[Federal Register Volume 65, Number 140 (Thursday, July 20, 2000)]
[Proposed Rules]
[Pages 45003-45013]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-17875]



[[Page 45003]]

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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.

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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

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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.
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    \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.
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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\
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    \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.
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    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

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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 
(NOX). 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 NOX. 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

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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

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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, 
NOX 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 
NOX emissions from MGS on visibility impairment at GCNP was 
not estimated as part of Project MOHAVE. MGS must, however, reduce 
particulate matter and NOX 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 
NOX 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-NOX 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 NOx 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 
NOx 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 
NOX control systems--3/01/03
Issue binding contract to procure SO2, opacity and 
NOX control systems--9/01/03
Commence physical, on-site construction of SO2 and opacity 
equipment--4/01/04
Complete construction of SO2, opacity and NOX 
control equipment and complete tie in for first unit--7/01/05
Complete construction of SO2, opacity and NOX 
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 NOx 
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-
NOX 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 NOX control systems for Unit 1 and Unit 2 by March 1, 
2003.
    (ii) Issue a binding contract to procure the SO2, 
opacity and NOX 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 
NOX control equipment and complete tie in for first unit by 
July 1, 2005.
    (v) Complete construction of SO2, opacity and 
NOX 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 NOX 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 
NOX 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