DAR File No.: 28224
Filed: 09/08/2005, 11:46
Received by: NLNOTICE OF REVIEW AND STATEMENT OF CONTINUATION
Concise explanation of the particular statutory provisions under which the rule is enacted and how these provisions authorize or require the rule:
Rule R307-110 has 35 sections, each of which incorporates by reference one section or part of Utah's State Implementation Plan (SIP), which is required by Section 110 of the federal Clean Air Act (42 U.S.C. 7401). Most parts of the SIP review available data concerning emissions of air pollutants and how they interact with meteorology and topology to create air pollution that is harmful to human health; they also include appropriate control measures to ensure that pollution levels remain within limits that protect human health. Subsection 19-2-104(3)(e) authorizes the Air Quality Board to "prepare and develop a comprehensive plan or plans for the prevention, abatement, and control of air pollution in this state." Subsection 19-2-104(1)(a) authorizes the Air Quality Board to make rules "regarding the control, abatement, and prevention of air pollution from all sources and the establishment of the maximum quantity of air contaminants that may be emitted by any air contaminant source." These two provisions enable the Air Quality Board to prepare plans and to incorporate them into state rules to make them enforceable.
Summary of written comments received during and since the last five-year review of the rule from interested persons supporting or opposing the rule:
Rule R307-110 was last reviewed on March 27, 2002. The only written comments since then have addressed proposed additions and changes in the plans that are incorporated by reference by Rule R307-110; all of these comments were reviewed and discussed by the Air Quality Board (AQB) at the time of the amendments. Rule R307-110 has been amended 12 times since the last review; no comments were received on DAR 26946, published on March 1, 2004, and effective on June 8, 2004; DAR 27296, published on August 1, 2004, and effective on October 7, 2004; and DAR 27344, published on September 1, 2004, and effective on November 4, 2004. Comments were received on the other amendments, and are summarized below. These amendments were DAR 26616, addition of the Regional Haze SIP, published on October 1, 2003, and effective on December 31, 2003; DAR 26896, Provo Maintenance Plan for Carbon Monoxide, published February 1, 2004, and effective May 18, 2004; DAR 26898 - 26899, revisions to the Vehicle Inspection and Maintenance Plans, General Provisions and Utah County, published February 1, 2004, and effective on May 18, 2004; DAR 27295, update of the Salt Lake City Carbon Monoxide Maintenance Plan, published August 1, 2004, and effective on December 2, 2004; DAR 27343, update of the Ogden Carbon Monoxide Maintenance Plan, published September 1, 2004, and effective on January 4, 2005; DAR 27429, Sulfur Dioxide Maintenance Plan, published October 1, 2004, and effective on March 4, 2005; and DAR 27768 - 27769, PM10 Maintenance Plans for Salt Lake County, Utah County, and Ogden, and revised Emission Limits SIP for Salt Lake and Utah Counties. DAR 26616, ADD REGIONAL HAZE SIP AND APPENDICES, ORGANIZED BY ISSUE. GENERAL COMMENTS:
COMMENT 1: I am writing to express my strong support for the adoption and implementation of the strongest possible Utah state plan for regional haze in all five national parks in Utah. I have witnessed haze in many parks around the nation, from the Grand Canyon to Great Smoky Mountains. I want Utah's parks to remain clean, healthy, and pristine. These parks attract tourist and this tourism is crucial to Utah's current and future economy. (Richard Spotts, St. George) RESPONSE 1: Noted.
COMMENT 2: Utah's proposed plan appears to address all the major components required for inclusion in SIPs as specified in Utah's regional haze rule. (Stephen P. Martin, Intermountain Region, National Park Service) RESPONSE 2: Noted. CLEAN AIR CORRIDORS.
COMMENT 3: We agree with the Department's characterization of the clean air corridor requirements. Although it is unlikely that the emissions increase threshold will be triggered, we urge the State to consider that emission increases may not necessarily influence all Class I areas on the Colorado Plateau on the least-impaired days. Efforts should be taken to further refine the underlying meteorology and modeling for demonstrating impacts on the least impaired days. (William K. Lawson, PacifiCorp) RESPONSE 3: The State agrees that analysis of impact should address each Class I area individually, and that refinements are needed in meteorological and monitoring data for demonstrating impacts of emissions coming from the clean air corridor. WRAP's periodic "Causes of Haze" reports will provide more robust understanding of clean air corridors in the future. STATIONARY SOURCES: MILESTONES AND BACKSTOP TRADING PROGRAM.
COMMENT 4: In the section on the milestones there is one minor error. It says that compliance will be based on a three-year average of emissions. That is correct except for the first two years as shown in the table later on in the document. (Wayne Leipold, Phelps Dodge) RESPONSE 4: The language in Part D is an executive summary of the stationary source program, and all of the details are addressed in Part E. There is language further on in Part D that explains how the averaging will work, and the years 2003, 2004 and 2018 are addressed in that section.
COMMENT 5: As the result of the uncertainty created by the US Court of Appeals decision on the "American Corn Growers Association" challenge to the regional haze rule, it would be premature for the State of Utah to take any administrative action by choosing either 40 CFR 51.309 or 40 CFR 51.308 as an option to address regional haze. (Terry Ross, Center for Energy and Economic Development) RESPONSE 5: EPA's approval of the Annex on June 5, 2003 addressed the impact of the May 24, 2002 American Corn Growers Decision (Federal Register, Vol. 68, 108, pages 33766 - 33767). The approval notice states, "The American Corn Growers court decision did not address the provisions in the regional haze rule allowing States to adopt a trading program or other alternative measures in place of source specific measures for BART sources." The State of Utah has developed a SIP under section 309 of the RH rule based on years of work with the GCVTC and WRAP that identified the best approach to address regional haze on the Colorado Plateau. The approach is flexible, and addresses all of the significant sources of haze in the west. The American Corn Growers decision does not change these underlying reasons for implementing the regional approach allowed under section 309 of the RH rule.
COMMENT 6: The effect of the American Corn Growers decision is that EPA will need to revise the BART provisions, and this could have a ripple effect throughout the entire rule. The State of Utah should revise its SIP proposal to notify the public of the decision and assess the impact of that decision. (Terry Ross, Center for Energy and Economic Development) RESPONSE 6: As noted above, EPA addressed the impact of the American Corn Growers decision in the FR action that approved the Annex. The June 5, 2003 approval of the Annex established the requirements that a state must meet to submit a SIP under section 309 of the RH rule, and Utah is developing this SIP in accordance with that final rule.
COMMENT 7: It has not been shown that the Annex will achieve a humanly perceptible improvement in visibility impairment. All of the other provisions (e.g., fire, mobile sources, pollution prevention, etc.) are illusory. (Terry Ross, Center for Energy and Economic Development) RESPONSE 7: EPA's approval of the Annex on June 5, 2003 states, "The EPA continues to believe that the milestones provide for 'greater reasonable progress than BART' and for 'steady and continuing progress.'" (FR Vol. 68, 108, page 33769) The GCVTC strategies that are the basis for Utah's proposed SIP are focused on achievable emission reductions from all of the emission sources that contribute to regional haze. 40 CFR 51.309(a) states, "If a transport region State submits an implementation plan which is approved by EPA as meeting the requirements of this section, it will be deemed to comply with the requirements for reasonable progress for the period from approval of the plan to 2018."
COMMENT 8: The economic analysis for the Annex is not adequate. This analysis shows a disproportionate cost impact on downwind states such as Wyoming, Colorado and New Mexico. (Terry Ross, Center for Energy and Economic Development) RESPONSE 8: The economic analysis for the Annex supported the earlier GCVTC conclusions that an incentive-based market trading program is more cost-effective than a traditional command-and-control approach. An incentive-based program allows sources in all of the states to find the most cost-effective strategies to reduce SO2 emissions that affect regional haze on the Colorado Plateau as well as other Class I areas that were not addressed by the Annex.
COMMENT 9: The Annex was based on unrealistic cost assumptions for natural gas that creates a bias against coal. The Annex will create a disincentive for constructing new coal-fired power plants. (Terry Ross, Center for Energy and Economic Development) RESPONSE 9: The Annex was negotiated using the best information available at that time. However, the Market Trading Forum included uncertainty factors in the analysis to address changes in the underlying assumptions. More importantly, a regional emission cap allows flexibility to adapt to changing circumstances while still achieving the same or better environmental goals. If natural gas prices remain high, the cap will create an incentive to over control existing sources to make room under the cap for new, highly-controlled coal-fired power plants.
COMMENT 10: Regional haze strategies should be coordinated with the multi-pollutant legislation that is being debated by Congress. (Terry Ross, Center for Energy and Economic Development) RESPONSE 10: It is not clear when, or if, Congress will pass multi-pollutant legislation. If legislation is passed, Utah will need to review its regional haze strategy at that time to see if there are any impacts.
COMMENT 11: I do not share WRAP's faith (for 'faith' is what it is) in the market-based 'backstop trading' program. When we hit the regional cap for visibility impairment, as we inevitably will do before many years pass, we will have to revisit this program, iteratively. (Ivan Weber, Weber Sustainability Consultants) RESPONSE 11: The backstop trading program is fully enforceable to ensure that milestones are met. The program will be revisited regularly, both in comparing actual emissions against the cap annually, and in the SIP review and revisions that are due in 2008, 2013, and 2018.
COMMENT 12: The EPA Non-road Diesel Rule, at the minimum level of aggressiveness drafted by EPA, or 'better' is imperative to RHR goal attainment. WRAP's own comments on the Non-road Diesel Rule asked EPA to accelerate the implementation schedule and to deny exemptions, delays and exceptions requested by companies, particularly in the equipment manufacturing sector. This is critical to the Salt Lake Valley, as you know, because of the proximate Bingham Canyon Mine, but also because of the massive amount of construction on roads that has characterized the past few years. This latter activity promises to increase, along with housing and other infrastructure construction to accompany the projected trebling or quadrupling of Wasatch Front population by 2050. (Ivan Weber, Weber Sustainability Consultants) RESPONSE 12: Utah supports the WRAP's comments regarding EPA's Non-road Diesel Rule.
COMMENT 13: Please also enter into the record consideration of the new climate change regional study, to which I referred at the hearing last week: Preparing for a Changing Climate: The Potential Consequences of Climate Variability and Change, Rocky Mountain/Great Basin. A Report of the Rocky Mountain/Great Basin Regional Assessment Team, for the U.S. Global Change Research Program, Feb. 2003. Frederic H. Wagner, Principal Author and Editor. May be obtained from Dr. Fred Wagner, Utah State Univ. Ecology Center, Logan, UT 84322-5205, telephone (435) 797-2555, email at ecol@cc.usu.edu. The implications of this very thorough report's findings are potentially profound for this region, as you will discover. (Ivan Weber, Weber Sustainability Consultants) RESPONSE 13: Noted.
COMMENT 14: Under this Plan, coal fired electric utilities in Utah are allowed to expand and emit more visibility impairing pollutants. (Nina Dougherty, Sierra Club) RESPONSE 14: The proposed regional haze SIP establishes a declining regional SO2 cap with enforceable milestones. The cap does not limit SO2 emissions in Utah, but requires the reductions to occur in the region. Modeling performed by the WRAP contractor, ICF, indicated that future electrical demand would not concentrate SO2 emission increases in Utah, and that emission decreases would occur throughout the region. This SIP will be a complement to other existing programs, such as the Prevention of Significant Deterioration (PSD) permitting program, that will require new coal-fired power plants to meet stringent emission limitations and prevent significant deterioration of air quality in Utah's Class I areas.
COMMENT 15: An assessment of the contribution of NOx emissions to visibility impairment in Utah is brushed aside for five years. (Nina Dougherty, Sierra Club) Language used by the State indicates that some determination of the need for NOx-PM strategies has already been made, perhaps giving the impression that there may be little future concern for these pollutants as regional haze contributors. The NPS would prefer based on the incompleteness of the current WRAP work on this subject, that the State stress the ongoing assessment of visibility impacts of NOx and PM and the potential control strategies to address those impacts. It would be appropriate to indicate that determinations of these impacts and strategies will be addressed in future revisions of the plan, and would better reflect the current status to state that the State cannot determine what level of control, if any, would be appropriate for NOx and PM through a stationary source milestone program. (Stephen P. Martin, Intermountain Region, National Park Service) RESPONSE 15: Utah's SIP reflects the requirements of 40 CFR 51.309 by committing to address NOx and PM emissions from stationary sources in the 2008 SIP revision. The GCVTC and WRAP concentrated on sulfur dioxide emission reductions because SO2 was the most significant contributor to visibility impairment from stationary sources. Now that the work on SO2 has been completed, the WRAP is beginning the technical and policy analysis that will be needed to make informed decisions about NOx and PM for the 2008 SIP revision. The Division of Air Quality (DAQ) staff agree with both commenters that further work is needed to evaluate the impacts of NOx and PM emissions. Section XX.D.5 of the SIP has been revised in response to these comments, and to incorporate the conclusions of the final NOx/PM report that was presented to the WRAP on October 15, 2003. The final report will replace the earlier draft report in the TSD for the SIP.
COMMENT 16: The Market Trading Forum agreed to allow an increase in emissions in Utah, presumably on the basis that there would be a reduction in emissions in other states in the agreement, and, therefore, a net reduction in regional emissions. Possible problems are: (a) only five states out of the original nine will be in the market trading program and (b) the other states are also facing proposals for new traditional coal fired power plants. Because of the new energy situation, it would seem that there needs to be a careful, continuing inventory of emissions in the different states in the region, with appropriate action, such as Provision L.2.(2) "If the state finds that the implementation plan is inadequate to ensure reasonable progress due to emissions from outside the state, Utah shall notify EPA and the other contributing state(s), and initiate efforts through a regional planning process to address the emissions in question." The best time to address new emissions is during the permitting process rather than after construction and operation of the new facilities. (Nina Dougherty, Sierra Club) RESPONSE 16: Because regional SO2 emissions are capped, any new coal-fired power plants must "find room under the cap" for their new SO2 emissions. This is the advantage of a mass-based cap as opposed to a traditional command-and-control approach that would not address the cumulative effects of new source growth. Modeling performed by the WRAP contractor, ICF, indicated that future electrical demand would not concentrate SO2 emission increases in Utah or any other state, and that emission decreases would occur throughout the region. The proposed SIP will track SO2 emissions in Utah and in the 5-state region on an annual basis for comparison to the regional milestone. The 5-year SIP reviews in 2008 and 2013 will provide an opportunity to review progress and assess whether the current implementation plan elements and strategies are sufficient to enable Utah to meet all established reasonable progress goals.
COMMENT 17: A GCVTC analysis of the contribution of nitrates to visibility impairment found that nitrates were an important pollutant at Canyonlands. This would indicate that Utah should have a good reason to assess the contribution of NOx to visibility impairment. In addition, the recent WRAP report, "Stationary Source NOx and PM Emissions in the WRAP Region: An Initial Assessment of Emissions, Controls, and Air Quality Impacts," October 1, 2003, is not reassuring in supporting the idea of insignificance of nitrates in visibility impairment. The report states that "stationary source NOx emissions result in nitrates that probably cause about 2-5% of the impairment on the Colorado Plateau," with a footnote that says, "Some of the 20% haziest days, however are dominated by nitrate....During the 20 percent worst days on the Colorado Plateau, nitrate aerosols are responsible for about 6 to 18 percent of the man-made visibility impairment, although on some of these days they are responsible for as much as 40-60%". (p. I-3, I-4) The report adds that stationary sources have unique emission characteristics which may disproportionately impact visibility. There are also problems with the model--it works best in the summer months, a period when nitrate concentrations are low. It is stated that the current model produces uncertain results; more complete and accurate modeling results are needed. The report also emphasizes that "In addition to the modeling results, consideration should be given to meeting the reasonable progress goals of the regional haze rule, which generally imply a steady and continuous reduction in emissions and a prevention of degradation on the best visibility days." P. I-8 A problem with waiting five years for an assessment of the contribution of NOx and nitrates in Utah is that during that time period there will be notices of intent for new projects (just as there are right now) which would increase NOx emissions in Utah. It is better to tackle NOx reduction during the permitting stage than after construction and operation. We would hope that NOx modeling could begin when the modeling capability has improved, and that regional inventorying of operating and proposed NOx emissions is continuous. (Nina Dougherty, Sierra Club) RESPONSE 17: The proposed SIP commits to address the impact of stationary source NOx and PM emissions and the possible need for a regional cap to address growth in these pollutants in the 2008 SIP revision. As the commentor notes, modeling and inventory improvements are needed to better understand the impacts of these two pollutants. It is premature to draw policy conclusions regarding the impact of these pollutants from existing sources at this time. As described in the response to an earlier comment, the SIP has been revised to incorporate the conclusions from the final NOx/PM report. Between now and 2008, the Regional Haze SIP will complement other programs, such as the PSD permitting program, that require new sources of NOx and PM to meet stringent emission limitations and prevent significant deterioration of air quality in Utah's Class I areas.
