume 65, Number 140)]
[Proposed Rules]
[Page 45003-45013]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr20jy00-25]

[[Page 45003]]

-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 52

[FRL-6731-2]


Approval and Promulgation of Implementation Plans: Revision of
the Visibility FIP for Nevada

AGENCY: Environmental Protection Agency.

ACTION: Proposed rule.

-----------------------------------------------------------------------

SUMMARY: The Environmental Protection Agency (EPA) is conducting a
review of, and proposing to revise, the long-term strategy portion of
the Nevada federal implementation plan (FIP) for Class I visibility
protection (Nevada Visibility FIP). EPA proposes to revise the Nevada
Visibility FIP to include emissions reduction requirements for the
Mohave Generating Station (MGS), which is located in Clark County,
Nevada. The proposed requirements are based on a consent decree entered
into by the owners of MGS and the Grand Canyon Trust (GCT), the Sierra
Club, and the National Parks and Conservation Association (NPCA). EPA
believes that the emissions reductions that will result from compliance
with the consent decree will address concerns raised by the Department
of the Interior (DOI or Department) regarding the Mohave Generating
Station's contribution to visibility impairment at the Grand Canyon
National Park (GCNP) due to sulfur dioxide (SO2) emissions.
EPA also believes that adopting the requirements of the consent decree
into the long-term strategy of the Nevada Visibility FIP will allow for
reasonable progress toward the Clean Air Act national visibility goal
with respect to the Mohave Generating Station's contribution to
visibility impairment at the Grand Canyon National Park due to
SO2 emissions.

DATES: Comments on this proposed rule must be submitted no later than
August 21, 2000.

ADDRESSES: Comments should be submitted (in duplicate, if possible) to:
EPA Region IX, 75 Hawthorne Street (AIR2), San Francisco, CA 94105,
Attn: Regina Spindler (Phone: 415-744-1251).
    Docket: EPA has established a docket for this notice, Docket Number
A2-99-01. Materials related to the development of this notice have been
placed in this docket. The docket is available for review at: EPA
Region IX, Air Division, 75 Hawthorne Street, San Francisco, CA 94105.
Interested persons may make an appointment with Regina Spindler, (415)
744-1251, to inspect the docket at EPA's San Francisco office on
weekdays between 9 a.m. and 4 p.m.
    Electronic Availability: This document is also available as an
electronic file on the EPA Region IX Web Page at http://www.epa.gov/
region09/air/mohave.

FOR FURTHER INFORMATION CONTACT: Regina Spindler (415) 744-1251,
Planning Office (AIR2), Air Division, EPA Region IX, 75 Hawthorne
Street, San Francisco, CA 94105.

SUPPLEMENTARY INFORMATION:

Outline

I. Background
    A. Statutory and Regulatory Framework
    1. Clean Air Act Visibility Requirements
    2. EPA's Visibility Regulations
    3. Federal Implementation Plans for Visibility Protection
    B. Visibility Impairment at the Grand Canyon National Park
    1. The Department of the Interior Certification of Visibility
Impairment
    2. Mohave Generating Station
    3. Project MOHAVE
    C. Grand Canyon Trust/Sierra Club Lawsuit
    1. Overview of Complaint
    2. Settlement and Consent Decree
    D. Advance Notice of Proposed Rulemaking
    E. Further Actions in Light of the Mohave Consent Decree
II. Review and Revision of the Nevada Visibility FIP Long-Term
Strategy
    A. Long-Term Strategy Review
    B. Consultation with Federal Land Managers
III. Proposed Action
    A. Emission Controls and Limitations
    B. Emission Control Construction Deadlines
    C. Emission Limitation Compliance Deadlines
    D. Interim Emission Limits
    E. Reporting
    F. Force Majeure Provisions
IV. Request for Public Comments
V. Administrative Requirements
    A. Executive Order 12866
    B. Executive Order 13045
    C. Executive Order 13084
    D. Executive Order 13132
    E. Regulatory Flexibility Act
    F. Unfunded Mandates
    G. National Technology Transfer and Advancement Act

I. Background

A. Statutory and Regulatory Framework

1. Clean Air Act Visibility Requirements
    Section 169A of the Clean Air Act (Act or CAA), 42 U.S.C. 7491,
provides for a visibility protection program and sets forth as a
national goal ``the prevention of any future, and the remedying of any
existing, impairment of visibility in mandatory Class I Federal areas
which impairment results from manmade air pollution.'' (The terms
``impairment of visibility'' and ``visibility impairment'' are defined
in the Act to include reduction in visual range and atmospheric
discoloration.) Section 169A requires EPA, after consultation with the
Secretary of the Interior, to promulgate a list of ``mandatory Class I
Federal areas'' where visibility is an important value. These areas
include international parks, national wilderness areas and national
memorial parks greater than five thousand acres in size, and national
parks greater than six thousand acres in size, as described in section
162(a) of the Act, 42 U.S.C. 7472(a). Each mandatory Class I Federal
area is the responsibility of a Federal Land Manager (FLM), the
Secretary of the federal department with authority over such lands.
Section 302(i) of the Act, 42 U.S.C. 7602(i). On November 30, 1979, EPA
identified 156 such mandatory Class I Federal areas, including the
Grand Canyon National Park (GCNP) in Arizona. 44 FR 69122.
    Section 169A(a)(1) of the Act states that ``Congress declares as a
national goal the prevention of any future, and the remedying of any
existing, impairment of visibility in mandatory class I Federal areas
which impairment results from manmade air pollution.'' Section
169A(a)(4) requires EPA to promulgate regulations to assure reasonable
progress toward meeting these national visibility protection goals.
EPA's regulations must require each state with a mandatory Class I
Federal area (or states with emissions that may reasonably be
anticipated to cause or contribute to visibility impairment in a
mandatory Class I Federal area) to revise the applicable implementation
plan for that state (SIP) to contain such emission limits, schedules of
compliance and other measures as may be necessary to make reasonable
progress toward meeting the national visibility protection goal. CAA
section 169A(b)(2), 42 U.S.C. 7491(b)(2). The SIP revisions for these
subject states must require each existing stationary facility \1\ that
emits any air pollutant that may reasonably be anticipated to cause or
contribute to visibility impairment in a mandatory Class I Federal area
to install and operate ``best available retrofit technology'' (BART)
for controlling emissions from such source to eliminate or reduce
visibility

[[Page 45004]]

impairment. CAA section 169A(b)(2)(A), 42 U.S.C. 7491(b)(2)(A).
Pursuant to section 169A(b)(2)(B) of the Act, 42 U.S.C. 7491(b)(2)(B),
EPA's regulations must further require these states to include long-
term strategies in their SIP revisions for making reasonable progress
toward meeting the national goal. Section 110(a)(2)(J) of the Act, 42
U.S.C. 7410(a)(2)(J), provides a corollary provision that requires SIPs
to meet the visibility protection requirements of part C of the Clean
Air Act.
---------------------------------------------------------------------------

    \1\ For purposes of the visibility protection requirements, the
term ``existing stationary facility'' means a source that falls
within any of 26 listed categories, has the potential to emit 250
tons per year or more of any air pollutant, and which was not in
operation prior to August 7, 1962, but was in existence on August 7,
1977. 40 CFR Sec. 51.301.
---------------------------------------------------------------------------

2. EPA's Visibility Regulations
    On December 2, 1980, EPA promulgated what it described as the first
phase of the required visibility regulations, codified at 40 CFR
51.300-51.307. 45 FR 80084. These visibility regulations apply to 36
states, including Nevada, that contain mandatory Class I Federal areas.
The visibility regulations require these 36 states to comply with the
requirements set forth above, including (1) coordinating development of
SIP requirements with appropriate FLMs; (2) developing a program to
assess and remedy visibility impairment from new and existing sources;
(3) developing a long-term strategy (10-15 years) to assure reasonable
progress toward the national visibility goal; (4) developing a
visibility monitoring strategy to collect information on visibility
conditions; and (5) considering in all aspects of visibility protection
any ``integral vistas'' (important views of landmarks or panoramas that
extend outside of the boundaries of the Class I area) identified by the
FLMs as critical to a visitor's enjoyment of the Class I area. 40 CFR
51.300-51.307.\2\
---------------------------------------------------------------------------

