00-17875. 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: [phone]).

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, [phone], 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 [phone], 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 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.

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]

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 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 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 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 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.

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 SO₂emissions 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 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

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:

§ 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 (§ 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 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 SO₂limit 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.

Footnotes

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 § 51.301.

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.

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.