COMMENT 18: Reasonably Attributable Visibility Impairment (RAVI). This is a very important provision to address the geographic aspect of sources near Class I areas in the context of regional haze. We hope the RAVI procedure will be used, such as in examining the impact of NOx and other emissions from the Hunter and Huntington units on visibility in Canyonlands. (Nina Dougherty, Sierra Club) RESPONSE 18: Utah's current visibility SIP addresses reasonably attributable visibility impairment (RAVI). Section XX.D.4 of the SIP addresses the relationship between the existing RAVI SIP and the new regional haze SIP. This section states, "If the National Park Service certifies impairment, the State of Utah will fulfill its obligations to determine attribution and if necessary determine BART for the applicable source or group of sources in accordance with Utah's SIP for visibility protection submitted to EPA on April 26, 1985 and approved on May 30, 1986."
COMMENT 19: The title of section XX.D.2 should be changed to reflect the specific requirement in 309. (William K. Lawson, PacifiCorp) RESPONSE 19: The title has been changed to: "Achievement of a 13% or Greater Reduction of Sulfur Dioxide by 2000."
COMMENT 20: The text in XX.D.3.a should mirror the language in 40 CFR 309 that requires the milestones to achieve "greater reasonable progress than BART." (William K. Lawson, PacifiCorp) RESPONSE 20: The second sentence in XX.D.3.a has been changed to: "The Annex demonstrated that the 2018 regional sulfur dioxide milestone provides for greater reasonable progress than would be achieved by application of best available retrofit technology (BART), as required by 40 CFR 51.309(f)(1)(i)."
COMMENT 21: PacifiCorp urges Utah to continue working with the federal land managers in order to refine the approach that will be used to address RAVI given that regional emissions are being reduced under the haze program. There are still a few significant policy issues that remain to be resolved (e.g., data interpretation methods revealing significant emission spikes within class I areas that would qualify them as genuine "hot spots" and identifying a portfolio of remedies if they become necessary). (William K. Lawson, PacifiCorp) RESPONSE 21: The State of Utah is working with the National Park Service to finalize a Memorandum of Agreement regarding the circumstances that would lead to a certification of impairment within the context of a regional haze SIP that establishes a declining SO2 emission cap. A draft MOA developed by the WRAP Market Trading Forum is included in the TSD to the RH SIP. DAQ staff agree with PacifiCorp that the resolution of any "hot spot" issues could be addressed with different remedies that achieved similar or better results. DAQ intends to work with the Federal Land Managers as new visibility data are gathered through the IMPROVE network to ensure that there are common understandings and agreements about visibility trends in the Class I areas.
COMMENT 22: PacifiCorp recommends that the State be very cautious about adjusting the interim milestones due to changes in flow measurement techniques at electric generating utilities, and recommends that the State rely on the emissions that utilities report to EPA under the acid rain program rather than focusing on relatively minor changes in the milestones. (William K. Lawson, PacifiCorp) RESPONSE 22: The WRAP Market Trading Forum discussed at length the issue of "paper" emission changes due to new flow measurement techniques. There was concern that these changes would undermine the goals of the Annex because real emission reductions would not occur, even though the reported emissions would show a decrease. The SIP provisions related to flow rate measurement methods were designed to ensure that actual emission reductions take place. These measures need to remain in place so that we can determine the scope of the "paper changes" that have occurred since 1999. The measures are also specifically required by 40 CFR 51.309(h)(1)(iv).
COMMENT 23: Revise XX.E.1.d.(2)(b) - at the end of this subsection, add the following sentence: "The draft report will be posted on the WRAP website for a period of public review and comment for not less than 30 days." (William K. Lawson, PacifiCorp) RESPONSE 23: The change has been made as recommended.
COMMENT 24: Revise XX.E.1.d.(3) to read as follows - "(3) Consensus decision: The executive secretary commits to meet with the participating states and tribes in March 2014 to discuss any comments received on the 2018 emission projections in the draft report. The participating states and tribes will decide through a consensus process, whether it can be determined that the 2018 milestone will not be met, and whether it is necessary to trigger the WEB trading program early in order to meet the SO2 emission reduction goals in 2018." (William K. Lawson, PacifiCorp) RESPONSE 24: The suggested language has not been added to the SIP. The purpose of the 2013 review is to determine whether we are heading into trouble so that the participating states and tribes can avoid a major non-compliance issue in 2018. If the 2018 penalty provisions are triggered, it will be a failure of the expected process, and sources in Utah would face significant financial penalties. By triggering the trading program, the states will use the backstop regulatory program to ensure that sources remain in compliance and that the goals of the program are met. The decision will be based on the best information available, but because the states and tribes will be using emission projections, there will always be some uncertainties in the numbers. It cannot be "determined that the milestones will not be met" with absolute certainty, and the proposed language could be interpreted to require certainty. The milestones are designed so that market forces and the incentive of avoiding a regulatory program will drive emission reductions rather than a regulatory program. The states and tribes will not trigger the trading program in 2013 unless this incentive process does not appear to be effective. The decision will not be made lightly. However, it is impossible to identify all of the factors that must be considered in this decision process at this point in time.
COMMENT 25: In Table 4, correct the tonnage for the Ute Indian Tribe in years 2008-2018 from 1,129 to 1,135. Also, the second half of Table 4, for years 2011 - 2018, is missing. (Laurel Dygowski, EPA Region 8) RESPONSE 25: The corrections have been made.
COMMENT 26: In E.1.c(4)(b), the reference to Table 3 should be Table 5. (Laurel Dygowski, EPA Region 8) RESPONSE 26: The correction has been made.
COMMENT 27: In E.1.d.(2)(b), "2013" should be added after December 31. (Laurel Dygowski, EPA Region 8) RESPONSE 27: The correction has been made.
COMMENT 28: In E.3.i(2)(b), the reference to SIP Section XX.E.5.k(1)(b) should be XX.E.3.k(1)(b). (Laurel Dygowski, EPA Region 8) RESPONSE 28: The correction has been made.
COMMENT 29: In E.3.k(2), it would be helpful to add the sentence from the model SIP stating, "More details on liabilities for different provisions can be found in the provisions of [state or tribe market trading rule]." It is an informative statement that can help direct people to appropriate liability provisions. (Laurel Dygowski, EPA Region 8) RESPONSE 29: The sentence has been added. FIRE PROGRAMS.
COMMENT 30: Utah Farm Bureau Federation believes the Utah State Implementation Plan for compliance with the Regional Haze rule accurately portrays the surveyed emissions from agricultural burning. In addition, the conclusion that the requirements of 40 CFR 51.309(d)(6)(i) are met through the voluntary emission reduction techniques and local government controls coincides with the empirical and anecdotal evidence Farm Bureau has observed. However, we believe the statement of agency action stated on page 64 of the SIP is attributed to a conclusion that does not bear out from the data. The SIP states: "Since agricultural burning has been documented in Section 3 to have an inordinate impact on visibility in Class I areas, the emission tracking activities will be conducted on a periodic basis...." We believe you have incorrectly stated the evidence of the data by utilizing the term "inordinate" and request you change the word to from "inordinate" to "insignificant." (Wes Quinton, Utah Farm Bureau Federation) RESPONSE 30: The text has been changed as follows: "Since agricultural burning has been documented in Subsection 2.b above to be a very small proportion of total emissions in Utah and a very small proportion of agricultural burning in the West, the emission tracking activities will be conducted on a periodic basis to determine if any significant changes have been made since the 2003 survey."
COMMENT 31: Part G addresses fire emissions from federal, State, and private lands but creates disparate treatment between wildlands and agricultural lands. Utah's Enhanced Smoke Management Plan (ESMP) only applies to federal and State land managers while exempting the agricultural sector. We question whether this meets the intent of EPA requirements for state visibility plans. (Stephen P. Martin, Intermountain Region, National Park Service) RESPONSE 31: The Western Regional Air Partnership (WRAP) and a survey conducted by Utah State University (USU) Extension indicate that agricultural burning is a very small portion of total emissions in Utah, and also of agricultural burning in the West. In 1996 a WRAP emission inventory found that Utah agricultural burning comprised approximately 1% of the WRAP total agricultural burning emissions and less than 1/4 of 1% of the total emissions in Utah. Since that time, a USU Extension survey indicates that agricultural burning activities have declined by 48% statewide since 1996. The survey, which is included in the Utah TSD, documents the reasons for the decline. The Regional Haze SIP does not create disparate treatment between wildlands and agricultural lands, nor are agricultural lands "exempted." Instead, it is consistent with our treatment of all other minor sources of air pollution, including minor industrial sources. For example, under Rule R307-204 of the Utah Administrative Code, only prescribed fires that cover 20 acres or more per burn or result in air emissions of 0.5 tons or more per burn are required to submit a burn plan and burn request, and gain approval from the executive secretary before ignition. Land managers are allowed to ignite only when the clearing index is 500 or greater.
COMMENT 32: The State relied on an agricultural survey to determine future air quality management strategies. In addition, the State concluded that "there are no hot spots where agricultural burning in close proximity to a Class I area is likely to cause an inordinate impact". Neither the proposed plan or the Utah Technical Support Documentation Supplement (Utah TSD) explained the methodology and criteria used to support that conclusion. This conclusion is also used to dismiss closer examination and timely tracking of agricultural fire activities by the State. Given the regional nature of the visibility impairment problem, we question whether the notion of "proximity to a Class I area" is relevant for regional haze purposes. (Stephen P. Martin, Intermountain Region, National Park Service) RESPONSE 32: The Agricultural Lands Inventory portion of Part G clarifies that the State will work collaboratively with the Utah Farm Bureau Federation and USU Extension to develop and implement an inventory and emissions tracking system for agricultural burning. The USU survey will be used as a baseline and emission tracking activities will be conducted periodically to determine if any changes have occurred since the survey. Results from the inventory will be provided in future progress reports to EPA required every five years by 40 CFR 51.309(d)(10)(i). Revisions have been made to the proposed plan to clarify DAQ's conclusions: "Emissions from agricultural burning are less than 0.25% of total Utah emissions and therefore do not result in significant impacts on visibility in the 16 Class I areas or on regional haze in general. Since agricultural burning emissions are minimal, agricultural land managers are currently not subject to the Utah Enhanced Smoke Management Plan." DAQ notes that tracking, monitoring and understanding the effects of agricultural burning emissions--as well as all other fire emissions--are just getting underway in most states, and our understanding of these issues will improve over time. Monitors are now available in four of Utah's five Class I areas, and comparisons can be made in the future to better understand the sources of visibility impairment. These comparisons will be documented in periodic WRAP reports on the causes of haze. However, DAQ finds that the USU Survey provides the best current information regarding the extent and practices of agricultural burning in Utah.
COMMENT 33: The State also discusses the concept of developing an emissions inventory for agricultural lands, but does not detail an approach or a timeline for this activity. The NPS believes that inventory methods should be implemented to help assure data reliability and to create a record of activity for long-term evaluation and needs. The information that is collected would provide the State with the means to determine on an ongoing basis whether the State should consider strengthening air management oversight of these activities in the future to reduce impacts on regional haze at any Class I area, not just the 16 Class I areas on the Colorado Plateau. (Stephen P. Martin, Intermountain Region, National Park Service) RESPONSE 33: Improvements are expected in tracking fire emissions, and our understanding of their impact on visibility also will improve. As per the five-year reports required under 40 CFR 51.309(d)(10)(i), there will be regular opportunity to consider whether changes are needed in managing fire activities. POLLUTION PREVENTION AND RENEWABLE ENERGY.
COMMENT 34: The problem of regional haze is just one symptom of our larger cultural dependence on fossil fuels and inefficient internal combustion engines. We need to reduce this dependence through an aggressive new combination of new energy sources as well as much greater energy efficiencies and conservation. I hope that Utah officials will demonstrate the wisdom, foresight and courage to change the status quo for the better to move us forward. Otherwise, with the explosion in human population and development in the St. George basin and elsewhere, the problems, including regional haze, will only worsen. (Richard Spotts, St. George) RESPONSE 34: Noted.
COMMENT 35: (William K. Lawson, PacifiCorp) We ask the State to include following Table 10 the following language from the Preamble to the federal regional haze rule: "The goals themselves are not enforceable and States are not required to meet the renewable energy goals...Rather, EPA is setting enforceable requirements for the States to assess progress toward goals established by the GCVTC with respect to renewable energy production as a means for reducing dependence on more polluting forms of energy production. States participating in the GCVTC strategy are responsible for explaining why they cannot meet the GCVTC goals. The required reporting by the States will inform the public of air quality improvements that would result from that goal had it been realized. It is the relationship between renewable energy production and associated environmental effects (direct and indirect) that is the thrust of the assessment and reporting effort under the SIP." (64 FR 35754-55) RESPONSE 35: This paragraph has not been added. This statement of the intent of 40 CFR 51.309(d)(8) matches our understanding but the Preamble carries the same weight whether or not it is included in the SIP and generally, we do not repeat language from the Preamble within the SIP.
COMMENT 36: In Appendix I, page 24, change the line to "PacifiCorp plans to purchase contracts for over 1,000 MW of renewables (such as wind, geothermal, and/or other resources)." Also, please check on the claim that, since Utahns pay 38% of our costs, then 38% of our renewable purchases will go towards meeting Utah's share of the WRAP's 10/20 renewables goals in Section 309. (William K. Lawson, PacifiCorp) RESPONSE 36: Appendix I has been moved to the Technical Support Document, and the sentence has been changed. It is clear that the IRP is a plan that is updated annually or biennially, and therefore is subject to change in future iterations. The word "approximately" has been added before "38%" to indicate that this share varies somewhat from year to year. WRAP states have determined that renewable energy will be apportioned to each state in accordance with that state's purchase of renewables, rather than on the basis of renewables generated within the state.
COMMENT 37: Appendix I, page 27: "Each block a customer agrees to purchase costs $1.95/month." (William K. Lawson, PacifiCorp) RESPONSE 37: This change has been made.
COMMENT 38: Appendix I, page 27-28: Should be "Blue Sky" rather than "Blue Skies." (William K. Lawson, PacifiCorp) RESPONSE 38: This change has been made.
COMMENT 39: The SIP appears to conclude that renewables and energy efficiency do little to decrease visibility impairing pollutants. (Nina Dougherty, Sierra Club) RESPONSE 39: Renewables and energy efficiency bring on line additional electric power to meet the growing demands of the West without adding additional emissions that impair visibility.