    \2\ These visibility regulations only address the type of
visibility impairment that is ``reasonably attributable'' to a
single source or small group of sources. In 1980 when EPA
promulgated these regulations, EPA deferred setting SIP requirements
to address visibility impairment caused by ``regional haze'' (i.e.,
a widespread, regionally homogeneous haze from a multitude of
sources which impairs visibility in every direction over a large
area) due to the complexity and technical limitations inherent in
attempting to identify, measure, and control this type of widespread
visibility impairment. In 1993, the National Academy of Sciences
concluded that ``current scientific knowledge is adequate and
control technologies are available for taking regulatory action to
improve and protect visibility.'' EPA published final regulations to
address regional haze on July 1, 1999 at 64 FR 35714.
---------------------------------------------------------------------------

    An FLM may, at any time, certify to a state that impairment of
visibility exists in a mandatory Class I Federal area. 40 CFR
51.302(c). If the FLM certifies such impairment at least 6 months prior
to submission of a revised SIP, an affected state must (1) identify
each existing stationary facility which may ``reasonably be anticipated
to cause or contribute'' to any impairment which is ``reasonably
attributable to that existing stationary facility,'' and (2) analyze
and determine what emission limitation represents the ``best available
retrofit technology'' at each such facility. 40 CFR 51.302(c)(4).
Visibility impairment is ``reasonably attributable'' to a facility if
it is ``attributable by visual observations or any other technique the
state deems appropriate.'' 40 CFR 51.301(s). The state must also
include in its plan an assessment of visibility impairment and a
discussion of how each element of the plan relates to preventing future
or remedying existing impairment in any mandatory Class I Federal area
in the state. 40 CFR 51.302(c)(2)(ii). The visibility regulations also
provide for periodic review, and revision as appropriate, of the long-
term strategy for making reasonable progress toward the visibility
goals at a minimum frequency of every three years. 40 CFR 51.306(c).
The 36 affected states were required to submit revisions to their SIPs
to comply with these requirements by September 2, 1981. 40 CFR
51.302(a)(1).
3. Federal Implementation Plans for Visibility Protection
    Most states did not meet the September 2, 1981 deadline for
submitting a SIP revision to address visibility protection. A number of
environmental groups sued EPA alleging that the Agency had failed to
perform a nondiscretionary duty under section 110(c) of the Act to
promulgate visibility FIPs. In settlement of the lawsuit, EPA agreed to
promulgate visibility FIPs according to a specified schedule. On July
12, 1985, EPA promulgated a FIP for the visibility monitoring strategy
and new source review (NSR) requirements of 40 CFR 51.304 and 51.307.
50 FR 28544. See also, 51 FR 5504 and 51 FR 22937. These provisions
have been codified at 40 CFR 52.26, 52.27 and 52.28. On November 24,
1987, EPA continued its visibility FIP rulemaking by promulgating its
plan for meeting the general visibility plan requirements and long-term
strategies of 40 CFR 51.302 and 51.306. 52 FR 45132. The long-term
strategy provisions have been codified at 40 CFR 52.29; the provisions
specifically pertaining to Nevada are at 40 CFR 52.1488.
    In the proposed rulemaking for the general visibility plan and
long-term strategy requirements, EPA addressed certifications of
existing visibility impairment submitted by the FLMs. 52 FR 7802 (March
12, 1987). EPA found that the information provided was not adequate to
enable the Agency to determine whether the impairment was traceable to
a single source and therefore addressable under the visibility
regulations. For this reason, EPA determined that the implementation
plans need not require BART or other control measures at that time. EPA
also acknowledged, however, that FLMs may certify the existence of
visibility impairment at any time and, therefore, FLMs might in the
future provide additional information on impairment that would allow
EPA to attribute it to a specific source. EPA stated that in such
cases, the information regarding impairment and the need for BART or
other control measures would be reviewed and assessed as part of the
periodic review of the long-term visibility strategy. 52 FR 7808. EPA
affirmed these determinations in its final rulemaking.

B. Visibility Impairment at the Grand Canyon National Park

1. The Department of the Interior Certification of Visibility
Impairment
    On November 14, 1985, the Department of the Interior certified to
EPA the existence of visibility impairment in all Class I Federal areas
within the Department's jurisdiction in the lower 48 states. On August
19, 1997, DOI sent a letter to EPA that reaffirmed the Department's
1985 certification of visibility impairment at the Grand Canyon
National Park and stated DOI's belief that there is sufficient
information available to support a ``reasonable attribution'' finding
concerning the Mohave Generating Station (MGS). The DOI provided, as an
attachment to its August 1997 letter, a summary prepared by the
National Park Service (NPS) of studies that DOI believes demonstrate
that emissions from MGS contribute to visibility impairment at GCNP.
The DOI requested that if EPA agreed with DOI's assessment of
``reasonable attribution,'' EPA comply with its statutory obligation to
determine the best available retrofit technology for MGS.
2. Mohave Generating Station
    The Mohave Generating Station is a 1580 MW coal-fired power plant
located in Laughlin, Nevada, approximately 75 miles southwest of GCNP.
It was built between 1967 and 1971. It currently emits over 40,000 tons
of SO2 per year. MGS is operated by Southern California
Edison Company, the majority owner of the plant. The Los Angeles
Department of Water and Power, Nevada Power Company, and Salt River
Project also own interests in the plant. The coal for the plant comes
from the Black Mesa

[[Page 45005]]

Coal Mine on the Hopi and Navajo Reservations via a 273-mile coal
slurry pipeline. The mine, operated by Peabody Western Coal Company, is
jointly owned by the Navajo Nation and the Hopi Tribe. Groundwater from
an aquifer underlying the Navajo and Hopi reservations provides the
water for the slurry pipeline.
3. Project MOHAVE
    In 1991, Congress directed EPA to conduct a tracer study to
ascertain the extent to which MGS contributes to visibility impairment
at GCNP. The tracer study was developed as a cooperative effort among
EPA, the NPS, and Southern California Edison Company. This cooperative
effort was named Project Measurement Of Haze And Visibility Effects,
more commonly referred to as Project MOHAVE.
    Project MOHAVE was an extensive monitoring, modeling, and data
assessment project designed to estimate the contributions of the MGS to
haze at GCNP. The field study component of the project was conducted in
1992 and contained two intensive monitoring periods (approximately 30
days in the winter and approximately 50 days in the summer). Tracer
materials were continuously released from the MGS stack during the two
intensive periods to enable the tracking of emissions specifically from
MGS. Tracer, ambient particulate composition and SO2
concentrations were measured at about 30 locations in a four-state
region. Two of these monitoring sites, Hopi Point, near the main
visitor center at the south rim of GCNP and Meadview near the far
western end of GCNP, were used as key receptor sites representative of
GCNP.
    The findings of Project MOHAVE are discussed briefly in section
II.A.4. below. The Project MOHAVE final report is available on the
Mohave page of the EPA Region IX web site and in Docket Number A2-99-01
at the EPA Region IX office.

C. Grand Canyon Trust/Sierra Club Lawsuit

1. Overview of Complaint
    On February 19, 1998, Grand Canyon Trust filed a citizen suit in
the federal district court for the District of Nevada against the
owners of MGS. GCT alleged that the defendants had violated several SIP
provisions that apply to MGS. GCT included allegations that MGS had
exceeded emission limits in the Nevada and Clark County SIPs for
opacity and sulfur dioxide, and had failed to conduct necessary
reporting. Sierra Club and the National Parks and Conservation
Association subsequently joined GCT as plaintiffs in the citizen suit.
See Grand Canyon Trust v. Southern California Edison (District of
Nevada) CV-S-98-00305-LDG.
2. Settlement and Consent Decree
    The litigation was eventually resolved through a consent decree
entered by the court on December 15, 1999 (Mohave consent decree). The
Mohave consent decree requires the installation of pollution control
equipment that will reduce visibility impairing SO2
emissions as well as particulate matter emissions and nitrogen oxides
(NO_X). The consent decree requires the plant owners to
install dry scrubber technology (lime spray dryers) to reduce
SO2 emissions from each boiler by at least 85% based on a
90-day rolling average. Each unit must also meet an SO2
emission limit of .150 lb/mmbtu based on a 365-day rolling average. The
owners will also install baghouses to control particulate matter
emissions and ensure that each unit meets a 20% opacity limit based on
a 6-minute average. New burners will also be installed in the boilers
to reduce emissions of NO_X. Unit 1 must be in compliance
with all pollution control requirements and emission limits by January
1, 2006 and Unit 2 by April 1, 2006. If any of the current owners sell
a portion of or all of their interest in the plant, the new owners must
comply with the terms of the consent decree. If all the current owners
sell their interests in the plant (100% sale), the new owners would be
required to install the pollution controls within 3 years and 3 months
of the sale, but no later than the January 1 and April 1, 2006 dates
discussed above. Prior to the final compliance dates, an interim
SO2 emissions limit of 1.0 lb/mmbtu, based on a 90-day
rolling average, will apply to each boiler. The interim opacity limit
is 30%, based on a 6-minute average.

D. Advance Notice of Proposed Rulemaking

    On June 17, 1999, EPA published an advance notice of proposed
rulemaking (ANPR) (64 FR 32458) ) regarding the assessment of
visibility impairment at GCNP. The ANPR provided background information
on statutory and regulatory requirements for protecting visibility in
national parks and wilderness areas and provided a brief summary of the
methodologies and results of Project MOHAVE. In the ANPR, EPA also
asked the public to submit additional information that the Agency
should consider before determining whether visibility problems at GCNP
can be reasonably attributed to MGS and information regarding
appropriate pollution control requirements for the facility, should EPA
find that any portion of the visibility impairment is reasonably
attributable to MGS.
    The public comment period for the ANPR closed on November 15, 1999.
EPA received comments from 83 entities. Most of the comments received
were from private citizens expressing concern about the environmental
impact of MGS on both GCNP and the local community. Other commenters
submitted their views on the findings of Project MOHAVE and whether EPA
should proceed with a ``reasonable attribution'' finding and BART
determination. While some commenters believe that there is ample
evidence to substantiate a ``reasonable attribution'' finding, others
argue that Project MOHAVE does not sufficiently prove that the MGS is
causing visibility impairment at GCNP. Some commenters believe that the
plant's contribution is not significant enough to warrant the
imposition of pollution control requirements and that such controls
would not result in a meaningful improvement in visibility at GCNP.
Several commenters emphasized the economic importance of MGS to the
local community and to the Navajo and Hopi, who supply coal to the
plant. These commenters asked that EPA fully evaluate the economic
impact of pollution control requirements on not only MGS owners but on
the local community and tribes. EPA did receive a number of comments
that were submitted after the environmental groups and owners of MGS
signed the consent decree discussed above. While the views of these
commenters varied with regard to the need for EPA to proceed with a
rulemaking given the agreement to install pollution controls, all
agreed that any EPA rulemaking and/or requirements for pollution
controls at the power plant should be consistent with the requirements
of the consent decree. All comments that EPA received in response to
the ANPR are in Docket Number A2-99-01.

E. Further Actions in Light of the Mohave Consent Decree

    The NPS commented, in response to the ANPR, that MGS's compliance
with the emission limitations contained in the Mohave consent decree
would address the concern expressed in its 1997 letter that sulfur
dioxide emissions from MGS are contributing to visibility impairment at
GCNP. In its November 12, 1999 comment letter on the ANPR, the NPS
stated: ``We request that EPA give strong consideration in its future
rule-making action to incorporate the components of the consent decree
as

[[Page 45006]]

appropriate as a means to address our concerns over the visibility
impairment at GCNP by MGS. The NPS has reviewed the consent decree and
find that the restrictions on future plant operation would address the
visibility concerns raised in our certification of impairment sent to
EPA on November 14, 1985 and reaffirmed on August 19, 1997.''
Considering the NPS comments, EPA believes that if the terms of the
Mohave consent decree are incorporated into the long-term strategy of
the Nevada Visibility FIP, then EPA need not address the issue of
``reasonable attribution'' or proceed with a BART determination. In
taking this action, EPA is not making a decision with respect to
whether there is sufficient information to proceed with a ``reasonable
attribution'' finding or to establish a BART emission limitation. EPA
is determining that such a decision is not necessary because the NPS
has indicated that its concerns regarding the impact of sulfur dioxide
emissions on visibility impairment at GCNP will be resolved if the
terms of the Mohave consent decree are contained within the Nevada
Visibility FIP.
    EPA agrees that inclusion of the Mohave consent decree provisions
in the Nevada Visibility FIP is an appropriate way to address the
impact of sulfur dioxide emissions from MGS on visibility impairment at
GCNP. EPA also believes that incorporation of the Mohave consent decree
provisions into the Nevada Visibility FIP will allow for reasonable
progress toward the national visibility goal and will ensure that the
emission limitations and other requirements applicable to MGS are
federally enforceable. (A detailed analysis of how the Mohave consent
decree requirements represent reasonable progress is contained below in
section II.A.4.) Thus, EPA is proposing to adopt the requirements of
the Mohave consent decree into the Nevada visibility FIP. Today's
action, however, does not address MGS's contribution to visibility
impairment in the form of regional haze. Under EPA's regional haze
regulations, the State of Nevada has the responsibility to prepare a
SIP that contains a strategy for reducing emissions of air pollutants
from sources that contribute to regional haze.

II. Review and Revision of Nevada Visibility FIP Long-Term Strategy

A. Long-Term Strategy Review

    As part of the long-term strategy to address visibility protection,
EPA is required to conduct a review of the Nevada Visibility FIP every
three years to determine whether the plan is sufficient or if
additional measures are necessary for visibility protection. 40 CFR
52.29(c)(4). (Because the State of Nevada does not have an approved SIP
for visibility, EPA is required to assume responsibility for visibility
protection until the State submits, and EPA approves, a SIP that
adequately provides for visibility protection.) Pursuant to 40 CFR
52.29, EPA must include in its triennial report an assessment of: (1)
The progress achieved in remedying existing impairment of visibility in
any mandatory Class I Federal area; (2) the ability of the long-term
strategy to prevent future impairment of visibility in any mandatory
Class I Federal area; (3) any change in visibility since the last such
report, or in the case of the first report, since plan approval; (4)
additional measures, including the need for SIP revisions, that may be
necessary to assure reasonable progress toward the national visibility
goal; (5) the progress achieved in implementing best available retrofit
technology (BART) and meeting other schedules set forth in the long-
term strategy; (6) the impact of any exemption granted under section
51.303; and (7) the need for BART to remedy existing visibility
impairment of any integral vista identified pursuant to section 51.304.
    In November 1998, the Environmental Defense Fund (EDF) submitted a
letter to the EPA Region IX Regional Administrator noting its concern
over EPA's failure to conduct a review of the Nevada Visibility FIP.
EDF noted that EPA had not updated the FIP or conducted any required
reviews, even though DOI had notified EPA of visibility impairment at
GCNP and submitted information indicating that such impairment is
attributable to emissions from MGS. EDF further referred to studies
that have been conducted (including Project MOHAVE) which EDF believes
indicate that emissions from MGS contribute to visibility impairment.
On April 20, 1999, EDF sent EPA notice of its intent to sue the Agency,
pursuant to section 304(b)(1) of the Act, 42 U.S.C. 7604(b)(1), and 40
CFR part 54. EDF's notice of intent to sue made the same claims as
contained in its November 1998 letter to EPA.
    In today's notice, EPA is proposing its first report assessing the
long-term visibility strategy for Nevada. This is the first report that
EPA has made since promulgating the Nevada Visibility FIP. EPA is
reviewing the long-term strategy only for the purpose of addressing the
DOI's certification of existing visibility impairment at GCNP and MGS's
contribution to that impairment and evaluating whether the terms of the
Mohave consent decree will make reasonable progress toward the national
visibility goal. EPA is not conducting a comprehensive review of the
long-term strategy of the Nevada Visibility FIP at this time. FLMs have
not provided any information and EPA is not aware of any evidence that
visibility impairment at any other Class I area can be attributed to a
specific source or group of sources located in Nevada. For this reason,
EPA does not believe that a comprehensive review of the Nevada long-
term strategy is necessary at this time.
1. The Progress Achieved in Remedying Existing Impairment of Visibility
in any Mandatory Class I Federal Area
    As discussed above, DOI first certified the existence of visibility
impairment at GCNP in 1985. DOI subsequently stated its belief in 1997
that MGS is contributing to that impairment. Since that time, EPA has
been working with DOI, including the NPS, to address these concerns.
Part of that effort was the completion of the Project MOHAVE study,
discussed in sections I.B.3. and II.A.4. of this action, to determine
the extent to which MGS contributes to visibility impairment at GCNP.
In addition, EPA published the June 17, 1999 ANPR to inform the public
of the study's findings and to request the submission of any other
information that EPA should consider before proceeding further.
Following EPA's publication of the ANPR, the GCT, Sierra Club, NPCA and
the owners of MGS began the process of negotiating a settlement of the
environmental groups' lawsuit against MGS. Ultimately the parties
agreed that MGS would install pollution control equipment that is
expected to significantly reduce visibility impairing pollutants. While
EPA was not a party to the Mohave consent decree, the Agency did
provide technical consultation to the parties during their
negotiations.
    As discussed above, both EPA and DOI believe that implementation of
the provisions of the Mohave consent decree and inclusion of such
requirements in the long-term strategy of the FIP will address the
concerns expressed by DOI regarding the impact of MGS's sulfur dioxide
emissions on visibility impairment at GCNP. EPA also believes the level
of improvement that will result from compliance with the Mohave consent
decree will achieve reasonable progress toward the national visibility
goal as it relates to MGS and GCNP. A detailed analysis of how the
consent decree requirements will address the visibility concerns and