COMMENT 40: The SIP emphasizes that Utah does not have to meet within the state the goals of having 10% of its power generation come from renewables by 2005 and 20% by 2015, nor of enhancing energy efficiency programs, because according to the SIP those goals are to be achieved on a regional, not a state basis. Utah is just supposed to contribute in some way to those goals, but can proceed with increasing the percentage of coal used to generate electricity for Utah customers. (Nina Dougherty, Sierra Club) RESPONSE 40: Because regional haze spreads widely across the West, the Grand Canyon Visibility Transport Commission determined that regional programs could best meet the goal of improved visibility in Class I areas. The Commission recommended that reductions of sulfur dioxide from large stationary sources be achieved through a regional cap and a backstop regional trading program. Similarly, the Commission recommended regional renewable energy goals. This regional approach is especially appropriate for electricity generation because the electricity to meet demand is not generated within each state, but rather is generated where it is most economical to do so. Expected increases in renewable energy production that are paid for by Utah consumers are identified in the Technical Support Documentation. Examination of the data in the Technical Support Document indicates that the proportion of energy generation for demand within Utah--as opposed to demand in other states that is supplied by electricity generation in Utah--increasingly will come from renewable sources, with the expectation that Utah will generate about 550 MW of new renewable generating sources by 2013. Those sources may well lie outside Utah's boundaries, but will be paid for by Utah consumers. The Regional Haze Rule itself is not clear in how states submitting 309 SIPs should project their expected shares of the 10/20 goals, and several different methods are available. DAQ has chosen to estimate Utah's portion of peak summer demand, and estimates that Utah will be responsible or generating approximately that much renewable energy by 2013.
COMMENT 41: The states in the region are expected to contribute to the 10/20 regional goals, if not to achieve it. But surely, the states should do more than Utah to contribute to the regional goal. The SIP indicates that Utah has a huge untapped solar resource and impressive potential for wind generation in the state. Yet currently only 0.768% of its energy generation comes from non-hydro renewables (5.975% with Hydro). Geothermal is the main renewable used in Utah--39.8 MW in 2002--with landfill providing 1.6 MW, solar/PV 0.238 MW and wind 0.498. Even Utah's consumption of non-hydro renewable power from any source, whether in-state or out-of-state, is minimal - only 0.62%. Coal, on the other hand, was used to produce 87% of the electricity in Utah in 2002. (Nina Dougherty, Sierra Club) RESPONSE 41: All western states have untapped sources of renewable energy potential. When those resources will be developed depends upon market forces. A significant portion of the electricity generated in Utah serves consumers in other states. Again, the 10/20 goals are goals, and the WRAP's Air Pollution Prevention Forum recommends measuring each state's contribution toward the goals by the renewable energy purchased by consumers within the state, no matter where the electricity is generated. The Technical Support Document indicates that the renewable energy purchased by Utah consumers in the future will increase substantially, to approximately 550 MW by 2013 and Part I.4.b indicates that will meet Utah's share of the regional goal.
COMMENT 42: The assumption regarding distributed energy is very limited--"In general, small loads located more than 3 miles from the transmission and distribution grid have the highest potential for being served cost effectively by on-site renewable power generation." PV is in fact useful and used where there is connection to the grid. (Nina Dougherty, Sierra Club) RESPONSE 42: It is true that photovoltaics are used where there is connection to the grid, but the highest potential for their use is for small loads located at some distance from the grid.
COMMENT 43: Also of major concern is the assertion that increased use of renewables and energy efficiency would primarily replace generation by combined cycle natural gas in the region and would barely make a dent in generation by coal. The stated result of this is that renewable and energy efficiency programs would only result in minor reduction of NOx and that no significant visibility changes can be shown because the resolution of the regional air quality modeling system is insufficient for such marginal emission reductions. Also, WRAP modeling suggests that increased use of renewables and energy efficiency does not reduce SO2 emissions "because the regional SO2 trading program proposed under the Annex is the controlling factor in reducing SO2 emissions." (Nina Dougherty, Sierra Club) RESPONSE 43: Which traditional sources of energy generation will be displaced by renewables and energy efficiency increases was a prediction by the model used by ICF for the WRAP. In the SIP updates of 2008, 2013, and 2018, improved projection methods, as well as improved air quality modeling, are likely to yield a more accurate understanding of the magnitude of NOx reductions and their effect on visibility impairment. Finally, the SO2 milestones are the limiting factor for SO2 in the region. Renewable energy sources may be used to replace sources that emit SO2, but the fact that renewables are the substitute generation source will not change the amount of SO2 that is reduced.
COMMENT 44: The energy pollution prevention section of the SIP seems constructed to tell us that (1) Utah can continue on its minimal use of renewables and can depend on other states to do the right thing, and (2) that increased use of renewables and energy efficiency in the region will not do much to improve visibility. These are disturbing conclusions that can be rectified by (1) Utah doing more on renewables and energy efficiency, and (2) promotion of more aggressive renewable and efficiency programs in the region--and assuming that such programs will replace coal as well natural gas. (Nina Dougherty, Sierra Club) RESPONSE 44: Utah's demand for renewable energy will increase substantially in the next decade, according to expectations presented in the Technical Support Documentation. This SIP and its accompanying documentation is the most complete assembly to date of information and projections regarding energy generation for Utah consumers, and is being published by DAQ as a stand-alone document so that interested parties can better understand what is happening today and whether additional policy decisions are needed regarding future energy production. PROJECTION OF VISIBILITY IMPROVEMENT.
COMMENT 45: We suggest revisions in Part K, in the paragraph following Table 22. The paragraph indicates that visibility improvements on the best days goes beyond the national visibility goal in the Clean Air Act. On the contrary, the Clean Air Act goal is in part "the remedying of existing impairment of visibility." Mesa Verde National Park should be included in the list of Class Is where visibility on the good days is expected to improve. The title of Table 23 might more appropriately be "Projected Visibility Changes..." rather than "Projected Visibility Improvement..." because half the 16 areas shown reduced visibility by 2018. (Stephen P. Martin, Intermountain Region, National Park Service) RESPONSE 45: The 1996 numbers are not modeled information, as the table headings indicate, but rather are averages of actual monitored data for the years 1997-2001, collected from monitoring sites within or near the 16 Class I areas. For some sites, monitored data is available for the entire period; for other sites, only a single year of data was available. Because this information is not comparable with the modeled information in the column for 2018, the column of 1996 data in Tables 22 and 23 is being removed. The 1996 column of data is not comparable to modeled values for two reasons. First, the base year for Section 309 SIPs--the year from which inventories of emissions were collected for use in the modeling--was 1996, and use of 1997 -2001 monitored information contributes nothing toward an understanding of how changes in emissions affect visibility. Second, use of a single or even several years of monitored data from which to understand changes in visibility impairment is inappropriate, because of the year to year variability. Removing the 1996 column from the tables requires modifications in the accompanying text. The new text focuses on the required 309 comparisons of the modeled projections of visibility that are expected with and without the regional haze SIP. These indicate that visibility will be better on best and worst days with this SIP. WRAP is making appropriate modifications in the tables in the WRAP Technical Support Document to correct the data. ADDITIONAL CLASS I AREAS.
COMMENT 46: The proposed plan does not include a section discussing other Class I areas, but the Executive Summary states that Utah has no additional Class I areas in response to the federal requirement under 40 CFR 51.309(g). For purposes of the initial plan, no additional Class I areas must be addressed, but the plan should indicate that the 2008 update must address out-of-state Class I areas not on the Colorado Plateau that may be affected by the transport of emissions from Utah. (Stephen P. Martin, Intermountain Region, National Park Service) RESPONSE 46: 40 CFR 51.309(g) provides a mechanism to apply 309 control strategies to other Class I areas within states that submit SIPs under Section 309. Utah is the only state that is submitting a SIP under Section 309 that has no Class I areas outside the 16 Class Is on the Colorado Plateau. Other 309 States are declaring within their 309 SIPs whether they will address the additional Class I areas within their borders by implementing 309 strategies, or by following the provisions of Section 308. Utah will, of course, work with other states within the WRAP in addressing impairment in Class I areas outside Utah's borders. DAR 26896: NEW PROVO CARBON MONOXIDE MAINTENANCE PLAN.
COMMENT 47: Commentors: Rep. David Cox, Lehi, email. AB Fredericks, Woodland Hills, email. Paul Jensen, Spanish Fork, email. Nellie Motes, Provo, telephone. Mrs. Paulsen, Payson, phone. Kathy Jackson, Provo, phone. Mr and Mrs Warren Johnson, Spanish Fork, letter. Virl C Long, Provo, letter. Jay Allen, American Fork, letter. Terry Fredericks, Spanish Fork, email. J.J. Bird, Springville, letter. R. Holley, Springville, letter. The above commenters favored ending the oxygenated gasoline program, and expressed similar reasons: oxyfuel causes poor vehicle performance and reduces gas mileage; oxyfuel doesn't really help the air quality; it's unfair that other areas don't have to use oxyfuel as well as Utah County; our smog blows in from Salt Lake; it doesn't help here because so many people buy gas outside Utah County; and it's harmful to human health. RESPONSE 47: If this Plan is adopted, use of oxygenated gasoline in Utah County will end, unless carbon monoxide levels again exceed the federal health standard.
COMMENT 48: It seems to me that in order to make an educated decision, citizens need to be able to see what they are trading for approximately $5 per winter. I believe that appreciable differences in air quality are worth much more than $5/person each winter. (email, Myles Watson) RESPONSE 48: DAQ staff agrees. However, the difference is not appreciable. Carbon monoxide levels are approximately 4% lower with oxygenated gasoline, but that percentage is declining each year as more vehicles with advanced technology replace older vehicles. Projections for the future show that the federal health standard will be maintained without oxygenated gasoline for at least the next 10 years. The health standard is set at a level to protect public health. Thus, no health benefits are lost by ending use of oxygenated gasoline.
COMMENT 49: ConocoPhillips is directly impacted by the current oxygenated gasoline requirements and the proposed changes. ConocoPhillips supports the State's request that EPA approve a new attainment demonstration and maintenance plan for Provo and redesignate Provo to attainment status for carbon monoxide. Removing the wintertime oxygenate requirement will give fuel suppliers additional flexibility which we all support. (letter, H. Daniel Sinks, Fuel Issues Advisor, ConocoPhillips) RESPONSE 49: Noted.
COMMENT 50: Highland City wishes to express its support for the current action under consideration. With the proximity to Salt Lake County, it seems of dubious value to have a different kind of gas. As it appears that the air quality has improved it is time to make these changes. Our residents are excited about these changes and are encouraged that they may be coming sooner rather than later. (letter, Barry Edwards, City Administrator, Highland City) RESPONSE 50: Noted.
COMMENT 51: Mountainland AOG is pleased with the progress of the redesignation request and Maintenance Plan and we look forward to the elimination of the oxyfuel provision for the next fall/winter season starting November 2004. We would like to thank the Division for the positive cooperation demonstrated throughout the preparation of this Plan and in particular we thank Bill Colbert for his personal helpfulness and professional coordination. (Susan Hardy, Air Quality Program Manager, Mountainland Association of Governments) RESPONSE 51: Noted.
COMMENT 52: The member companies of the Utah Petroleum Association strongly support the Provo carbon monoxide plan and the deletion of the requirement for use of oxygenated gasoline in Utah County. Oxygenated fuels have served a valid purpose, but eliminating them will be a welcome relief to the petroleum industry. The inconvenience and added expense of producing and dispensing oxyfuel each winter has been a continuing concern for our industry. Our industry is proud to be a positive contributor in Utah's efforts to improve and maintain air quality. (Lee Peacock, president, Utah Petroleum Association) RESPONSE 52: Noted.
COMMENT 53: I'm also glad to see the end of the annual inspection of new cars. That too was just an added expense to the public. (email comment, Paul K. Jensen, Spanish Fork) RESPONSE 53: Noted. EPA
COMMENT 54: With respect to the revised version of Rule R307-301 "Utah and Weber Counties: Oxygenated Gasoline Program as a Contingency Measure" we are unsure of the State's intention. From EPA's perspective, this specific contingency measure rule language does not have to be adopted at this time for the maintenance plan. If the State decides to have the AQB adopt this language, this revision does not need to be submitted to EPA. (letter, Richard Long, EPA Region 8) RESPONSE 54: Agree. In fact, there is no longer a need for the rule to be federally-enforceable at all. The letter to EPA requesting redesignation also will request that R307-301 be removed from the federally-enforceable SIP. EPA
COMMENT 55: Page 2, first paragraph, third sentence under "(3) Provo Carbon Monoxide Designation History": The Federal Register citation "(67 FR 59232)" is not correct. The correct citation of the direct final rule is 67 FR 59165. RESPONSE 55: Agree. The change has been made. EPA
COMMENT 56: Page 2, second paragraph, last sentence under "(3) Provo Carbon Monoxide Designation History": The sentence states "In September 2001, the oxygenate concentration was reduced to 2.7% after MOBILE6 modeling runs demonstrated that the NAAQS could be met with the lower concentration of oxygenate." This is not correct. The oxygenate requirement was allowed to be reduced from 3.1% to 2.7% only after EPA's approval on September 20, 2002 (ref. 67 FR 59165). Please note and cite our approval. RESPONSE 56: Revise the sentence to read as follows: "In September 2001, the oxygenate concentration under State law was reduced to 2.7% after MOBILE6 modeling runs demonstrated that the NAAQS could be met with the lower concentration of oxygenate; EPA approved the revision on September 20, 2002 (67 FR 59165)." EPA
COMMENT 57: Page 3, first paragraph, second sentence which includes the phase "... and a monitoring site was established ..." We suggest adding the word "also" as follows "... and a monitoring site was also established...." RESPONSE 57: Revise as follows: "... and a monitoring site was also established ..." EPA
COMMENT 58: Page 3, third paragraph, directly under Table 1; the State needs to provide a clarification of this paragraph in that particular measures and implementation time frames should be mentioned. RESPONSE 58: The text has been modified to include implementation dates for vehicle inspection and maintenance, oxygenated gasoline and contingency measures, as well as the designation history. EPA
COMMENT 59: Page 3, second paragraph, second sentence under "(2) Monitoring Results and Attainment Demonstration": The "University Avenue No.3 site" is mentioned as also having detected an exceedance of the CO standard. However, it is not listed on page 3 in "Table 1. Monitoring Site Locations." The State needs to explain what happened to this monitoring site. RESPONSE 59: The station number and address were incorrect in the draft Plan. The text and Table 1 have been corrected. EPA
COMMENT 60: Page 5, "Table 2. 1 and 2 High 8-hour CO Concentrations (ppm) at Utah County Monitoring Stations": The footnote to this table states "* Data with more significant figures are not available." EPA disagrees; the data is in our Air Quality Subsystem (AQS). This information needs to be included in Table 2. RESPONSE 60: Agree; the change has been made. EPA
COMMENT 61: Page 5, "Figure 2. 2 High 8-hour Carbon Monoxide Concentration at the North Provo and University Avenue Monitors." Data are displayed for values up through 2001; however, data for 2002 are available and need to be displayed. Further, the State needs to provide any acceptable data that are available for 2003. This comment also applies to comment 6 above. Also, the key for the figure states "8-hour Running Average Standard is 9 PPM." The correct description is "8-hour non-overlapping average standard is 9 ppm." RESPONSE 61: Agree; the change has been made and additional data are added. EPA
COMMENT 62: Page 6, first paragraph, first sentence under "(5) Ongoing Review of Monitoring Sites"; delete "additional." RESPONSE 62: Agree; the change has been made. EPA
COMMENT 63: Page 8, "Figure 3. Provo 2000 Base-Year Episode Inventory" and "Table 4. 2000 Provo Attainment-Episode Inventory." The contribution of non-road source emissions is not identified and needs to be presented. RESPONSE 63: Agree; the change has been made. EPA
COMMENT 64: Page 10, first paragraph, first full sentence which ends with "...within the modeling domain." Insert the following statement after this sentence, "Therefore, attainment of the CO NAAQS is demonstrated for the year 2000." RESPONSE 64: (Page 12) Agree; the sentence is amended as follows: "Therefore, attainment of the carbon monoxide standard is demonstrated for the year 2000." EPA
COMMENT 65: Page 10, under "(i) Oxygenated Gasoline Program." It is stated that a 2.7% oxygen content by weight program was applicable to the year 2000. The oxygen content by weight that was required in the Provo area in calendar year 2000 was 3.1%. EPA granted relief from this 3.1% requirement, and the program was allowed to revert back to 2.7%, but not until our direct final rule of September 20, 2002 (67 FR 59165) became effective November 19, 2002. The State needs to review this issue and make any necessary corrections. RESPONSE 65: (Page 13) Agree; the sentence is amended as follows: "...addition of a minimum of 3.1% oxygen content by weight to gasoline sold in Utah County during the control period." EPA
COMMENT 66: Page 10, paragraph under "(ii) Gasoline Vehicle Emissions Inspection and Maintenance (I/M) Program," last sentence which states "EPA has verified that Utah County's I/M program is equivalent to a test-only program. For clarity, please add the Federal Register citation for this Agency approval which is 67 FR 5774 (September 12, 2002, effective November 12, 2002). RESPONSE 66: (Page 13) Agree; the change has been made. EPA
COMMENT 67: Page 11, third paragraph, last sentence under "(B) Enhanced Inspection and Maintenance Program": For clarity and accuracy, this sentence should read as "This allowed Utah County to claim 100% emissions test-only credit for its I/M program and meet the requirements of the CAA for an enhanced program, as modified by the NHSDA. RESPONSE 67: (Page 14) Agree; the sentence is amended as follows: "This allowed Utah County to claim 100% emissions test-only credit for its I/M program and to meet the federal requirements, as modified by the NHSDA, for an enhanced program." EPA
COMMENT 68: Page 11, paragraph under "(iii) Wood-burning Controls": The State should be aware that EPA never took action on the 1994 SIP revision that addressed controls for wood-burning devices. This revision was included with the 1994 SIP and was labeled as "Rule Change DAR No.15736, R307-1-4.12." EPA and the State need to discuss the status of this rule prior to the AQB's meeting in April. For the State to have a fully approved SIP for purposes of redesignation, EPA would need to be able to approve this 1994 rule revision or a replacement rule. RESPONSE 68: (Page 14) No action is needed at this time by DAQ or the AQB. Governor Leavitt submitted the wood-burning controls for carbon monoxide along with the Provo CO SIP on July 11, 1994. EPA could approve the wood-burning rules as requested in 1994. EPA
COMMENT 69: Page 11, sentence under "(d) Tri-annual Emissions Inventory": For clarity, "NEI" should be spelled out (National Emissions Inventory) and the citation for EPA's Consolidated Emissions Reporting Rule (CERR) should be included (June 10, 2002, 67 FR 39602). RESPONSE 69: (Page 14) Agree; the change has been made. EPA
COMMENT 70: Page 13, "Table 7. Requirements of a Maintenance Plan": This table is not correct and appears to contain provisions from several documents. The overall requirements for redesignation to attainment are stated in section 107(d)(3)(E) of the Clean Air Act (CAA). Primary redesignation and maintenance plan requirements are found in section 175A of the CAA and in EPA's redesignation policy memorandum, signed by John Calcagni and dated September 4, 1992, entitled "Procedures for Processing Requests to Redesignate Areas to Attainment" (hereafter referred to as the "Calcagni memorandum"). The State needs to review these documents and modify this table accordingly. Please include all five requirements from section 107(d)(3)(E) of the CAA and ensure that the State addresses all five requirements in the text that follows the table. The current text fails to address three of the requirements. RESPONSE 70: (Pages 15-17) Both Table 6 and Table 7 are revised to reflect this and the next 4 comments. EPA
COMMENT 71: Page 13, "Table 7. Requirements of a Maintenance Plan," under the heading "Requirement" for the first item entitled "Attainment Emission Inventory": The Provo area was originally designated as nonattainment on November 6, 1991 (56 FR 56694) and was classified as "moderate" with a design value greater than 12.7 ppm. Areas with this designation were required by section 187(a)(7) the Clean Air Act (CAA) to perform a dispersion modeled attainment demonstration and, therefore, do not qualify to use an "inventory approach" to demonstrate maintenance. The Calcagni memorandum states on page 9. under "b. Maintenance Demonstration": "Under the Clean Air Act, many areas are required to submit modeled attainment demonstrations to show that proposed reductions in emissions will be sufficient to attain the applicable NAAQS. For these areas, the maintenance demonstration should be based upon the same level of modeling." The discussion regarding the "inventory approach" needs to be deleted and replaced with the modeling approach requirements as this is what has been required and prepared by the State for the Provo plan. For the attainment inventory, we agree this would become a base year inventory for the modeling effort. RESPONSE 71: Agree; Tables 5 and 6 are revised. EPA
COMMENT 72: Page 13, "Table 7. Requirements of a Maintenance Plan," under the heading "Requirement" for the second item entitled "Projected Inventories": Please refer to our comment 17 above and adjust this language to reflect the requirements for a modeled maintenance demonstration. Also, the reference to "CAA: section 172(c)(3)" is not relevant to this requirement. RESPONSE 72: Agree; the tables are revised. EPA
COMMENT 73: Page 13, "Table 7. Requirements of a Maintenance Plan," under the heading "Reference" for the item entitled "Verification of Continued Maintenance"; delete the references and insert "Calcagni memorandum, CAA sections 110(a)(2)(B) and (F)." RESPONSE 73: Agree; the tables are revised. EPA
COMMENT 74: Page 13, "Table 7. Requirements of a Maintenance Plan," under the heading "Category": A periodic three-year inventory is not a requirement for a maintenance plan and this needs to be deleted. An area, however, may commit in the its maintenance plan to prepare a three-year inventory in order to fulfill the requirement for verification of continued attainment (see the Calcagni memorandum, under "d. Verification of Continued Attainment"). RESPONSE 74: (Page 17) Agree; the 3-year inventory requirement has been deleted from Table 7. The text of Subpart (6)(a) below retains the commitment as a mechanism to verify continued attainment of the standard. EPA
COMMENT 75: Page 14, "Table 7. Requirements of a Maintenance Plan," under the category "maintenance demonstration" for the heading entitled "Requirement": The statement that "Demonstration can be made by showing the that future emissions of a pollutant or its precursors will not exceed the level of the attainment inventory ..." is not correct for the Provo area. The Provo area must use the modeling approach. Please refer to our comment above. RESPONSE 75: (Page 16) Agree. The sentence in Table 7 is revised to read as follows: Provide for Maintenance of the relevant NAAQS in the area for at least 10 years after redesignation. Demonstration can be made by modeling to show that the future mix of sources and emission rates will not cause a violation of the NAAQS. EPA
COMMENT 76: Page 14, first sentence under "(a) Existing Controls"; refer to "... and enhanced vehicle...," this needs to correctly state "...a vehicle...." RESPONSE 76: (Page 17) Agree; the word "enhanced" is deleted. EPA
COMMENT 77: Page 14, second sentence under "(2) Improvement in Air Quality Due to Permanent and Enforceable Emission Reductions": This sentence begins with "Area and mobile source emission data..." So as not to preclude any sources of emissions from consideration, this sentence needs to state "Emission data must ..." RESPONSE 77: (Page 17) Agree. "Area and mobile source" is deleted, and "emission" is capitalized. EPA
COMMENT 78: Page 14, second paragraph, second sentence and third sentence under "(a) Permanent and Enforceable Emission Reductions": The reference in these two sentences to "Subpart e(4)(b)" of the State's maintenance plan appear to EPA to actually refer to Subpart e(4)(a) of the maintenance plan. The State needs to check and change this reference as necessary. RESPONSE 78: (Page 18) Agree. The change has been made. EPA
COMMENT 79: Page 15, first paragraph, last sentence; the statement appears "... so long as it is needed to demonstrate attainment of the NAAQS." This statement must be removed. Changes to the Utah County I/M program must be approved by the Utah AQB and approved by EPA as a revision to the SIP before any relaxation or elimination of the I/M control measure can be allowed. RESPONSE 79: (Page 18) Staff recognizes that any changes in Utah County's I/M program must be included in a SIP or maintenance plan revision, and that any revision must be approved by the AQB and EPA. Change the sentence as follows: "In addition, Utah County Health Department will continue to operate its vehicle inspection program." EPA
COMMENT 80: Page 17, first paragraph, first sentence the statement appears "...during the early 1990 time period." This should say "...early 1990s time period." Also, the second sentence states "However, no violations of the CO standard have occurred." To be correct, this sentence needs to state "However, no violations of the CO standard have occurred since 1993." RESPONSE 80: (Page 20) Agree. Amend the text as follows: "These periods are equal in severity and frequency to that which occurred during the early 1990s time period. However, no violations of the CO standard have occurred since 1993. EPA
COMMENT 81: Page 18, first paragraph, last sentence and throughout the document, references to "Provo": For clarity the State needs to either indicate that all references to "Provo" throughout the maintenance plan document actually refer to Provo City or wherever "Provo" is used it should be stated as Provo City. RESPONSE 81: On page 1, add a sentence at the end of the first paragraph: Provo refers to the area within the geographic boundaries of the city of Provo, the area addressed by this Plan. EPA
COMMENT 82: Page 18, "Figure 4. Provo 2000 Base-Year Inventory": This figure needs to provide the non-road emissions contribution. RESPONSE 82: (Page 22) The change has been made. EPA
COMMENT 83: Page 19, "Figure 5. Provo 2001 Base-Year Inventory" and "Table 12. 2000 and 2001 Provo Base-Year Inventories": This figure and table need to provide the non-road emissions contribution. RESPONSE 83: (Page 23) The change has been made. EPA
COMMENT 84: Page 20, the first paragraph states "The attainment emission inventory reported in Subpart (1) above documents a level of emission in Provo that is sufficient to maintain the NAAQS for carbon monoxide. Emission projections for each source category are used to determine if expected emission levels in future years will exceed the attainment emission inventory level. Maintenance of the NAAQS is demonstrated if the projected emissions remain below the attainment emission inventory level." This discussion of the method for demonstrating maintenance for the CO NAAQS for Provo is not applicable and is incorrect. The Provo area is required to demonstrate maintenance of the CO NAAQS by modeling. Areas with a prior nonattainment designation of "moderate" and with a design value greater than 12.7 ppm were required by section 187(a)(7) the Clean Air Act (CAA) to perform a dispersion modeled attainment demonstration and, therefore, do not qualify to use an "inventory approach" to demonstrate maintenance. The Calcagni memorandum states on page 9. under "b. Maintenance Demonstration": "Under the Clean Air Act, many areas are required to submit modeled attainment demonstrations to show that proposed reductions in emissions will be sufficient to attain the applicable NAAQS. For these areas, the maintenance demonstration should be based upon the same level of modeling." The discussion regarding the "inventory approach" needs to be deleted and replaced with the modeling approach requirements as this is what has been required and prepared by the State for the Provo plan. RESPONSE 84: (Pages 24-25) Agree. The entire Subpart (2) is deleted, including Tables 13-14. The inventory information that was used for the modeling is found in the Technical Support Document, and is not needed in the text of the Plan. Subsequent subparts and tables are re-numbered. EPA
COMMENT 85: Page 21, "Table 14. Carbon Monoxide Emission Inventories for the Provo Modeling Domain": Does this table reflect emissions from the modeling domain or just Provo City? The table headings need to be consistent, clear, and accurate. This table needs to provide the non-road emissions contribution. Also, there is a math error for the 2015 total emissions; the table show 52.46, but the correct number is 56.34 tons per day. RESPONSE 85: Table 14 has been moved into Subpart IX.C.6.e(3), Modeling Demonstration, and re-numbered as Table 13. Non-road emissions have been added and the math error is corrected. EPA
COMMENT 86: Page 21, first paragraph, first sentence which states "The emission inventory remains below the attainment emission inventory through the year 2015." As stated above in our comment number 30, the emission inventory approach to demonstrate maintenance of the CO standard is not applicable to Provo. RESPONSE 86: The entire Subpart (2) is deleted, including Tables 13-14. The inventory information that was used for the modeling is found in the Technical Support Document, and is not needed in the text of the Plan. Subsequent subparts and tables are re-numbered. EPA