[[Page 45007]]

achieve reasonable progress is contained below in section II.A.4.
2. Ability of Long-Term Strategy To Prevent Future Impairment of
Visibility in any Class I Area
    In general, EPA's process for reviewing new and modified emissions
sources under the Prevention of Significant Deterioration program (40
CFR 52.21) and New Source Review program (40 CFR 52.28) is designed to
address future impairment of visibility in Class I areas within Nevada
or affected by sources in Nevada. Because today's review of the long-
term strategy concerns only MGS's contribution to existing visibility
impairment at GCNP and whether the proposed controls make reasonable
progress toward the national visibility goal, EPA is not formally
reviewing the effect on future impairment at this time.
3. Any Change in Visibility Since Plan Approval
    Today's long-term strategy review addresses only MGS' contribution
to visibility impairment at GCNP and the steps that will be taken to
address its contribution. This review, therefore, will not address the
broader changes in visibility since promulgation of the Nevada
Visibility FIP.
4. Additional Measures, Including the Need for SIP Revisions, That May
Be Necessary To Assure Reasonable Progress Toward the National
Visibility Goal.
    EPA believes that the level of improvement that will result from
implementation of the Mohave consent decree represents reasonable
progress toward the national visibility goal and, therefore, that it is
necessary to revise the Nevada Visibility FIP to adopt the provisions
of the Mohave consent decree. In making such a determination, EPA must
consider the amount of visibility improvement expected from the
emissions limits. MGS currently emits over 40,000 tons of
SO2 per year. Under certain meteorological conditions,
SO2 converts to particulate sulfate in the atmosphere. It is
these sulfate particles that cause light to scatter which creates hazy
conditions and poor visibility. Project MOHAVE found that for the
summer study period, MGS contributed between 1.7 and 3.3 percent,
depending on the methodology used, of the measured sulfate
concentrations at Meadview, on the western edge of GCNP. The 90th
percentile estimate of MGS's contribution to sulfate, reported as 8.7
to 21 percent of total measured sulfate, can be used as an estimate of
the episodic effects of MGS emissions during the summer intensive study
period. Ten percent of the time, impacts higher than this range could
be expected but were too uncertain to quantify. The Project MOHAVE
estimates of MGS's contribution to total extinction, or total
visibility impairment, are 0.3 to 0.8 percent and 1.9 to 4.0 percent
for the average and 90th percentile conditions, respectively, during
the summer intensive study period. Again, impacts higher than the 90th
percentile range could be expected ten percent of the time. These
estimates are based only on MGS's contribution to visibility impairment
due to SO2 emissions. Project MOHAVE did not examine how
other emissions from the facility, such as particulate matter,
NO_X or organics, may affect visibility impairment. EPA also
notes that there is considerable uncertainty surrounding the
quantitative estimates of the effect of pollutant emissions on
visibility within the boundaries of GCNP.
    Once MGS is in compliance with the final emission limits
established in the Mohave consent decree, the 85% reduction in sulfur
dioxide emissions should remove most of the visibility impacts noted
above. During ten percent of the summer period, there will likely be a
noticeable improvement. The impact of particulate matter and
NO_X emissions from MGS on visibility impairment at GCNP was
not estimated as part of Project MOHAVE. MGS must, however, reduce
particulate matter and NO_X emissions as required by the
Mohave consent decree. There may be some additional visibility benefit
from reducing these emissions, though there has been no quantification
of that potential benefit. EPA believes, however, that it is
appropriate to adopt all of the emission limits and pollution controls
required by the Mohave consent decree since they were established as
part of a complete package. Therefore, EPA is proposing to include the
NO_X and particulate matter control requirements in the
revision to the Nevada Visibility FIP.
    Pursuant to CAA section 169A(g)(1), EPA must also consider the
following factors when determining reasonable progress: (1) the cost 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 the source. The following is EPA's evaluation
of these factors in determining whether implementation of the terms of
the Mohave consent decree constitutes reasonable progress relative to
MGS and its impact on GCNP:

    a. Cost of compliance. By signing the consent decree, the owners
of the Mohave Generating Station have demonstrated their willingness
to bear the costs associated with the retrofit. The owners estimate
the capital cost of the MGS retrofit will be $300 million. This
figure includes $220 million for installation of the lime spray
dryers and integral baghouses, $20 million for installation of the
low-NO_X burners, and $60 million for other site-specific
modifications related to installation of the pollution control
equipment. Upon examination of capital costs at other coal-fired
power plants that have installed similar pollution control equipment
in recent years, EPA believes the estimated costs to be reasonable.
For example, in 1999, the Navajo Generating Station (NGS), a 2250 MW
plant in Page, Arizona, completed installation of limestone wet
scrubber technology on its three boilers. The capital cost for this
retrofit was $420 million dollars or $187/kW.\3\ The estimated
capital cost to install lime spray dryers and baghouses at the
Hayden Generating Station, a 440 MW coal-fired plant in Colorado,
was $129 million, or $294/kW.\4\ The $177/kW ($280 million divided
by 1580 MW) estimate for installing the lime spray dryers and
baghouses and other associated retrofits at MGS is less than the
costs for both Hayden and NGS. In a 1991 EPA study of retrofit costs
for SO2 and NO_X control options at 200 coal-
fired power plants, the 50th percentile cost for lime spray drying
is estimated to be $213/kW.\5\ For a plant the size of MGS, this
equals a capital cost of $336 million. In calculating the 50th
percentile estimate, EPA included all or part of the cost of
baghouses for some of the boilers studied, so the $336 million
estimate should be compared to the $280 million that Southern
California Edison estimates the lime spray dryer, integral
baghouses, and related retrofits will cost. Again, the estimated
costs for MGS fall below the 50th percentile number. Finally, EPA
used its Integrated Air Pollution Control System Costing Program to
estimate a capital cost of $210 million, or $133/kW, for the lime
spray dryers and baghouses. This is comparable to Southern
California Edison's $220 million capital cost estimate. (The EPA
program did not include the other modifications related to
installation of the control equipment in its estimate. Southern
California Edison estimates these modifications will cost $60
million.) EPA's cost program estimates that annual costs for the MGS
retrofit will be $38 million and that the additional cost of
producing power will be .63 cents/kWH annually. The model also
predicts that the control strategy will cost $147/ton of particulate
removed and $1297/ton of SO2 removed. The Public Service

[[Page 45008]]

Company of Colorado (operators of Hayden Station) estimated a cost
of approximately $2000/ton SO2 removed and $100/ton
particulate matter removed (in 1996 dollars). Southern California
Edison's estimated capital cost of the pollution controls required
by the consent decree appear to be lower than or similar to
estimates for other similar retrofit projects. In addition, the
owners of MGS have voluntarily agreed to bear the cost of the
retrofit. EPA concludes, therefore, that the cost of compliance with
the requirements that EPA is proposing to adopt in the revised
Nevada visibility FIP is reasonable.
---------------------------------------------------------------------------