COMMENT 87: Page 21, last paragraph, last sentence; the statement appears "...revised Utah statute 41-6-163.6 providing for biennial I/M vehicle emissions testing for vehicles six years old and newer." EPA does not have a record of receiving a revision to the SIP to address this change in the I/M program. This is necessary in order for the changes to the I/M program to be approved either prior to or with EPA's action on the redesignation and maintenance plan SIP submittal. RESPONSE 87: (Page 26) On January 16, 2004, DAQ staff mailed three separate packets to EPA Region 8. Each packet included: 1) the draft Provo Attainment Demonstration and Maintenance Plan, 2) draft revisions in the Oxygenated Gasoline rule, 3) draft revisions in SIP section X.A, the general I/M requirements for all counties; 4) draft revisions in SIP section X.D, the I/M requirements for Utah County; 5) the rules incorporating the plans; 6) the newspaper notice announcing changes in the three plans and the oxyfuel rule; and 7) forms for each item for the Division of Administrative Rules. EPA located copies after their comments were submitted, and submitted additional comments on the I/M SIPs. All 3 plans and the oxyfuel rule need to be approved by EPA. EPA
COMMENT 88: Page 22, first paragraph, first sentence; the statement appears "Since the selected intersections show no exceedance of the CO NAAQS..." This Statement is only true for the 2000 episode modeling with respect to the results displayed in Table 15 on page 22. For the 2001 episode, an exceedance of 9.2 ppm was modeled for 2001 at the 500 North University Ave. and Center Street intersection as displayed in Table 16 on page 23. Carbon Monoxide is an inert pollutant and EPA's modeling guidance indicates that attainment (or in this case maintenance) of the CO NAAQS is shown when the combined UAM-AERO and CAL3QHC values are below 9.0 ppm. Please consult with Kevin Golden of Region 8 staff, on this issue, for further information. The State needs to provide a basis to disregard this 9.2 ppm value for purposes of the maintenance demonstration. EPA suggests a couple of thoughts on this issue. First, the monitors in the Provo/Orem area showed no exceedances of the CO NAAQS in 2001. A discussion of the values, and how they were below the 9.0 ppm standard, should be provided. Second, the State should indicate that the year 2001 has passed and all future modeled projections show attainment at all the modeled intersections. The State also needs to provide an affirmative conclusion that it has demonstrated maintenance of the CO NAAQS through 2015. RESPONSE 88: (Page 26) Agree; the change has been made. EPA
COMMENT 89: Page 22, Table 15, Figure 6 and on Page 23, Table 16, Figure 7: The University Parkway State Street (Orem) intersection has modeling results displayed for only the years 2000 and 2001 and then is deleted from the data set. An explanation must be provided for why this intersection was removed. RESPONSE 89: (Page 27) The University Parkway-State Street intersection is in Orem, not Provo, and is not within the nonattainment area. That line has been removed from Tables 15 and 16 (now 13 and 14), and from Figures 6 and 7. EPA
COMMENT 90: Page 23, "Table 16. 2001 Episode and Projections: 8-hour Maximum CO Concentrations (ppm)": We note that the CO concentrations predicted for the 500 North University Ave and Center St. is not demonstrating attainment of the CO standard as the table shows a value of 9.2 ppm. For carbon monoxide attainment and maintenance demonstrations, the standard is met when modeling predicts values of less than 9.0 ppm. Please refer to the comment above. The next year that modeled concentrations are presented for is 2005. The value at the 500 North University Ave and Center St. location is shown as 8.8 ppm. The State has indicated a desire to eliminate the oxygenated gasoline program for the Provo area beginning in November, 2004. As only modeled concentrations for 2001 and 2005 are shown for this intersection (and others), EPA needs to see CO concentrations that are predicted for all six intersections for year 2004 in order to be assured the CO standard will be maintained in the year the control program may be eliminated. The State needs to discuss this issue with Kevin Golden to evaluate a method to determine CO concentrations for 2004. RESPONSE 90: (Page 27-29) See response for comment above. Modeled values for 2004 have been added. EPA
COMMENT 91: Page 24, second paragraph, first sentence concerning the statement "...so long as they are needed to demonstrate attainment of the NAAQS." This statement must be removed. Changes to the control measures, used to demonstrate maintenance of the CO NAAQS in the maintenance plan, must be approved by the Utah AQB and approved by EPA as a revision to the SIP. RESPONSE 91: (Page 31) Staff recognizes that any changes in Utah County's I/M program must be included in a SIP or maintenance plan revision, and that any revision must be approved by the AQB and EPA. The sentence is amended as follows: Provo will rely on the control programs listed below to demonstrate maintenance of the carbon monoxide standards through 2015. EPA
COMMENT 92: Page 24, third and fourth paragraphs under the heading "(b) Enforceable Control Measures": As noted in our comment number 14 above, EPA has not taken action on the 1994 SIP submittal for wood burning emissions. The State and EPA need to discuss this prior submittal. The State and EPA also need to discuss the referenced SIP revision, that involved carbon monoxide control strategies for Salt Lake City, Ogden City, and Utah County that was amended by the State in 1998. It does not appear that this revision has been approved by EPA. RESPONSE 92: (Page 31) Regarding the 1994 SIP submittal's woodburning controls, no action is needed at this time by DAQ or the AQB. Governor Leavitt submitted the woodburning controls for carbon monoxide along with the Provo CO SIP on July 11, 1994. EPA could approve the wood-burning rules as requested in 1994. Regarding the 1998 amendments to the Carbon Monoxide SIP, they were a clarification of the triggering mechanism for contingency measures for Provo, and are superceded by this Plan. The text of the item is amended as follows: "Utah State Implementation Plan, Section IX, Control Strategies for Area and Point Sources, Part C, Carbon Monoxide, Salt Lake City, Ogden City, and Utah County, as amended in 2004;" EPA
COMMENT 93: Page 24, fifth and sixth paragraphs under the heading "(b) Enforceable Control Measures": In paragraph six it is stated that Prevention of Significant Deterioration (PSD) regulations will apply in Provo. However, in paragraph five, it appears that State and Federal Nonattainment New Source Review (NSR) provisions will also apply. This needs to be clarified as it is unclear if the State intends to apply PSD to the Provo area after it is redesignated to attainment. RESPONSE 93: (Page 31) Yes, PSD will apply to Provo after redesignation. This is clarified by deleting the following bulleted item: "State and federal nonattainment NSR requirements currently in effect statewide, including R307-401 of the Utah Administrative Code, that requires Best Available Control Technology for all new sources statewide." Utah's NSR program will remain in effect in other areas of the state. EPA
COMMENT 94: Page 25, first paragraph, third sentence under "(5) Contingency Plan": This sentence may be misinterpreted. For clarification, EPA recommends the following replacement language; "The triggering of contingency measures does not automatically require a revision to the SIP or redesignation to nonattainment." RESPONSE 94: (Page 31) Agree. The text is amended to read as follows: "The triggering of contingency measures does not automatically require a revision to the SIP or redesignation to nonattainment." EPA
COMMENT 95: Page 25, under "5. Contingency Plan," "(b) If the Action Level is Exceeded": The second full paragraph under this heading says: "Immediately following the end of February and the end of the carbon monoxide season each year, DAQ will evaluate monitored data from Utah County to determine whether the NAAQS for CO has been violated." This time frame for analyzing the CO data is not appropriate. As the DAQ will be continuously monitoring the CO monitoring data, the paragraph above needs to be modified to state that DAQ will notify EPA within 30 days of an occurrence of an exceedance of the CO standard. Should a violation of the CO standard occur (two exceedances), this would then trigger the contingency measures plan sooner rather than waiting until the end of February to examine the monitoring data to determine if in fact a violation has occurred. RESPONSE 95: (Pages 31-33) Under the State-EPA Performance Partnership Agreement, the Air Monitoring Center notifies EPA within 30 days of any exceedance of any standard, and will continue to do so. However, this is raw data. Utah will not trigger implementation of contingency measures until quality-assured monitored data indicates it is necessary to do so. Under 40 CFR 58.35, the State is required to submit the quality-assured monitoring data within 90 days after the end of each calendar quarter; thus, verified data for the October through December quarter will be available by April 1, and verified data for the January through March quarter will be available by July 1. The entire section regarding contingency measures is amended to commit the State to validating data quickly if there are exceedances, and to implementing contingency measures by November 1. EPA
COMMENT 96: Page 25, under "5. Contingency Plan": Language in this section goes back and forth between the "Executive Secretary" and the "Board." The State needs to review this section and make necessary changes for consistent use of terms. RESPONSE 96: (Pages 31-33) The text is correct as written. Under Title 19, Chapter 2 of the Utah Code, the executive secretary and the AQB have different duties, and the text reflects that division of responsibilities. EPA
COMMENT 97: Page 25, paragraph under "(c) Contingency Measures": The single contingency measure listed, the re-implementation of a 2.7% oxygenated fuels program, is insufficient to meet the requirements of section 175A(d) of the CAA and the Calcagni memorandum. EPA believes that additional potential contingency measures must be identified such as; (a) returning to an annual I/M test (as is required by section 175A(d)), (b) re-implementation of a 3.1% oxygenated fuels program, (c) increase the stringency of the carbon monoxide I/M cutpoints, and (d) implementation of an employee trip reduction program. The listing of contingency measures is necessary to identify those measures which could address a violation of the CO NAAQS, but this does not mean they must all be selected and implemented upon a violation. RESPONSE 97a: (Page 33) The Clean Air Act section 175A(d) requires that the state implement all control measures that were in the state implementation plan while the area was designated as nonattainment. To meet that requirement, the following amendment is made in the text on page 25: (c) Contingency Measures. The State will implement contingency measures under this Plan if the contingency action level in Subpart e(5)(a) is exceeded. As required by Section 175A of the Act, the contingency measures to be implemented are: implementation of 2.7% oxygenated gasoline in Utah County from November 1 through the end of February, beginning with one year after it has been determined that the action level has been exceeded; and a return to annual vehicle emissions inspections. The State cannot increase the stringency of the carbon monoxide I/M cutpoints, as they are already as stringent as is allowed under 40 CFR Part 51, Subpart S and Appendix C. Utah's employer-based trip reduction program is implemented voluntarily in Utah County already, and data from other urban areas around the country indicate that such programs are very difficult to implement and that quantifying the benefit from such programs is impossible. On-Board Diagnostics (OBD-II) already is implemented in Utah County. Section XI of the Utah SIP includes other vehicle emission reduction techniques implemented by Metropolitan Planning Organizations, including 700 park and ride stalls in Utah County by 2006. Beyond that, the Act (175A(d)) says that: "Each plan revision submitted under this section shall contain such contingency provisions as the Administrator deems necessary to assure that the State will promptly correct any violations of the standard which occurs after the redesignation of the area as an attainment area. The Calcagni memorandum states (page 8, first paragraph) that: However, any final EPA determination regarding the adequacy of a maintenance plan will be made following review of the plan submittal in light of the particular circumstances facing the area proposed for redesignation and based on all relevant information available at the time." The second-highest 8-hour monitored values of carbon monoxide in Provo have been about half the NAAQS since 2001, and computer modeling for this Plan indicates that carbon monoxide emissions in Provo, as elsewhere in the United States, will drop another 30% between 2005 and 2105. In the Revised Draft 09/06/02 "National Ambient Air Monitoring Strategy," EPA includes the following suggestion for re-directing monitoring resources away from areas where objectives have been achieved: "2. Divestment Opportunities: To make more efficient use of existing monitoring resources and to help pay for (and justify additional resources for) the new monitoring initiatives noted above, it will be necessary to make certain cuts in the existing monitoring program. Two areas of potential divestment are suggested. First, many historical criteria pollutant monitoring networks have achieved their objective and demonstrate that there are no national (and, in most cases, regional) air quality problems for certain pollutants, including PM10, SO2, NO2, CO, and lead. A substantial reduction in the number of monitors for these pollutants should be considered." RESPONSE 97b: In the foreseeable future, Utah will continue to monitor for carbon monoxide, but "all relevant information available at the time" that EPA is considering approval of the maintenance plan, as directed in the Calcagni memo, indicates that the likelihood is approximately zero that contingency measures would be triggered in the next eight years before the plan is revised. EPA
COMMENT 98: Page 26, under "(6) Verification of Continued Attainment" and "(b) Analyze Ambient CO Monitoring Data": The second sentence of this paragraph states: "Any exceedance of the standard will be reported to EPA." As indicated in our comment above, a specific time frame for reporting this information to EPA needs to be included (i.e., DAQ will notify EPA within 30 days of an occurrence of an exceedance of the CO standard.) RESPONSE 98: (Page 33) Under the State-EPA Performance Partnership Agreement, the Air Monitoring Center notifies EPA within 30 days of any exceedance of any standard, and will continue to do so. However, this is raw data. Under 40 CFR 58.35, the State is required to submit quality-assured monitoring data within 90 days after the end of each calendar quarter; thus, verified data for the October through December quarter will be available by April 1, and verified data for the January through March quarter will be available by July 1. DAQ staff review the monitoring data every day, and the AQB reviews the data at every meeting. The State of Utah has in the past implemented voluntary measures to avoid violation of the NAAQS, particularly for ozone, and expects to continue to do so. The State will keep EPA informed of any exceedances. The sentence is revised is follows: Any exceedance of the standard will be reported to EPA within 30 days, and quality-assured data will be reported as required under 40 CFR Part 58. EPA
COMMENT 99: Page 26, first paragraph, second sentence under the heading "(d) Provisions for Revising the Maintenance Plan": This sentence states "The State will also revise the Plan as necessary to comply with any EPA finding..." We suggest changing this to read as "The State will also revise the Plan as necessary to comply with any State or EPA finding..." RESPONSE 99: (Page 33) Staff disagrees. A State finding does not mandate a revision in the Maintenance Plan. EPA
COMMENT 100: Page 26, first paragraph, first sentence under the heading "(f) Subsequent Maintenance Plan Revisions": Delete the portion which says "...and maintenance plan approval." The obligation for the second maintenance plan revision is triggered by the promulgation of the redesignation to attainment only. RESPONSE 100: (Page 34) Agree. The text is amended as follows: "The Clean Air Act requires that a maintenance plan revision be submitted to the EPA no later than eight years after the promulgation of the original redesignation." EPA
COMMENT 101: Page 27, under "f. Conformity": The transportation conformity description and the derivation of the CO motor vehicle emissions budgets (MVEB) is not correct. The original CO nonattainment area boundary was defined by EPA as "Provo Area, Utah County part, City of Provo" on November 6, 1991 (56 FR 56694, page 56839). EPA has not changed this boundary and the State's proposed attainment/maintenance plan references only the City of Provo. Given this boundary, the MVEBs will only apply for that area. The maintenance plan needs to make explicit that the MVEBs are for Provo City only and not the larger modeling domain. The State's description under "f. Conformity" states that mobile source figures from the projection emission inventories indicate that a budget of 70.44 tons per day of CO would apply to any analysis year between 2005 and 2014 and that a budget of 72.10 tons per day would apply to 2015 and beyond. The mobile sources emissions for Provo are found in "Table 14. Carbon Monoxide Emission Inventories for the Provo Modeling Domain" (table labeled as "Provo City (Tons per Day)). Because this is a modeled maintenance demonstration, the State cannot assume that higher emission inventory values from earlier years are consistent with maintenance. The earlier, higher emission inventory values would need to be modeled to derive any available safety margin for use in later years. Some form of an analysis (perhaps qualitative) would also be necessary to ensure the MVEBs would not interfere with maintenance in the years between the modeled years. As the State did not model emissions of 70.44 tons per day for 2008, 2011, or 2014, it cannot say with certainty that level of mobile source emissions would not cause an exceedance of the CO standard. This comment also applies to the use of 72.10 tons per day in 2015. We note that interim year budgets are not required, but are optional, with one exception. Assuming the Provo attainment/maintenance plan SIP revision will be submitted to EPA in 2004, the State would only have to provide MVEBs for two years; 2014 and 2015 and beyond. Forty CFR 93.118(b) requires selection of at least one horizon year that is 10 years or less in the future; for the State's demonstration, this would be no later than 2014. We suggest 2014 because for that budget you would then only need to model maintenance for 2014; if you selected an earlier year, you'd need to model maintenance for that earlier year as well as subsequent years before 2015, and conduct additional analyses to ensure consistency with maintenance. If the State wishes to use 70.44 tons per day as the MVEB for 2014, it must provide a demonstration that using 70.44 tons per day, instead of the modeled 52.88 tons per day, will not cause an exceedance of the CO standard. If the State wishes to use 72.10 tons per day as the MVEB for 2015 and beyond, it must provide a demonstration that using 72.10 tons per day, instead of the modeled 52.46 tons per day, will not cause an exceedance of the CO standard. We suggest contacting Kevin Golden of Region 8 for any questions regarding the modeling. RESPONSE 101: (Page 35-36) Agree; the changes have been made. DAR 26898 - 26899: AMEND THE VEHICLE INSPECTION AND MAINTENANCE PLAN FOR UTAH COUNTY AND THE GENERAL PROVISIONS. DAQ STAFF