    \3\ Salt River Project web site, Navajo Generating Station page.
(www.srpnet.com/power/stations/navajo.html)
    \4\ ``Long-Term Strategy Review and Revision of Colorado's State
Implementation Plan for Class I Visibility Protection, Part I:
Hayden Station Requirements,'' August 15, 1996. Costs adjusted to
1999 dollars.
    \5\ ``Project Summary: Retrofit Costs for SO2 and
NO_X Control Options at 200 Coal-Fired Plants,'' EPA/600/
S7-90-021, March, 1991. Costs adjusted to 1999 dollars.
---------------------------------------------------------------------------

    b. Time necessary for compliance. The Mohave consent decree
requires that MGS be in full compliance with all emission limits
applicable to Unit 1 by January 1, 2006 and to Unit 2 by April 1,
2006. If a 100% sale of the facility is completed prior to December
30, 2002, the plant would be required to come into compliance even
sooner (3 years and 3 months from the final sale). The parties to
the consent decree agreed that the compliance deadlines allow an
appropriate period of time for installation of pollution control
equipment. For comparison purposes, if EPA were to make a
``reasonable attribution'' finding and BART determination, such a
rulemaking would likely not be complete until early to mid-2001. CAA
sections 169A(b)(2)(A) and 169A(g)(4) require that BART be installed
``as expeditiously as practicable but in no event later than five
years after the date'' that EPA would complete the reasonable
attribution/BART rulemaking. Under this scenario, EPA estimates that
installation of control equipment and compliance with emission
limits would occur by early to mid-2006, depending on when EPA
finalized the rulemaking. The time frame could be longer if there
were administrative and/or judicial appeals of the agency's
decision. EPA believes the MGS settlement offers emissions
reductions on a more rapid timetable than would likely be achievable
through a possibly controversial reasonable attribution finding and
BART process. Thus, EPA believes the time frame for compliance is
reasonable.
    c. Energy and non-air quality environmental impacts. There are a
number of impacts associated with installation of lime spray dryers
and baghouses that should be considered and evaluated, including
increased energy consumption, water usage and solid waste disposal.
Southern California Edison estimates, assuming an 85% generating
capacity factor, that MGS will need an additional 20 MW or 150,000
MWhrs/yr to operate the control equipment. Included in the cost
estimates discussed above is the capital cost for constructing a new
auxiliary substation to serve the increased load created by the new
control equipment. EPA believes that this additional energy
consumption is reasonable given the emission reductions and
improvements in visibility that will occur once the pollution
controls are operational. It is also worth noting that the increased
energy needs are less than would be required for a wet scrubber
system. SCE estimates that such a system would use 30 MW or 225,000
MWhrs/yr. Regarding increased water usage, SCE estimates that 1400
gallons per minute, or 1900 acre-ft/yr will be required to operate
the SO2 scrubbers. This is nearly 30% less than the 1800
gallons per minute (2500 acre-ft/yr) that would be required for a
wet scrubber system. Once operating, the lime spray dryers at MGS
will generate 160,000 tons/year of waste. A wet scrubber system
would generate 170,000 tons/year of waste. The MGS lime spray dryer
waste can potentially be sold for use as fertilizer; whether that
will occur depends on the distance to potential markets,
transportation costs, etc. If the waste cannot be sold, it will be
disposed of at an on-site waste disposal facility so there will be
no impacts from shipping waste off-site. Other impacts that could
affect the local community include increased truck traffic for
transporting the lime and other reagents necessary for operating the
scrubbers. The number of trips depends on which supplier is used. If
the lime is shipped from Arizona, SCE estimates there will be 11
additional trucks/day. If a Nevada supplier is chosen, truck traffic
will be increased by 7 trucks/day. This additional traffic is not
expected to have a significant impact on the local community and its
air quality, including the area's ability to remain in compliance
with EPA's health-based National Ambient Air Quality Standards for
pollutants such as particulate matter, ozone, and carbon monoxide.
EPA believes that the issues discussed above will not have a
significant adverse impact on the environment or the local
community. EPA also believes that these impacts are reasonable in
consideration of the significant emission reductions and visibility
improvement that will occur as a result of the pollution control
equipment.
    d. Remaining useful life of the source. Southern California
Edison estimates that MGS will continue to operate until 2025. This
was the original projection for the life of the source and is
largely dependent on the remaining coal reserves at the Black Mesa
Mine which is the sole supplier of coal to the facility. Given that
MGS will operate for 20 years beyond installation of the pollution
control equipment and compliance with the emission limits, the
proposed level of control is reasonable and will allow progress
toward the national visibility goal over that time.

    Considering the improvements in visibility that will likely occur,
that the cost of compliance is similar to or lower than compliance
costs for other coal-fired power plants, that the compliance deadlines
are consistent with compliance time frames if EPA were to undertake a
BART rulemaking, that the other environmental impacts are minimal, and
that the source will operate for another 20 years beyond the compliance
deadline, the requirements that EPA proposes to adopt into the Nevada
Visibility FIP meet the reasonable progress requirements of the Clean
Air Act.
5. Progress Achieved in Implementing BART and Meeting Other Schedules
Set Forth in the Long-Term Strategy
    The Nevada Visibility FIP that was promulgated in 1987 did not
contain any requirements for BART or set out any schedules for
compliance with emission limits or control strategies. Although Nevada
has one Class I area, FLMs have not certified visibility impairment in
this area. Moreover, though the FLMs had certified visibility
impairment at the Grand Canyon National Park prior to promulgation of
the Nevada Visibility FIP, at that time neither the FLMs nor EPA had
identified any specific sources in Nevada as contributing to the
impairment. No sources in Nevada were identified as potential
contributors to the impairment until the August 1997 letter from DOI
indicated that MGS was a likely source of visibility impairment.
Today's notice proposes to address that visibility impairment by
revising the long-term strategy of the Nevada Visibility FIP to
incorporate emission reduction requirements and compliance deadlines
for MGS.
6. The Impact of any Exemption (From BART) Granted Under Section 51.303
    The long-term strategy contains no requirements for BART and
therefore no exemptions from BART for any source.
7. The Need for BART To Remedy Existing Visibility Impairment of Any
Integral Vista Identified Pursuant to Section 51.304
    To date, FLMs have not identified integral vistas with existing
visibility impairment.

B. Consultation With Federal Land Managers

    Section 52.29(c)(3) of EPA's visibility FIP requires that EPA
consult with the appropriate FLMs during the review and revision of the
long-term strategy. Since DOI sent EPA the August 1997 letter
reaffirming its certification of visibility impairment at GCNP, EPA has
been working with the Department, including the National Park Service,
on possible approaches for resolving the MGS's contribution to the
visibility impairment. Since the Mohave consent decree was signed, EPA
has consulted with DOI and NPS regarding the approach proposed in
today's notice. As discussed earlier in this notice, NPS has reviewed
the consent decree and believes that an EPA rulemaking which adopts the
emission limits and other requirements from the decree is an
appropriate means of addressing its concerns regarding the impact of
SO2

[[Page 45009]]

emissions from MGS on visibility impairment at GCNP.

III. Proposed Action

    EPA proposes to revise the long-term strategy of the Nevada
Visibility FIP to adopt the emission limits, compliance deadlines and
other requirements of the consent decree between the Grand Canyon
Trust, Sierra Club, National Parks and Conservation Association and the
owners of the Mohave Generating Station (Southern California Edison,
Nevada Power, Salt River Project, Los Angeles Department of Water and
Power) as approved by the U.S. District Court of Nevada on December 15,
1999. A summary of the requirements that EPA is proposing to include in
the FIP is contained below. A complete description of the requirements
that EPA is proposing to adopt into the long-term strategy of the FIP
is contained in the proposed amendment to 40 CFR 52.1488 at the end of
this notice.

A. Emission Controls and Limitations

    The owners of MGS will install and operate lime spray dryer
technology on both units at the plant. This technology must provide for
SO2 reductions of at least 85% for each unit on a 90-boiler-
operating-day rolling average basis. A boiler-operating-day is defined
as any calendar day in which coal is combusted in the boiler of a unit
for more than 12 hours. SO2 emissions from each unit shall
not exceed .150 pounds per million BTU heat input on a 365-boiler-
operating-day rolling average basis. Compliance with the SO2
limits will be determined using continuous SO2 monitors. The
first boiler-operating-day of a rolling average period for a unit shall
be the first boiler-operating-day that occurs on or after the
compliance date for the unit. Once the unit has operated the necessary
number of days to generate an initial 90 or 365 day average, consistent
with the applicable limit, each additional day the unit operates a new
90 or 365 day (``rolling'') average is generated. The owners of MGS may
substitute other control technology provided that technology achieves
the applicable emission limits, subject to approval by EPA.
    The owners will install and operate fabric filter dust collectors
(polishing baghouses), without a by-pass, on both units at MGS. Opacity
of emissions shall be no more than 20.0%, averaged over each separate
6-minute period within an hour. Compliance with the opacity limit will
be determined using a continuous opacity monitor. The owners are
excused from meeting the opacity limit during cold startup if the
failure to meet such limit was due to the breakage of one or more bags
caused by condensed moisture. In addition, exceedances of the opacity
limit during a malfunction will not be considered a violation if
certain notification and mitigation requirements are met.

B. Emission Control Construction Deadlines

Issue binding contract to design the SO2, opacity and
NO_X control systems--3/01/03
Issue binding contract to procure SO2, opacity and
NO_X control systems--9/01/03
Commence physical, on-site construction of SO2 and opacity
equipment--4/01/04
Complete construction of SO2, opacity and NO_X
control equipment and complete tie in for first unit--7/01/05
Complete construction of SO2, opacity and NO_X
control equipment and complete tie in for second unit--12/31/05

    There will be no penalty for failure to meet these deadlines if the
final emission limitation compliance deadlines described in section
III.C. below are met, if coal-fired units at MGS are not in operation
after December 31, 2005, or if coal-fired units are not in operation
after December 31, 2005 and then recommence operation in compliance
with all emission controls and limitations.