COMMENT 102: In Part A, page 2, strike out "1990" in the title of the top Census table. (Bill Colbert) RESPONSE 102: Agree; the change has been made. EPA
COMMENT 103: General I/M, Part A: Pages 3 and 4: Delete all references to "Non-attainment." With the approval of the documents, all the areas will be maintenance. RESPONSE 103: Agree; the change has been made. EPA
COMMENT 104: Utah County, Part D: Page 3: 2nd paragraph: Federal Register Notice should be "67 FR 57744" not "67 FR 57775." RESPONSE 104: Agree; the change has been made. EPA
COMMENT 105: Page 3: 4th paragraph: Delete the word "enhanced" before "I/M." RESPONSE 105: Agree; the change has been made. EPA
COMMENT 106: Page 3, under "2. Network type," first sentence: Add phrase "as approved by EPA on September 12, 2002 (67 FR 57744). RESPONSE 106: Agree; the change has been made. EPA
COMMENT 107: Page 20, under "19. I/M SIP implementation": delete phrase "and shall continue until a maintenance plan without an I/M program is approved by EPA in accordance with Section 175 of the Clean Air Act as amended." RESPONSE 107: Staff disagrees; this statement is accurate as it is written. The I/M program will remain in effect until the AQB and EPA approve amending the maintenance plan to delete the program. DAQ STAFF
COMMENT 108: The date of Board adoption should be changed in R307-110-12, R307-110-31, R307-110-24, and on the title pages of the Carbon Monoxide Plan and the two Vehicle I/M plans. The Board has changed its meeting date from April 7, to March 31. (Jan Miller) RESPONSE 108: The date on each is changed from April 7, 2004, to March 31, 2004. These are nonsubstantive changes and can become effective at the same time the rules and plans become effective. DAR 27295: UPDATE CARBON MONOXIDE MAINTENANCE PLAN FOR SALT LAKE CITY. DAQ STAFF
COMMENT 109a: Page 1, line 34: The woodburning control program, R307-302-3, applies in Salt Lake County for PM10 but not for carbon monoxide. The reference is deleted. DAQ STAFF
COMMENT 109b: Throughout the SIP, the emissions have been re-calculated to reflect the most recent version of EPA's factors for miscellaneous non-road mobile emissions. The new factors generally predict lower emissions than the previous factors. Changes are found in Tables 1 - 3, and at page 2, line 15; page 5, lines 20 and 21; and page 7, lines 16 - 26. EPA
COMMENT 109c: Page 5, first paragraph, last sentence, states "As the projections demonstrate, this change in the I/M program does endanger attainment of the standard." Based on the information provided in this paragraph above this sentence and in table 3 of the maintenance plan, we believe the intent of this sentence is there is no endangerment for the CO standard. We recommend this sentence to be adjusted to read "...in the I/M program does not endanger continued attainment of the standard." RESPONSE 109: This correction was made at the AQB meeting on July 7, 2004, at which the Plan was proposed for public comment. EPA
COMMENT 110. Page 6, third paragraph: The requirements and EPA's policy on motor vehicle emissions budgets are found in the preamble to the November 24, 1993, transportation conformity rule (58 FR 62193-96). The criteria for the analysis to determine the conformity of transportation plans, TIPs, and projects are found in the 40 CFR 93.118. For accuracy and clarity, the above distinctions need to be clarified in this paragraph of section IX.C.7.d. RESPONSE 110: The references are changed on page 6, lines 20 - 29 to clarify this distinction. EPA
COMMENT 111: Page 7, paragraph four, last sentence which currently reads "Therefore, the MVEB for 2005 is 277.5 tons per day." This sentence is fine, however, we would just like to clarify for the State that this MVEB will actually apply to all years from 2005 to 2018 as another MVEB is not specified until 2019. This interpretation is consistent with the preamble to our November 24, 1993 rule noted above. RESPONSE 111: Agree. No change is needed. EPA
COMMENT 112: Page 7, paragraph five, last sentence which currently reads "Therefore, the MVEB for 2019 is 262.81 tons per day." As noted for comment three above, this sentence is fine; but to clarify, the State should be aware that this MVEB will apply to 2019 and beyond as another MVEB is not specified after 2019. RESPONSE 112: Agree. See response for Comment 2 above. EPA
COMMENT 113: Page 7, paragraph six: This paragraph is not accurate. Because the existing maintenance plan contains a budget for 2005, the new budget will only take effect after EPA approves the maintenance plan. The 2019 budget will take effect upon approval of the maintenance plan or upon a finding of adequacy by EPA, whichever comes first. Please note, the existing budgets for 2006 and 2016 will remain in effect until EPA approves the revision to the maintenance plan. RESPONSE 113: Agree. Because the 2005 Motor Vehicle Emissions Budget is specified in the current Plan, EPA cannot agree to changing it by making an adequacy determination. The sentence on page 7, lines 36 - 38 is amended to read as follows: "This new MVEB will take effect for future transportation conformity determinations upon approval of this Maintenance Plan by EPA." EPA
COMMENT 114: Page 7, paragraph seven: This paragraph is inaccurate and unnecessary and should be deleted. First, a state is never required to specify a budget for a year after the maintenance year. Second, under 93.102(b)(3), the conformity regulations apply to a maintenance area for 20 years from redesignation, unless the SIP says that the conformity requirements apply for longer. Thus, it appears that the State doesn't need to say anything on this subject in the maintenance plan. However, if the State wants to say anything on the subject, we recommend the following: "Pursuant to 40 CFR 93.102(b)(3) as currently written, no further conformity determinations for the Salt Lake County CO maintenance area will be necessary after March 22, 2019." RESPONSE 114: EPA sent further comments later, stating that "Our prior comment could have been more precise," and that their intent is to clarify "...to avoid future confusion and arguments." DAQ staff have modified the language pertaining to the 2019 MVEB to match the EPA revisions. EPA
COMMENT 115: Page 7, first paragraph under section IX.C.7.e: the first sentence needs to be changed to reflect the air quality monitoring commitment that was provided in the Provo carbon monoxide attainment/Maintenance plan. The Provo plan states "The State commits to continue operating the existing CO monitoring sites according to the requirements of 40 CFR part 58 and will gain EPA approval before any changes are made to the Utah County CO monitoring network." RESPONSE 115: The sentence is changed to specify that DAQ will obtain EPA approval before making changes in the monitoring network: "Utah will continue to operate an appropriate air quality monitoring network of NAMS and SLAMS monitors in accordance with 40 CFR Part 58 to verify the continued attainment of the CO NAAQS, and will gain EPA approval before making any changes to the Salt Lake City monitoring network." EPA
COMMENT 116: Page 7, first paragraph under IX.C.7.e: The second sentence states "...WFRC will request DAQ to perform a saturation monitoring study to determine whether additional and/or re-sited monitors are necessary." The WFRC is the metropolitan planning organization (MPO) that addresses transportation planning efforts affecting Salt Lake County. It is the responsibility of the DAQ to decide if the air quality monitoring network is adequate to address changes in congestion, transportation, VMT, etc. and not the WFRC. This sentence needs to be changed to reflect this division of responsibility, i.e., it should read "...change significantly over time, DAQ will perform a saturation monitoring study..." RESPONSE 116: Agree. The change is made. EPA
COMMENT 117: Page 9, first paragraph under section IX.C.7.f(3), second sentence which states: "WFRC will select the contingency measures from the following list..." As the WFRC is the MPO for the Salt Lake City and does not have the necessary regulatory authority to select and implement contingency measures, this sentence needs to be changed to reflect that the State and/or the AQB will select the necessary contingency measures. RESPONSE 117: Agree. The paragraph is re-written as follows to indicate that DAQ will consult with WFRC and Salt Lake City officials in choosing the contingency measures, and sets forth the criteria to be used in making that selection: "The State, in consultation with the WFRC and Salt Lake City officials, will choose one or more of the following contingency measures. Measures will be chosen to bring the area back into compliance quickly, and to meet the specific needs of Salt Lake City. It is likely that no federal money will be available to fund the implementation of the selected contingency measure(s). Most, if not all, of the costs will be borne by local citizens and Salt Lake City, local industries, and state government agencies." DAR 27343. UPDATE OGDEN MAINTENANCE PLAN FOR CARBON DIOXIDE. EPA
COMMENT 118: Page 1, second paragraph, 1st sentence states ...revises the 2005 on-road mobile source carbon monoxide attainment emissions inventory for 1992... This phrase is unclear. We note in the discussion of emission inventories in Section IX.C.8.b on page 2 that the 1992 attainment year inventory was revised to use the MOBILE6.2 model. Is this correct for 1992, or was the 2005 inventory actually modified as a surrogate for 1992? RESPONSE 118: Agree. Revise as follows: "...revised the on-road mobile source carbon monoxide attainment emissions inventory for 1992..."
COMMENT 119: Page 1, third bullet under IX.C.8.b. Emission Inventories and Maintenance Demonstration: this paragraph needs to be clarified as follows: "Automobile Inspection and Maintenance Program. SIP Section X, Vehicle Inspection and Maintenance Program, Part E, Weber County, adopted November 3, 2004, including the Weber-Morgan District Health Department Ordinance 2003-28, revised June 10, 2003. The program is set forth in SIP Section X.E, Weber County I/M program, last approved by EPA on July 17, 1997 (see 62 FR 38213)" RESPONSE 119: Agree; this change has been made.
COMMENT 120: Page 6, second paragraph under section IX.C.8.d Mobile Source Carbon Monoxide Emissions Budget for Transportation Conformity: The title of this section should use ...Budgets... for clarity and accuracy, the first sentence of this paragraph should be changed to read as "The federal conformity rule, at 40 CFR Part 93, subpart A, and its preamble (58 FR 62193), indicate that motor vehicle emission budgets must be established for the last year of the maintenance plan, and may be established for any other years deemed appropriate." RESPONSE 120: Agree; the change has been made.
COMMENT 121: Page 7, paragraph 6: This paragraph is not accurate. Because the existing maintenance plan contains a budget for 2005, the new budget for 2005 will only take effect after EPA approves the maintenance plan. The 2021 budget will take effect upon approval of the maintenance plan or upon a finding of adequacy by EPA, whichever comes first. Please note, the existing budgets for 2004, 2005, 2006, 2007, and 2008 and following years through 2017, will remain in effect until EPA approves the revision to the maintenance plan. Also, "These new MVEB..." should be changed to the plural as in "These new MVEBs..." RESPONSE 121: Agree. Because the 2005 Motor vehicle Emissions Budget is specified in the current Plan, EPA cannot agree to changing it by making an adequacy determination. The sentence on page 7, lines 41-43 is amended to read as follows: "These new MVEBs will take effect for future transportation conformity determinations upon approval of this Maintenance Plan by EPA or, for 2021, upon a finding of adequacy by EPA, whichever comes first."
COMMENT 122: Page 7, paragraph 7: This paragraph is inaccurate and unnecessary and should be deleted. First, a state is never required to specify a budget for a year after the maintenance year. Second, under 93.102(b)(3), the conformity regulations apply to a maintenance area for 20 years from redesignation, unless the SIP says that the conformity requirements apply for longer. Thus, it appears that the State doesn't need to say anything on this subject in the maintenance plan. However, if the State wants to say anything on the subject, we recommend the following: "Pursuant to CFR 93.102(b)(3) as currently written, no further conformity determinations for the Salt Lake County [sic] CO maintenance area will be necessary after May 8, 2021." RESPONSE 122: Agree; this change is made.
COMMENT 123: Page 8, first paragraph under section IX.C.8.e: the first sentence needs to be changed to reflect the air quality monitoring commitment that was provided in the Provo carbon monoxide attainment/maintenance plan. The Provo plan state "the State commits to continue operating the existing CO monitoring sites according to the requirements of 40 CFR part 58 and will gain EPA approval before any changes are made to the Utah County CO monitoring network." RESPONSE 123: The sentence is changed to specify that DAQ will obtain EPA approval before making changes in the monitoring network. "Utah will continue to operate an appropriate air quality monitoring network of NAMS and SLAMS monitors in accordance with 40 CFR Part 58 to verify the continued attainment of the CO NAAQS, and will gain EPA approval before making any changes to the Ogden monitoring network."
COMMENT 124: page 8, first paragraph under IX.C.9.e: The second sentence states "...WFRC will request DAQ to perform a saturation monitoring study to determine whether additional and/or re-sited monitors are necessary." The WFRC is the metropolitan planning organization (MPO) that addresses transportation planning efforts affecting Weber County. It is the responsibility of the DAQ to decide if the air quality monitoring network is adequate to address changes in congestion, transportation, VMT, etc. and not the WFRC. This sentence needs to be changed to reflect this division of responsibility; i.e., it should read "...change significantly over time, DAW will perform a saturation monitoring study." RESPONSE 124: Agree. The change is made.
COMMENT 125: Page 9, first paragraph under section IX.C.8.f(3), first sentence which states "The WFRC may choose one..." and the second sentence which states: "WFRC will select the contingency measures from the following list..." As the WFRC is the MPO for the Ogden City/Salt Lake City region and does not have the necessary regulatory authority to select and implement contingency measures, this sentence needs to be changed to reflect that the State and/or the UAQ will select the necessary contingency measures. RESPONSE 125: Agree. The paragraph is re-written to indicate that DAQ will consult with WFRC and Ogden officials in choosing the contingency measures, and sets forth the criteria to be used in making that selection: "The State, in consultation with the WFRC and Ogden City officials, will choose one or more of the following contingency measures. Measures will be chosen to bring the area back into compliance quickly, and to meet the specific needs of Ogden. It is likely that no federal money will be available to fund the implementation of the selected contingency measure(s). Most, if not all, of the costs will be borne by local citizens and Ogden City, local industries, and state government agencies."
COMMENT 126: Page 9, under "3. List of Potential Contingency Measures,' the phrase "as allowed by statute" which appears at the end of the second and third bulleted items: EPA's preference is that these phrases be removed. The State has the discretion to decide whether to pursue these particular contingency measures or not, but including this phrase calls into question whether these contingency measures can actually be implemented. RESPONSE 126: The second bullet lists as possible contingency measures: "Improving the current I/M program in the Ogden area, such as increasing the maximum repair cost limits or totally eliminating emissions test waivers for vehicles that have failed the test, as allowed by statute," DAQ agrees with EPA's comment. The relevant statute, Utah Code 41-6-163.6(2), states that "The legislative body of a county identified in Subsection (1) shall make rules regarding emission standards, test procedures, inspection stations, repair requirements and dollar limits for correction of deficiencies, and..." Thus, cost limits and emissions test waivers can be changed by county action if necessary. Regarding the third bullet, DAQ proposes to retain the language. The third bullet lists "Mandatory Employer-Based Travel Reduction programs as allowed by statute." Utah Code 19-2-104(1) states that the AQB may make rules..."(h) with the approval of the governor, implementing in air quality nonattainment areas employer-based trip reduction programs applicable to businesses having more than 100 employees at a single location and applicable to federal, state, and local governments to the extent necessary to attain and maintain ambient air quality standards consistent with the state implementation plan and federal requirements under the standards set forth in Subsection (2);..." Therefore, it is clear that there are specific limitations imposed by Utah statutes on the kind of Employer-Based Trip Reduction Program that could be implemented. It is appropriate to keep the reference to the statute in this case, in order to distinguish the kind of program that could be implemented in Utah from the model Employer-Based Trip Reduction that EPA has designed. In addition, the statute is clear that the program could not be implemented by action of the AQB alone; the approval of the Governor also must be obtained.