C. Emission Limitation Compliance Deadlines

    Unless subject to a force majeure event as described in section
III.F. below, one unit at MGS must be in compliance with the
SO2 and opacity emission limitations and NO_X
control requirements by January 1, 2006 and the second unit by April 1,
2006. The second unit may only be operated after December 31, 2005 if
the control equipment has been installed and is in operation. The
control equipment on the second unit may be taken out of service
between December 31, 2005 and April 1, 2006 as necessary to assure its
proper operation or compliance with the final emission limits.
    If the owners' entire (i.e. 100%) ownership interest in MGS is
sold, and the closing date of such sale occurs on or before December
30, 2002, the applicable emission limitations shall become effective
for one unit three years from the date of the last closing, and for the
second unit three years and three months from the date of the last
closing.

D. Interim Emission Limits

    Until the final emission limitation compliance deadlines discussed
above in section III.D., each unit at MGS must meet an interim
SO2 emissions limit of 1.0 pounds per million BTU of heat
input calculated on a 90-boiler-operating-day rolling average basis.
Each unit must also meet an opacity limit of 30%, as averaged over each
separate 6-minute period within an hour, with no more than 375
exceedances of 30% allowed per calendar quarter.

E. Reporting

    Beginning January 1, 2001, and continuing on a biannual basis
through April 1, 2006, or the date the owners of MGS demonstrate
compliance with the applicable emission limits, the owners will provide
to EPA a report that describes all significant events in the preceding
six-month period that may impact the installation and operation of
pollution control equipment, including the status of a full or partial
sale of MGS. These reports will also provide all opacity readings in
excess of 30% and all SO2 90-boiler-operating-day rolling
averages for each unit for the preceding two quarters.
    Once the final emission limits take effect, the owners of MGS must
provide quarterly reports containing compliance information related to
the SO2 and opacity emissions limitations.

F. Force Majeure Provisions

    MGS may assert that noncompliance with a deadline imposed by the
FIP is attributable to a force majeure event. MGS must notify EPA of
the need for an extension and submit a report to EPA which describes
the delay and includes a schedule with extended deadlines.

IV. Request for Public Comments

    EPA is requesting comments on all aspects of the Nevada Visibility
FIP long-term strategy review and proposal to revise the long-term
strategy portion of the FIP. As indicated at the outset of this
document, EPA will consider any comments received by August 21, 2000.

V. Administrative Requirements

A. Executive Order 12866

    The Office of Management and Budget (OMB) has exempted this
regulatory action from Executive Order 12866, Regulatory Planning and
Review.

B. Executive Order 13045

    Executive Order 13045, entitled Protection of Children from
Environmental Health Risks and Safety Risks (62 FR 19885, April 23,
1997), applies to any rule that: (1) Is determined to be ``economically
significant'' as defined under Executive Order 12866, and (2) concerns
an environmental health or safety risk that

[[Page 45010]]

EPA has reason to believe may have a disproportionate effect on
children. If the regulatory action meets both criteria, the Agency must
evaluate the environmental health or safety effects of the planned rule
on children, and explain why the planned regulation is preferable to
other potentially effective and reasonably feasible alternatives
considered by the Agency. This rule is not subject to Executive Order
13045 because it is does not involve decisions intended to mitigate
environmental health or safety risks.

C. Executive Order 13084

    Under Executive Order 13084, Consultation and Coordination with
Indian Tribal Governments, EPA may not issue a regulation that is not
required by statute, that significantly or uniquely affects the
communities of Indian tribal governments, and that imposes substantial
direct compliance costs on those communities, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by the tribal governments, or EPA consults with those
governments. If EPA complies by consulting, Executive Order 13084
requires EPA to provide to the Office of Management and Budget, in a
separately identified section of the preamble to the rule, a
description of the extent of EPA's prior consultation with
representatives of affected tribal governments, a summary of the nature
of their concerns, and a statement supporting the need to issue the
regulation. In addition, Executive Order 13084 requires EPA to develop
an effective process permitting elected officials and other
representatives of Indian tribal governments ``to provide meaningful
and timely input in the development of regulatory policies on matters
that significantly or uniquely affect their communities.'' Today's rule
does not significantly or uniquely affect the communities of Indian
tribal governments or impose direct compliance costs on those
communities. This federal action adopts into federal regulation pre-
existing requirements under a court-enforceable consent decree and
imposes no new requirements. Accordingly, the requirements of section
3(b) of Executive Order 13084 do not apply to this rule.

D. Executive Order 13132

    Executive Order 13132, entitled Federalism (64 FR 43255, August 10,
1999) revokes and replaces Executive Orders 12612, Federalism and
12875, Enhancing the Intergovernmental Partnership. Executive Order
13132 requires EPA to develop an accountable process to ensure
``meaningful and timely input by State and local officials in the
development of regulatory policies that have federalism implications.''
``Policies that have federalism implications'' is defined in the
Executive Order to include regulations that have ``substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government.'' Under
Executive Order 13132, EPA may not issue a regulation that has
federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the Federal
government provides the funds necessary to pay the direct compliance
costs incurred by State and local governments, or EPA consults with
State and local officials early in the process of developing the
proposed regulation. EPA also may not issue a regulation that has
federalism implications and that preempts State law unless the Agency
consults with State and local officials early in the process of
developing the proposed regulation.
    This proposed rule will not have substantial direct effects on the
States, on the relationship between the national government and the
States, or on the distribution of power and responsibilities among the
various levels of government, as specified in Executive Order 13132 (64
FR 43255, August 10, 1999), because it merely proposes to adopt into
federal regulation the requirements from a court-enforceable consent
decree, and does not alter the relationship or the distribution of
power and responsibilities established in the Clean Air Act. Thus, the
requirements of section 6 of the Executive Order do not apply to this
rule.

E. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to conduct a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements unless the agency certifies
that the rule will not have a significant economic impact on a
substantial number of small entities. Small entities include small
businesses, small not-for-profit enterprises, and small governmental
jurisdictions. This proposed rule will not have a significant impact on
a substantial number of small entities because it does not create any
new requirements but simply adopts into federal regulation existing
requirements from a court-enforceable consent decree. Therefore,
because the proposed FIP revision does not create any new requirements,
I certify that this action will not have a significant economic impact
on a substantial number of small entities.

F. Unfunded Mandates

    Under Section 202 of the Unfunded Mandates Reform Act of 1995
(``Unfunded Mandates Act''), signed into law on March 22, 1995, EPA
must prepare a budgetary impact statement to accompany any proposed or
final rule that includes a Federal mandate that may result in estimated
annual costs to State, local, or tribal governments in the aggregate;
or to private sector, of $100 million or more. Under Section 205, EPA
must select the most cost-effective and least burdensome alternative
that achieves the objectives of the rule and is consistent with
statutory requirements. Section 203 requires EPA to establish a plan
for informing and advising any small governments that may be
significantly or uniquely impacted by the rule.
    EPA has determined that the proposed FIP revision does not include
a Federal mandate that may result in estimated annual costs of $100
million or more to either State, local, or tribal governments in the
aggregate, or to the private sector. This Federal action adopts into
federal regulation pre-existing requirements under a court-enforceable
consent decree, and imposes no new requirements. Accordingly, no
additional costs to State, local, or tribal governments, or to the
private sector, result from this action.

G. National Technology Transfer and Advancement Act

    Section 12 of the National Technology Transfer and Advancement Act
(NTTAA) of 1995 requires Federal agencies to evaluate existing
technical standards when developing a new regulation. To comply with
NTTAA, EPA must consider and use ``voluntary consensus standards''
(VCS) if available and applicable when developing programs and policies
unless doing so would be inconsistent with applicable law or otherwise
impractical.
    The EPA believes that VCS are inapplicable to this action. Today's
proposed action does not require the public to perform activities
conducive to the use of VCS.

List of Subjects in 40 CFR Part 52

    Environmental protection, Air pollution control, Sulfur oxides.

[[Page 45011]]

    Dated: June 29, 2000.
Carol M. Browner,
Administrator.
    For the reasons set out in the preamble title 40, chapter I of the
Code of Federal Regulations is proposed to be amended as follows:

PART 52--[AMENDED]

    1. The authority citation for part 52 continues to read as follows:

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

    2. Section 52.1488 is amended by adding paragraph (d) to read as
follows:

Sec. 52.1488  Visibility protection.