COMMENT 127: Page 9, under "3. List of Potential Contingency Measures: " Section 175A(d), Contingency Provisions of the CAA states, in part, "Such provisions shall include a requirement that the State will implement all measures with respect to the control of the air pollutant concerned which were contained in the State implementation plan for the area before redesignation of the area as an attainment area." Therefore, the 2.7% oxygenated gasoline program, that was approved by EPA into the SIP and applied to the Ogden City area before its redesignation to attainment, must be included on the list of potential contingency measures. RESPONSE 127: It is true that the Clean Air Act required implementation 2.7% oxygenated gasoline in the Salt Lake-Ogden metropolitan statistical Area. However, the Clean Air Act allows waivers of that requirement where implementation of oxygenated gasoline might jeopardize attainment of another health standard. In this case, there was concern that use of oxyfuel could increase nitrogen oxide emissions that contribute to formation of PM10. Utah sought such waivers for Salt Lake City and Ogden until the Maintenance Plans for those areas were approved by EPA. Oxyfuel was never implemented in Ogden, but, because its use was required by the Clean Air Act, its use was included as a contingency measure in the Ogden Maintenance plan approved by EPA on March 9, 2001. Because use of oxygenated gasoline was required for the Ogden area under the Clean Air Act, and because SIP measures must be included as contingency measures in maintenance plans, DAQ staff recommends including it as a contingency measure in the current Maintenance Plan, with the caveat that it will not be implemented that would interfere with attainment of any other National Ambient Air Quality Standard. DAR No.27429. SULFUR DIOXIDE MAINTENANCE PLAN FOR SALT LAKE COUNTY AND EASTERN TOOELE COUNTY. EPA
COMMENT 128: There are no monitors located in the Tooele County portion of the nonattainment area. Therefore, the State cannot claim that the entire nonattainment area is in fact attaining the standards. RESPONSE 128: The Tooele County portion of the nonattainment area is also the area referred to as the elevated terrain. Attainment in the high terrain was addressed in the modeling analysis relied upon in the approved attainment SIP. The maintenance plan continues to rely upon that same modeling analysis, and therefore continues to demonstrate attainment in the elevated terrain and by definition in Tooele County. In the SIP, this analysis is presented in Section IX.B.3.d. Our intention is to present the maintenance portion of the SO2 story at Section IX.B.6, as an extension of what already appears in the SIP, but it should perhaps be made more clear therein that the modeling analysis from the approved attainment SIP will continue to function as the demonstration showing that ambient concentrations of SO2 will remain within the levels prescribed by the National Ambient Air Quality Standards (NAAQS) in the elevated terrain so long as the emission limits at the smelter remain at or below those used in the analysis. To that end, we are proposing to insert new language within Section IX.B.6.c.(1) of the proposed Maintenance Plan to clarify this. We have also added language in Section IX.B.6.b.(1) to describe how attainment of the standard in the elevated terrain is determined in the absence of monitored data. EPA
COMMENT 129a: One of the monitors that had recorded violations in 1981 (Airs 49-035-2002) is no longer in service. The State would need to show that one of the current monitors is still representative of that location. The map labeled Figure 1 in the proposed maintenance plan shows the locations of all SO2 monitors, both current and historical. The monitor in question (Airs 49-035-2002) is labeled number 5 on the map. One can see that it is very close to the monitor labeled number 6. Number 5 was taken out of service after 1983 because the lake rose and flooded the site. DAQ operated the monitor at site number 6, essentially the same location as site number 5, from 1986 - 1991. At some time in 1991, the monitor was moved from location number 6 to location number 7; the marina at Great Salt Lake State Park. In 1992 the monitor was repositioned within the marina to accommodate some remodeling, but essentially locations 7 and 8 are the same. The monitor continues to operate at site number 8. All four of these site locations are collectively referred to as the "Beach" site(s), and language has been added in Section IX.B.6.b.(1) to make this clear. The (1993) Annual Network Review, used to evaluate the adequacy of the monitoring network for all criteria pollutants, says that "The background for SO2 is assumed to be zero, therefore monitoring is necessary only in areas where there are sources of SO2." Hence, each of the "Beach" monitors was situated so as to measure "impact from a significant source, a copper smelter." When the monitor was moved to the marina, DAQ submitted to EPA Region VIII an Ambient Air Monitoring Network Modification Request Form. Therein, the modification was described as "relocation of Beach site to a location of potentially higher point source impact as determined by visual observation and citizen complaints." As discussed in the 1994 Annual Network Review, "The site routinely measures short timed SO2 spikes above 0.8 ppm that last 3 to 10 minutes. This site is properly located to meet our present data needs." Further evidence of the new Beach location(s)' representativeness of the impact from the copper smelter may be seen in Figure 3 of the proposed maintenance plan. This histogram charts the history of the 2 highest 24-hr values measured there, and one can see that it captures the trend of declining concentrations coinciding with the smelter modifications that took place from 1992 through 1995. This trend is also depicted in Figure 4 of the proposed maintenance plan, which illustrates the history of Kennecott's SO2 emissions. EPA
COMMENT 129b: Section IX.B.6.b(3) is confusing, and should clearly indicate what are the current enforceable requirements for Kennecott. The 4 paragraph of this section indicates that control of low-level emissions at KUC has resulted in lower concentrations recorded at the Beach site(s). EPA would like to know if these controls have been reflected in SIP limits and/or operating practices and been approved by EPA. RESPONSE 129: Section IX.B.6.b.(3) has been re-worked to more clearly describe the sequence of events at the smelter as it applied to both air quality emission limits and SO2 concentrations at various locations. In a word, the low-level emissions were controlled once in the late 1970s and early 1980s. These controls were reflected in the Utah administrative rules for air quality (R307,) and effectively lead to the end of SO2 exceedances at the Beach site(s). Low-level emissions were controlled again during a period of smelter modernization in the early 1990s. These controls were also incorporated into the Utah SIP, and remain federally enforceable. EPA
COMMENT 130: The 2 paragraph indicates that, at one time, R307 was revised to include emission limits and control requirements for the KUC smelter main stack and smelter fugitive emissions. EPA wants to know if these requirements are still enforceable or whether they have been superceded by the PM10 SIP. They would like clarification as to the current status of such in the maintenance plan, and they would like to know where these limits actually appear. RESPONSE 130: As discussed above, this has been addressed in a re-worked Section IX.B.6.b.(3). Section IX.B.6.c.(1) has also been re-worked to clarify what is being relied upon in this maintenance plan to demonstrate continued compliance with the SO2 NAAQS. The present status of emission limits is discussed therein, and a table has been added to illustrate the succession of emission limits as they pertained to the different stages of smelter modification. EPA
COMMENT 131: The 3 paragraph references Part H of the SIP. EPA still refers to this as Appendix A to the PM10 SIP, and ask that we provide a parenthetical reference. RESPONSE 131: DAQ will add a parenthetical reference to Appendix A wherever appropriate. EPA
COMMENT 132: The 2 paragraph of Section IX.B.6.c.(1) indicates that the modeling and monitoring relationships outlined in Section IX.B.3.d. (of the SO2 attainment SIP) suggest a safety factor of roughly 100%. EPA does not understand this statement, and asks for further clarification. The last sentence of this section also indicates that "those emission limits remain federally enforceable, and are not expected to increase over the next ten years." The State must commit to continued implementation of these limits. RESPONSE 132: The modeling/monitoring relationship outlined in Section IX.B.3.d. is able to predict a concentration by evaluating a given emission rate. The emission rates so evaluated are the federally approved emission limits for the smelter, and the predicted concentrations are then compared with the SO2 NAAQS. This information has been tabulated in Section IX.B.3.d.(4), and the results show that the predicted concentrations are roughly one half of the respective NAAQS. This means that we could double KUC's emission limits and still attain the SO2 standards. In other words, the emission limits could be 100% larger and we would still attain the standards. Another way to express this is to say that there is a "safety factor of roughly 100%." The second part of this comment concerns a commitment to continue implementation of these limits. The limits are in fact already a federally enforceable part of the Utah SIP. However, to make this entirely clear, we have added language on page 13 to specify that "These conditions demonstrate maintenance through the year 2016." EPA
COMMENT 133: The maintenance plan does not contain an emissions inventory and needs to do so. RESPONSE 133: While DAQ recognizes that EPA's comment may be attributed to the Calcagni Memorandum (Sept. 4, 1992), wherein guidance is presented for processing requests to redesignate areas to attainment, we are not necessarily convinced that the inclusion of this element is vital to the approvability of the plan. The "attainment inventory" is discussed by Calcagni as one of the core provisions that should be considered by states for inclusion in a maintenance plan. The guidance anticipates that the (listed) provisions will be necessary to a generic maintenance plan, but also notes that the adequacy of any maintenance plan will be made "in light of the particular circumstances facing the area proposed for redesignation." The circumstances in this case surround an area that was designated nonattainment based on the SO2 emissions from a single source; the copper smelter at Kennecott. According to Calcagni, the stated purpose of the attainment inventory is to establish the level of emissions during the time periods associated with monitoring data showing attainment. This is particularly important in those instances where a maintenance demonstration for the area is based on the notion that the future emissions in that area would remain within the levels established by just such an inventory. In such an instance, the attainment inventory would be compared with projection inventories compiled for the 10-year duration of the maintenance plan. So long as the projected inventory was less than the attainment inventory, one could continue to assume attainment of the NAAQS. By contrast, a maintenance demonstration could instead be founded on a modeling analysis. In that case, continued attainment would be demonstrated by running an air quality model which considers factors related to meteorology, topography, and certain stack characteristics as well as the emissions of an air contaminant. After evaluating all of these factors, the model would then predict concentrations of the air contaminant that could be compared to the relevant health standard. Depending on the mix of sources to be evaluated by such a model, it may be necessary to compile an inventory that would be used by the model. As discussed above, Utah is still relying on the modeling analysis described in Section IX.B.3.d of the approved attainment SIP to demonstrate compliance with the SO2 NAAQS in the elevated terrain. In this analysis, a suite of emission limits representing each different averaging period was plugged into the modeled relationship. These are the same emission rates that would be used to generate an emissions inventory for this source. As such, this suite of emission limits constitutes a surrogate emissions inventory for the sole source of SO2 affecting the area. Hence, this surrogate inventory assumes the role for which the actual attainment inventory was intended; that is, it represents a period in time during which the standards for SO2 were being attained, and thereby identifies a level of emissions below which attainment of the NAAQS may be presumed. The same approach for demonstrating continued attainment in the low terrain has been outlined in the re-worked Section IX.B.6.c.(1). In this case, the emission limits for the sources affecting the low terrain were modeled as part of the 1981 SO2 SIP, and a relationship was established to ensure attainment of the standards so long as those emission limits were retained. When the smelter was modernized in the early 1990s, these emission limits were largely superceded by limits that were more stringent. These new limits were incorporated into the Utah SIP, and the federal enforceability of these limits is enough to ensure continued maintenance of the SO2 NAAQS. Nevertheless, a Table 4 has been added to Section IX.B.6.c.(1) in order to provide the reader with a representative emission inventory for all of the significant sources of SO2 at Kennecott affecting both low and high terrain. These inventories of actual emissions reflect the succession of smelter modifications and the associated emission limitations relied upon by the SO2 attainment SIPs of both 1981 and 1992. EPA
COMMENT 134: A maintenance plan may generally demonstrate continued compliance with the NAAQS by either a modeling analysis or by comparison with an attainment inventory. Utah's proposed plan does neither. At a minimum there should be a maintenance inventory for the portion of Tooele County above 5,600 feet and the area around the KUC smelter (below which there would be no violation of the NAAQS.) For the remainder of Salt Lake County, there should be a modeled demonstration of continued compliance. In both cases, emission estimates should reflect permanent enforceable measures and should be consistent with the various averaging periods of the respective NAAQS. Any such limits must be practically enforceable, and the State must commit to continued implementation of such. RESPONSE 134: See previous discussion for the basis of an attainment/maintenance demonstration. As noted before, DAQ will clarify in the maintenance plan that it is continuing to rely upon the modeling analyses that served as the basis for the federally approved attainment SIP. The emission limits used therein do in fact represent permanent enforceable measures, and are consistent with all three averaging periods for the SO2 NAAQS. These limits appear in the SIP at Section IX.H. and thereby establish the basis for a commitment to the continued implementation of the control measures they represent. See the discussion at item 14 concerning the remainder of Salt Lake County. EPA
COMMENT 135: The draft maintenance plan does not contain a projected maintenance year. Any such plan must demonstrate continued compliance for 10 years. Adding two years for EPA review, the maintenance year should be 12 years from the date of submittal. RESPONSE 135: DAQ understands that a maintenance plan must demonstrate continued compliance with the respective NAAQS for at least 10 years from the date of approval. Practically speaking, this requirement is protective of the emissions creep that is generally associated with an urban area. When there are many different sources that contribute to a situation of nonattainment, to which trends of projected growth or decline may be ascribed, it is necessary to evaluate the sum of their emissions (ten years) into the future in order to determine, by modeling or by inventory, whether compliance with the NAAQS is still presumed after ten or twelve years. In this case, the only SO2 emissions that are significant to the modeled demonstration of continued attainment are constrained by emission limits that are contained in a federally approved SIP. This means that there is no projected trend of growth or decline, and that therefore the presumption of continued attainment extends indefinitely into the future. Nevertheless, we have added language in Section IX.B.6.c.(1) to reaffirm that "These conditions demonstrate maintenance through 2016." (see also response to comment above) EPA
COMMENT 136: Section IX.B.6.c.(3) and Table 3 within do not accurately reflect the stated requirement of CAA Section 175A(c), which states that part D of the Act continues to apply until the area is redesignated. Evidently what we have said, that the part D provisions will remain in effect until the area is redesignated, implies that the SIP elements would no longer apply after redesignation. This would be backsliding. RESPONSE 136: It is certainly not the intention of DAQ to abandon the elements of the SO2 SIP should the area be redesignated to attainment. Both Table 3 and Section IX.B.6.c.(3) will be revised to more accurately reiterate the language contained in CAA Section 175 A.(c). (see also response to comment above) EPA
COMMENT 137: EPA is uncomfortable with the notion of pre-implemented contingency measures for a couple of reasons. First, Section IX.B.6.c.(1) implies earlier that credit for these "other" sources in the PM10 SIP is being taken as part of the maintenance plan. Second, if there was a violation of the NAAQS the State would not be able to rely on these pre-implemented measures to address the violation. RESPONSE 137: Although pre-implemented contingency measures are not unprecedented, DAQ understands EPA's concerns surrounding the contingency measure element of the proposed maintenance plan. Due in large part to the confidence we have that these measures will not be needed, we can agree to re-structure Section IX.B.6.c.(4) such that pre-implementation will no longer be an issue. See discussion below. EPA
COMMENT 138: The plan must identify a list of potential contingency measures which includes, at a minimum, further controls on stationary sources. They provide some language from another maintenance plan that we could use. Also, the schedule for corrective action is too short. They suggest an implementation deadline of one year from the date of violation. RESPONSE 138: Given the flexibility exhibited in the language suggested by EPA, DAQ can agree to re-structure the contingency provisions to include some potential measures as well as a more definite schedule for ultimate implementation. See Section IX.B.6.c.(4) for proposed language. EPA
COMMENT 139: The State must assure that it is ready to implement PSD in the area once it is redesignated. RESPONSE 139: DAQ is well aware of the changes that will result to the permitting program should the area be redesignated to attainment. Utah is a "SIP approved" state with respect to the PSD program, meaning that our rules reflect, to a large degree, the construct of the federal PSD rules (at CFR 51.166.) The way in which Utah's rules are structured will allow for immediate implementation of the PSD program in any nonattainment area once it becomes redesignated to attainment. As a separate project, DAQ is planning to amend the state PSD permitting rules to adopt the NSR reform provisions, as required by the federal rule, by the beginning of 2006. EPA
COMMENT 140: To the extent that control measures must remain in effect and federally enforceable, the SIP still contains variance provisions and certain Director's Discretion that serve to undermine this requirement. RESPONSE 140: As EPA is well aware, these issues are presently being addressed within the context of the forthcoming PM10 maintenance plan. Nevertheless, we do wish to point out that these same provisions existed within the state air program at the time that EPA approved the SO2 attainment SIP. Despite the discomfort EPA has with these provisions, Utah has continued to attain and maintain the federal health standards for SO2. EPA
COMMENT 141: The State has modeled the emissions from the refineries, and thereby predicted violations of the NAAQS. RESPONSE 141: This statement is not correct. DAQ has conducted a refined modeling analysis that shows compliance with the SO2 NAAQS. Nevertheless, we understand EPA's concerns, and look forward to sharing this information with the Region. EPA
COMMENT 142: EPA was under the impression that the maintenance plan would include a modeling demonstration for the five refineries and would include emission limits for such. Such an analysis needs to be included in the plan before EPA can re-designate the area to attainment. Additionally, any modeling assumptions would need to be periodically reevaluated, along with the rest of the plan, as per the requirement for verification of continued attainment. RESPONSE 142: As we have said all along, the nonattainment situation within Salt Lake County and the eastern portion of Tooele County above 5,600 feet was due to entirely to the emissions from the copper smelter at Kennecott. The federally approved attainment SIP addresses only the Kennecott smelter, and so too should the maintenance plan. The refineries are located sufficiently far away from Kennecott, such that the emissions from these sources are distinct and do not act in an additive way. The refineries have been addressed in a supplemental analysis to see if they could create a separate incidence of SO2 nonattainment, and the result of the analysis is that they do not cause a violation of any SO2 standard in Salt Lake County or Davis County; either as separate facilities or as a group. DAQ continues to believe that this information is more appropriately structured as supplemental to a separate maintenance plan, as it does not demonstrate a potential violation of the SO2 standards. Furthermore, each of the refineries is presently required to comply with federally enforceable SO2 limits in the Utah SIP, and based on these limits we have one modeling analysis that shows compliance with the PM10 NAAQS and another analysis that shows compliance with the SO2 NAAQS. DAQ does not see the value in replicating these emission limits in another portion of the Utah SIP when it is not necessary to ensure the continued protection of the public with respect to either of these health standards. As indicated before, DAQ looks forward to making this analysis available to EPA with the understanding that it is not intended to become part of the SO2 SIP. EPA
COMMENT 143: In one additional comment from EPA, based on discussions that occurred after the close of the comment period, it was suggested that the maintenance plan would need to address banked emissions. RESPONSE 143: While recognizing that the issue of emissions banking is a point of ongoing debate between the DAQ and the EPA, we have inserted some language into Section IX.B.6.c.(1) which essentially states that the emission levels identified therein, which are incorporated into the Utah SIP at Section IX. Part H (formerly Appendix A to Section IX. Part A) should serve as a baseline for emission rates relied upon by the 1992 SO2 attainment SIP as well as this maintenance plan. Thus, emission reduction credits would be allowed to the extent that they are established by actual, verifiable, and enforceable reductions in SO2 emissions below these levels. DAR 27768 - 27769. PM10 Maintenance Plans for Salt Lake County, Utah County, and Ogden City, and Emission limits for Salt Lake County and Utah County. GENERAL COMMENTS.