* * * * *
    (d) This paragraph (d) is applicable to the Mohave Generating
Station located in the Las Vegas Intrastate Air Quality Control Region
(Sec. 81.80 of this chapter).
    (1) Definitions.--Administrator means the Administrator of EPA or
her/his designee.
    Boiler-operating-day shall mean any calendar day in which coal is
combusted in the boiler of a unit for more than 12 hours. If coal is
combusted for more than 12 but less than 24 hours during a calendar
day, the calculation of that day's sulfur dioxide (SO2)
emissions for the unit shall be based solely upon the average of hourly
Continuous Emission Monitor System data collected during hours in which
coal was combusted in the unit, and shall not include any time in which
coal was not combusted.
    Coal-fired shall mean the combustion of any coal in the boiler of
any unit. If the Mohave Generating Station is converted to combust a
fuel other than coal, such as natural gas, it shall not emit pollutants
in greater amounts than that allowed by paragraph (d) of this section.
    Current owners shall mean the owners of the Mohave Generating
Station on December 15, 1999.
    Owner or operator means the owner(s) or operator(s) of the Mohave
Generating Station to which paragraph (d) of this section is
applicable.
    Rolling average shall mean an average over the specified period of
boiler-operating-days, such that, at the end of the first specified
period, a new daily average is generated each successive boiler-
operating-day for each unit.
    (2) Emission controls and limitations. The owner or operator shall
install the following emission control equipment, and shall achieve the
following air pollution emission limitations for each coal-fired unit
at the Mohave Generating Station, in accordance with the deadlines set
forth in paragraphs (d) (3) and (4) of this section.
    (i) The owner or operator shall install and operate lime spray
dryer technology on Unit 1 and Unit 2 at the Mohave Generating Station.
The owner or operator shall design and construct such lime spray dryer
technology to comply with the SO2 emission limitations,
including the following percentage reduction and pounds per million BTU
requirements:
    (A) SO2 emissions shall be reduced at least 85% on a 90-
boiler-operating-day rolling average basis. This reduction efficiency
shall be calculated by comparing the total pounds of SO2
measured at the outlet flue gas stream after the baghouse to the total
pounds of SO2 measured at the inlet flue gas stream to the
lime spray dryer during the previous 90 boiler-operating-days.
    (B) SO2 emissions shall not exceed .150 pounds per
million BTU heat input on a 365-boiler-operating-day rolling average
basis. This average shall be calculated by dividing the total pounds of
SO2 measured at the outlet flue gas stream after the
baghouse by the total heat input for the previous 365 boiler-operating-
days.
    (C) Compliance with the SO2 percentage reduction
emission limitation in paragraph (d)(2)(i) of this section shall be
determined using continuous SO2 monitor data taken from the
inlet flue gas stream to the lime spray dryer compared to continuous
SO2 monitor data taken from the outlet flue gas stream after
the baghouse for each unit separately. Compliance with the pounds per
million BTU limit shall be determined using continuous SO2
monitor data taken from the outlet flue gas stream after each baghouse.
The continuous SO2 monitoring system shall comply with all
applicable law (e.g., 40 CFR part 75). The inlet SO2 monitor
shall also comply with the quality assurance-quality control procedures
in 40 CFR part 75, Appendix B.
    (D) For purposes of calculating rolling averages, the first boiler-
operating-day of a rolling average period for a unit shall be the first
boiler-operating-day that occurs on or after the specified compliance
date for that unit. Once the unit has operated the necessary number of
days to generate an initial 90 or 365 day average, consistent with the
applicable limit, each additional day the unit operates a new 90 or 365
day (``rolling'') average is generated. Thus, after the first 90
boiler-operating-days from the compliance date, the owner or operator
must be in compliance with the 85 percent sulfur removal limit based on
a 90-boiler-operating-day rolling average each subsequent boiler-
operating-day. Likewise, after the first 365 boiler-operating-days from
the compliance date, the owner or operator must be in compliance with
the .150 sulfur limit based on a 365-boiler-operating-day rolling
average each subsequent boiler-operating-day.
    (E) Nothing in this paragraph (d) shall prohibit the owner or
operator from substituting equivalent or superior control technology,
provided such technology meets applicable emission limitations and
schedules, upon approval by the Administrator.
    (ii) The owner or operator shall install and operate fabric filter
dust collectors (also known as FFDCs or baghouses), without a by-pass,
on Unit 1 and Unit 2 at the Mohave Generating Station. The owner or
operator shall design and construct such FFDC technology (together with
or without the existing electrostatic precipitators) to comply with the
following emission limitations:
    (A) The opacity of emissions shall be no more than 20.0 percent, as
averaged over each separate 6-minute period within an hour, beginning
each hour on the hour, measured at the stack.
    (B) In the event emissions from the Mohave Generating Station
exceed the opacity limitation set forth in paragraph (d) of this
section, the owner or operator shall not be considered in violation of
this paragraph if they submit to the Administrator a written
demonstration within 15 days of the event that shows the excess
emissions were caused by a malfunction (a sudden and unavoidable
breakdown of process or control equipment), and also shows in writing
within 15 days of the event or immediately after correcting the
malfunction if such correction takes longer than 15 days:
    (1) To the maximum extent practicable, the air pollution control
equipment, process equipment, or processes were maintained and operated
in a manner consistent with good practices for minimizing emissions;
    (2) Repairs were made in an expeditious fashion when the operator
knew or should have known that applicable emission limitations would be
exceeded or were being exceeded. Individuals working off-shift or
overtime were utilized, to the maximum extent practicable, to ensure
that such repairs were made as expeditiously as possible;
    (3) The amount and duration of excess emissions were minimized to
the maximum extent practicable during periods of such emissions;
    (4) All reasonable steps were taken to minimize the impact of the
excess emissions on ambient air quality; and
    (5) The excess emissions are not part of a recurring pattern
indicative of

[[Page 45012]]

inadequate design, operation, or maintenance.
    (C) Notwithstanding paragraphs (d)(2)(ii) (A) and (B) of this
section the owner or operator shall be excused from meeting the opacity
limitation during cold startup (defined as the startup of any unit and
associated FFDC system after a period of greater than 48 hours of
complete shutdown of that unit and associated FFDC system) if they
demonstrate that the failure to meet such limit was due to the breakage
of one or more bags caused by condensed moisture.
    (D) Compliance with the opacity emission limitation shall be
determined using a continuous opacity monitor installed, calibrated,
maintained and operated consistent with applicable law (e.g., 40 CFR
part 60).
    (iii) The owner or operator shall install and operate low-
NO_X burners and overfire air on Unit 1 and Unit 2 at the
Mohave Generating Station.
    (3) Emission control construction deadlines. The owner or operator
shall meet the following deadlines for design and construction of the
emission control equipment required by paragraph (d)(2) of this
section. These deadlines and the design and construction deadlines set
forth in paragraph (d)(4)(iii) of this section are not applicable if
the emission limitation compliance deadlines of paragraph (d)(4) of
this section are nonetheless met; or coal-fired units at the Mohave
Generating Station are not in operation after December 31, 2005; or
coal-fired units at the Mohave Generating Station are not in operation
after December 31, 2005 and thereafter recommence operation in
accordance with the emission controls and limitations obligations of
paragraph (d)(2) of this section.
    (i) Issue a binding contract to design the SO2, opacity
and NO_X control systems for Unit 1 and Unit 2 by March 1,
2003.
    (ii) Issue a binding contract to procure the SO2,
opacity and NO_X control systems for Unit 1 and Unit 2 by
September 1, 2003.
    (iii) Commence physical, on-site construction of SO2 and
opacity equipment for Unit 1 and Unit 2 by April 1, 2004.
    (iv) Complete construction of SO2, opacity and
NO_X control equipment and complete tie in for first unit by
July 1, 2005.
    (v) Complete construction of SO2, opacity and
NO_X control equipment and complete tie in for second unit by
December 31, 2005.
    (4) Emission limitation compliance deadlines. (i) The owner's or
operator's obligation to meet the SO2 and opacity emission
limitations and NO_X control obligations set forth in
paragraph (d)(2) of this section shall commence on the following dates,
unless subject to a force majeure event as provided for in paragraph
(d)(7) of this section:
    (A) For one unit, January 1, 2006; and
    (B) For the other unit, April 1, 2006.
    (ii) The unit that is to meet the emission limitations by April 1,
2006 may only be operated after December 31, 2005 if the control
equipment set forth in paragraph (d) (2) of this section has been
installed on that unit and the equipment is in operation. However, the
control equipment may be taken out of service for one or more periods
of time between December 31, 2005 and April 1, 2006 as necessary to
assure its proper operation or compliance with the final emission
limits.
    (iii) If the current owners' entire (i.e., 100%) ownership interest
in the Mohave Generating Station is sold either contemporaneously, or
separately to the same person or entity or group of persons or entities
acting in concert, and the closing date or dates of such sale occurs on
or before December 30, 2002, then the emission limitations set forth in
paragraph (d)(2) of this section shall become effective for one unit
three years from the date of the last closing, and for the other unit
three years and three months from the date of the last closing. With
respect to interim construction deadlines, the owner or operator shall
issue a binding contract to design the SO2, opacity and
NO_X control systems within six months of the last closing,
issue a binding contract to procure such systems within 12 months of
such closing, commence physical, on-site construction of SO2
and opacity control equipment within 19 months of such closing, and
complete installation and tie-in of such control systems for the first
unit within 36 months of the last closing and for the second unit
within 39 months of the last closing.
    (5) Interim emission limits. For the period of time between [the
effective date of paragraph (d) of this section] and the date on which
each unit must commence compliance with the final emission limitations
set forth in paragraph (d)(2) of this section (``interim period''), the
following SO2 and opacity emission limits shall apply:
    (i) SO2: SO2 emissions shall not exceed 1.0
pounds per million BTU of heat input calculated on a 90-boiler-
operating-day rolling average basis for each unit;
    (ii) Opacity: The opacity of emissions shall be no more than 30
percent, as averaged over each separate 6-minute period within an hour,
beginning each hour on the hour, measured at the stack, with no more
than 375 exceedances of 30 percent allowed per calendar quarter
(including any pro rated portion thereof), regardless of reason. If the
total number of excess opacity readings from [the effective date of
paragraph (d) of this section] to the time the owner or operator
demonstrates compliance with the final opacity limit in paragraph
(d)(2) of this section, divided by the total number of quarters in the
interim period (with a partial quarter included as a fraction), is
equal to or less than 375, the owner or operator shall be in compliance
with this interim limit.
    (6) Reporting. (i) Commencing on January 1, 2001, and continuing on
a bi-annual basis through April 1, 2006, or such earlier time as the
owner or operator demonstrates compliance with the final emission
limits set forth in paragraph (d)(2) of this section, the owner or
operator shall provide to the Administrator a report that describes all
significant events in the preceding six month period that may or will
impact the installation and operation of pollution control equipment
described in this paragraph, including the status of a full or partial
sale of the Mohave Generating Station based upon non-confidential
information. The owner's or operator's bi-annual reports shall also set
forth for the immediately preceding two quarters: All opacity readings
in excess of 30 percent, and all SO2 90-boiler-operating-day
rolling averages in BTUs for each unit for the preceding two quarters.
    (ii) Within 30 days after [the end of the first calendar quarter
for which the emission limitations in paragraph (d)(2) of this section
first take effect], but in no event later than April 30, 2006, the
owner or operator shall provide to the Administrator on a quarterly
basis the following information:
    (A) The percent SO2 emission reduction achieved at each
unit during each 90-boiler-operating-day rolling average for each
boiler-operating-day in the prior quarter. This report shall also
include a list of the days and hours excluded for any reason from the
determination of the owner's or operator's compliance with the
SO2 removal requirement.
    (B) All opacity readings in excess of 20.0 percent, and a statement
of the cause of each excess opacity reading and any documentation with
respect to any claimed malfunction or bag breakage.
    (C) Each unit's 365-boiler-operating-day rolling average for each
boiler-operating-day in the prior quarter following [the first full 365
boiler-operating-days after the .150 pound SO2

[[Page 45013]]

limit in paragraph (d)(2) of this section takes effect].
    (7) Force majeure provisions. (i) For the purpose of this
paragraph, a ``force majeure event'' is defined as any event arising
from causes wholly beyond the control of the owner or operator or any
entity controlled by the owner or operator (including, without
limitation, the owner's or operator's contractors and subcontractors,
and any entity in active participation or concert with the owner or
operator with respect to the obligations to be undertaken by the owner
or operator pursuant to this paragraph), that delays or prevents or can
reasonably be anticipated to delay or prevent compliance with the
deadlines in paragraphs (d)(3) and (4) of this section, despite the
owner's or operator's best efforts to meet such deadlines. The
requirement that the owner or operator exercise ``best efforts'' to
meet the deadline includes using best efforts to avoid any force
majeure event before it occurs, and to use best efforts to mitigate the
effects of any force majeure event as it is occurring, and after it has
occurred, such that any delay is minimized to the greatest extent
possible.
    (ii) Without limitation, unanticipated or increased costs or
changed financial circumstances shall not constitute a force majeure
event. The absence of any administrative, regulatory, or legislative
approval shall not constitute a force majeure event, unless the owner
or operator demonstrates that, as appropriate to the approval: they
made timely and complete applications for such approval(s) to meet the
deadlines set forth in paragraph (d)(3) of this section or paragraph
(d)(4) of this section; they complied with all requirements to obtain
such approval(s); they diligently sought such approval; they diligently
and timely responded to all requests for additional information; and
without such approval, the owner or operator will be required to act in
violation of law to meet one or more of the deadlines in paragraph
(d)(3) of this section or paragraph (d)(4) of this section.
    (iii) If any event occurs which causes or may cause a delay by the
owner or operator in meeting any deadline in paragraphs (d)(3) or (4)
of this section and the owner or operator seeks to assert the event is
a force majeure event, the owner or operator shall notify the
Administrator in writing within 30 days of the time the owner or
operator first knew that the event is likely to cause a delay (but in
no event later than the deadline itself). The owner or operator shall
be deemed to have notice of any circumstance of which their contractors
or subcontractors had notice, provided that those contractors or
subcontractors were retained by the owner or operator to implement, in
whole or in part, the requirements of paragraph (d) of this section.
Within 30 days of such notice, the owner or operator shall provide in
writing to the Administrator a report containing: an explanation and
description of the reasons for the delay; the anticipated length of the
delay; a description of the activity(ies) that will be delayed; all
actions taken and to be taken to prevent or minimize the delay; a
timetable by which those measures will be implemented; and a schedule
that fully describes when the owner or operator proposes to meet any
deadlines in paragraph (d) of this section which have been or will be
affected by the claimed force majeure event. The owner or operator
shall include with any notice their rationale and all available
documentation supporting their claim that the delay was or will be
attributable to a force majeure event.
    (iv) If the Administrator agrees that the delay has been or will be
caused by a force majeure event, the Administrator and the owner or
operator shall stipulate to an extension of the deadline for the
affected activity(ies) as is necessary to complete the activity(ies).
The Administrator shall take into consideration, in establishing any
new deadline(s), evidence presented by the owner or operator relating
to weather, outage schedules and remobilization requirements.
    (v) If the Administrator does not agree in her sole discretion that
the delay or anticipated delay has been or will be caused by a force
majeure event, she will notify the owner or operator in writing of this
decision within 20 days after receiving the owner's or operator's
report alleging a force majeure event. If the owner or operator
nevertheless seeks to demonstrate a force majeure event, the matter
shall be resolved by the Court.
    (vi) At all times, the owner or operator shall have the burden of
proving that any delay was caused by a force majeure event (including
proving that the owner or operator had given proper notice and had made
``best efforts'' to avoid and/or mitigate such event), and of proving
the duration and extent of any delay(s) attributable to such event.
    (vii) Failure by the owner or operator to fulfill in any way the
notification and reporting requirements of this section shall
constitute a waiver of any claim of a force majeure event as to which
proper notice and/or reporting was not provided.
    (viii) Any extension of one deadline based on a particular incident
does not necessarily constitute an extension of any subsequent
deadline(s) unless directed by the Administrator. No force majeure
event caused by the absence of any administrative, regulatory, or
legislative approval shall allow the Mohave Generating Station to
operate after December 31, 2005, without installation and operation of
the control equipment described in paragraph (d)(2) of this section.
    (ix) If the owner or operator fails to perform an activity by a
deadline in paragraphs (d)(3) or (4) of this section due to a force
majeure event, the owner or operator may only be excused from
performing that activity or activities for that period of time excused
by the force majeure event.

[FR Doc. 00-17875 Filed 7-19-00; 8:45 am]
BILLING CODE 6560-50-P
Notices For
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
1999
1998
1997
1996
1995
1994
Approval and Promulgation of Implementation Plans: Revision of the Visibility FIP for Nevada

Related Material

Local Navigation