COMMENT 144: Under EPA's interpretation of the Clean Air Act, the Natural Events Action Plan for Salt Lake County must be adopted as a SIP revision and submitted to EPA for approval as part of the maintenance plan. {Comment made by the EPA; A1} RESPONSE 144: The State submitted a Natural Events Action Plan (NEAP) to EPA for review. We have received comments on the plan from EPA, and we are currently reviewing those comments and working with EPA staff to prepare proposed responses to each. It is our intent to have the NEAP finalized prior to EPA's approval of the PM10 Maintenance Plan.
COMMENT 145. EPA requests that the State withdraw the February 6, 1996 State Implementation Plan revisions to R307-2-10, Section IX.A.6.f of the SIP, Diesel Inspection and Maintenance (I/M) Program, and Section XXI, Diesel Inspection and Maintenance Program, of the 1996 SIP revision. {Comment made by the EPA; A2} RESPONSE 145: The original PM10 SIP included credit for a diesel I/M program that was phased in by Davis, Salt Lake and Utah counties, beginning in 1994. The program was fully implemented by Section XXI, Diesel Inspection and Maintenance Program, which was submitted to EPA in February 1996. EPA has failed to approve that SIP. DAQ has submitted four separate requests to EPA seeking credit for the Diesel I/M program. We still believe that our justification for credit has been more than adequate, and we again urge EPA to approve the Diesel I/M SIP. Deleting the Diesel I/M SIP would require a separate rulemaking, including a public hearing, because it is incorporated by R307-110-29, and no changes have yet been proposed in that rule. B. SECTION IX.A.10 - PM10 MAINTENANCE PLAN: DOCUMENT ORGANIZATION:
COMMENT 146: DAQ has combined 3 different nonattainment areas into one maintenance plan. Generally, EPA cannot partially act on a maintenance plan. DAQ may want to consider reorganizing the document so that there is a separate maintenance plan and demonstration for each area. {Comment made by the EPA; A3} RESPONSE 146: DAQ will reorganize both Part A and Part H such that the Utah AQB may propose a separate maintenance plan for each of the three areas. There are certain administrative differences in the circumstances surrounding each of these areas, and this should allow EPA more latitude to address these specific concerns. DAQ will also prepare an intermediate copy of both Part A and Part H in order to more clearly show the reader how it addressed each of the comments summarized herein.
COMMENT 147: Does DAQ intend to retain in the federally approved SIP all of sections IX.A.1 through IX.A.9 (currently Section 9, Part A, 1-9 of the federally approved SIP) in addition to incorporating the maintenance plan into section IX.A.10? {Comment made by the EPA; B1} RESPONSE 147: As noted on page 1 of the proposed Maintenance Plan (lines 28-30), the provisions of Section IX.A.1-9 are retained for informational and historic purposes, but are superceded by the new section IX.A.10. DAQ agrees however that this should be made clear to the reader of sections 1-9, and will therefore propose to clarify this in the table of contents and on the title page at the beginning of Section IX.A. This will not constitute a rulemaking action. In addition, the language on page 1 will be clarified to read as follows: "While the Maintenance Plan could be written to replace all that had come before, it is presented herein as an addendum to Subsections 1-9 in the interest of providing the reader with some sense of historical perspective. Subsections 1-9 are retained for historical purposes, while existing subsection 10 (transportation conformity for Utah County) is herein replaced with a more current evaluation of transportation conformity."
COMMENT 148: (EPA B2) Section IX.A.10 was approved into Utah's SIP when EPA approved revisions to the Utah County PM10 SIP, effective January 22, 2003 (67 FR 78181). The existing section is titled Transportation Conformity and consists of language specific to Utah County's PM10 conformity budgets. Does DAQ intend for the PM10 Maintenance Plan to supersede and replace the existing SIP section? If so, this should be stated. {Comment made by the EPA} RESPONSE 148: Yes. This was probably an oversight in the numbering of the proposal, but in retrospect it will achieve the desired outcome of retaining, for historical purposes, subsections 1-9 while superceding subsection 10, transportation conformity for Utah County. As proposed, subsection IX.A.10.c(6) is to be the transportation conformity section for Salt Lake and Utah Counties and Ogden City, and will supercede the previously approved (67 FR 78181) Utah County PM10 section IXA.10 and its MVEBs with a new Transportation Conformity budget defined for 2017 and beyond. The language proposed in the first paragraph of Subsection IX.A.10.c(6)(c) already indicates that the Utah County conformity budgets for 2010 and 2020 that were previously approved by EPA are considered withdrawn. However, DAQ will re-word that sentence as follows to provide additional clarity: "Upon the approval of this Maintenance Plan by EPA, the previously approved Subsection IX.A.10, including Utah County Mobile Source budgets for years 2010 and 2020 will be considered repealed and these new MVEB will take effect for future conformity determinations for 2017 and beyond." The Metropolitan Planning Organization (MPO) for Utah County, Mountainland Association of Governments, supports this approach. MONITORED AIR QUALITY DATA:
COMMENT 149: On page 7, Section IX.A.10.b(1)(a), DAQ states that expected exceedances are calculated from the (AIRS) data base and that "any data which had been flagged as inappropriate for use in making such determinations, whether concurred with by EPA or not, was not considered here." For two exceedances at Magna in 2001 (causing a NAAQS violation) and exceedances at Ogden 2 on July 4, 2002 and July 4, 2003, EPA Region 8 has informed Utah DEQ that no exceptional or natural event flag is applicable or appropriate for these exceedances, and that they may not be excluded from regulatory calculations. These exceedances should be included in the Tables IX.A.30 and IX.A.32 and in the text discussing the exceedance history of Salt Lake County and Ogden City monitors. Similarly, these should be factored into the expected exceedances shown in Tables IX.A.33 and IX.A.35 (on pages 14 and 22 respectively). {Comment made by the EPA; B5, includes EPA comments B13 and B14} RESPONSE 149: DAQ still believes it appropriate to consider only the data which has not been flagged for the purposes of evaluating: 1) whether an area is attaining the NAAQS and 2) determining that the improvement in air quality is due to permanent and enforceable reductions in emissions. These discussions are both prerequisites to redesignation under section 107d of the Clean Air Act. The reason for this is that data is flagged when circumstances indicate that it would represent an outlier in the data set and not be indicative of the entire airshed or the efforts to reasonably mitigate air pollution within. This is anticipated in Appendix N to Part 50 - "Interpretation of the National Ambient Air Quality Standards for Particulate Matter" which says: "Data resulting from uncontrollable or natural events, for example structural fires or high winds, may require special consideration. In some cases, it may be appropriate to exclude these data because they could result in inappropriate values to compare with the levels of the PM standards." Nevertheless, DAQ received a number of comments on this issue, and will modify the proposed maintenance plan (at sections IX.A.10.b(1) and 10.b.(3)) to more fully explain this. As revised, the plan will also include a discussion of what the data points were that were flagged, and how this would affect the discussions in the plan should EPA eventually conclude that it would not concur with the flags attached by DAQ. EPA has in fact "not concurred" with the two exceedances measured in Ogden on the 4 of July. By contrast, it has only indicated to DAQ that it intends not to concur with the two exceedances measured at Magna in 2001. Accordingly, Tables IX.A.30 - 35 have been revised to include both sets of data involving the number of expected exceedances predicted for each monitoring station. Discussion is provided for each of the flagged exceedances. The data is also discussed in the context of the annual arithmetic mean concentrations presented in Figures IX.A.28 - 31, Figures IX.A.35 - 37, and IX.A.39.
COMMENT 150: In order to provide full disclosure, the maintenance plan should include all of the PM10 monitoring data measuring high concentrations for all three nonattainment areas. This would include all exceedances with flagged or otherwise excluded data. The proposed plan does not provide the public with a clear history of PM10 concentrations. Specifically, the plan should explain the violation of the 24-hour PM10 standard in 2001 at the Magna station, which occurred while Kennecott had violated its permit and SIP condition requiring that the tailings pond be covered in water at all times. The State issued an NOV and was supposed to fine Kennecott, but we do not believe this action was taken. Salt Lake County could have been bumped up to a "serious" nonattainment area designation, and the maintenance plan needs to make a full disclosure of this information. In addition, there were 8 other exceedances in the 2002-2004 period, for which DAQ has submitted a Natural Events Action Plan, but EPA has not yet accepted that Plan or the flags on those exceedances to label them exceptional or natural events. Until they do, we have serious doubts as to why Salt Lake County would qualify for a redesignation to attainment. The official public record must accurately reflect the status of PM10 data in these nonattainment areas. {Comment made by Environmental Defense and Utah Chapter of the Sierra Club} RESPONSE 150: As discussed in the response to comment 6 DAQ will modify the proposed maintenance plan (at sections IX.A.10.b(1) and 10.b.(3)) to more fully explain the data that was flagged, why it was flagged, and how this would affect the discussions in the plan should EPA eventually conclude that it would not concur with the flags attached by DAQ. As pointed out in the revised plan, almost all of these events have been included in the proposed Natural Events Action Plan (NEAP) as typifying the circumstances under which it would be appropriate to attach a flag to the monitoring data. DAQ expects that the EPA will concur with these flags when it approves the NEAP. Such concurrence would indicate that, despite regional control measures and mitigative action to address fugitive dust, the wind-speeds were such that it would be unreasonable to expect that high concentrations of blowing dust could have been prevented. Concerning the enforcement action taken against Kennecott: DAQ required Kennecott to update and submit a comprehensive fugitive dust control that would address the dust problems on April 20, 21, 22, 27, 28, May 2 and 3, 2001. Kennecott's June 7, 1994 fugitive dust plan was deemed inadequate, and the new plan specifically required Kennecott to address the issue of poor trafficability (access) to, and control of all the cells of the tailings impoundment. The NOV was issued on August 10, 2001. Kennecott responded by: updating the old fugitive dust control plan, constructing additional access roads in the reclaim areas, continuing to re-seed the reclaimed cells, and installing additional water irrigation systems to the dry areas. The penalty was lumped into one settlement agreement of $113,340 along with four other violations. $95,940 was paid in cash and $17,400 was credited to an SEP (green tag power). The tailings penalty by itself was $70,000.00, and the final agreement date was 1/6/2003.
COMMENT 151: On page 8, Section IX.A.10.b(1)(a), DAQ states that "the Salt Lake County PM10 nonattainment area has not exceeded the 24-hour standard since 1992." DAQ should revise the language to reflect that the Salt Lake County area had a violation at Magna in 2001 and had 8 measured exceedances in 2002-2004 that DAQ has flagged as natural events. {Comment made by the EPA; B6} RESPONSE 151: DAQ agrees that the language on page 8, Section IX.A.10.b(1)(a), is in error. As revised, the language will read as follows: "Additional information presented in Subsection IX.A10.b(3) shows that the Salt Lake County PM10 nonattainment area has not violated the 24-hour standard since 1992 nor has it exceeded the annual standard since 1993. It actually attained both standards as of December 31, 1995, and has remained in compliance with the PM10 NAAQS through 2004." As discussed in the response to comment 6, DAQ will modify the proposed maintenance plan (at sections IX.A.10.b(1) and 10.b.(3)) to more fully explain the data that was flagged. See the response to comment 33 for an explanation of the language regarding the annual standard.
COMMENT 152: On page 9, Section IX.A.10.b(1)(a), DAQ states that "the Utah County PM10 nonattainment area has not exceeded the 24-hour standard since 1993." DAQ should revise the language to reflect that the Utah County area has had 2 measured exceedances from 2002-2004 that DAQ has flagged as natural events. {Comment made by the EPA; B7} RESPONSE 152: As discussed in the response to comment 6, DAQ will modify the proposed maintenance plan (at sections IX.A.10.b(1) and 10.b.(3)) to more fully explain the data that was flagged.
COMMENT 153: On page 9, Section IX.A.10.b(1)(a), DAQ states that "the Ogden City PM10 nonattainment area has not exceeded the 24-hour standard since 1993." DAQ should revise the language to reflect that the Ogden City area has had 1 measured exceedances that DAQ flagged as a natural event and 2 measured exceedances that DAQ flagged as exceptional events, with which EPA has not concurred. {Comment made by the EPA; B8} RESPONSE 153: As discussed in the response to comment 6, DAQ will modify the proposed maintenance plan (at sections IX.A.10.b(1) and 10.b.(3)) to more fully explain the data that was flagged.
COMMENT 154: In Part A, Figures 38 and 39 do not include the monitored data for 2001 - 2004, which included exceedances on July 4, 2003 and 2004, presumably from fireworks at a park near the monitor. Apparently, these data were flagged in a category called "infrequent large gatherings," but EPA has not accepted the flag. Holiday fireworks are regular events and not truly infrequent; the public should be warned that the fireworks are not harmless, and the monitored data should be included in this Plan. {Comment made by Wasatch Clean Air Coalition} RESPONSE 154: The data monitored in Ogden City on the 4 of July (in both 2002 and 2003) is discussed in the revised plan at sections IX.A.10.b(1) and 10.b.(3). Therein, DAQ explains that it does not consider this data to be representative of the entire Ogden area, and that perhaps EPA would have concurred with the flags had there been an existing category (of reasons for such concurrence) that was more appropriate to the actual nature of the events. Nevertheless, DAQ agrees that the fireworks, in the parking lot where the monitor is located, elevated the particulate concentrations to levels that are considered unhealthy. Since these occurrences, DAQ has worked with local fire officials to assure that all fireworks in the area are legal and are being used in a manner that will not adversely impact the community. MOBILE VEHICLE EMISSION BUDGETS:
COMMENT 155: (EPA B30; includes EPA comments B31 and F3) On page 38, section IX.A.10.c(6), says that the road dust inventory was discounted by 75% for purposes of demonstrating maintenance, but that it was not discounted for purposes of establishing motor vehicle emissions budgets (MVEBs). Even if this is appropriate, it is not acceptable to use one method to demonstrate maintenance and another to set budgets. Budgets must reflect inventory values used in demonstrating maintenance. {Comment made by the EPA} RESPONSE 155: The EPA-approved PART5 model provides an approved estimate of road dust emissions. However, particulate precipitation near the road results in only an estimated 25% of road dust reaching the air quality monitors. The justification and citations for the 75% performance adjustment to the air dispersion model are provided in the response to Comment 104. Without the 75% reduction, the air dispersion model would significantly over-predict the primary PM component throughout the modeling domain. Consequently, the projected Mobile Source inventories and budgets appropriately reflect the actual outputs of the PART5 EPA-approved model and were not discounted to support the projected concentrations at the monitoring stations derived from the air dispersion model. This direction is consistent with existing and forthcoming EPA mobile source models.
COMMENT 156: Mobile Source PM10 Emissions Budgets: Utah County currently has an approved 2003 budget. The 2003 budget will remain in place and must be used in any conformity analysis required for years prior to 2017 unless the state establishes a new revised budget for 2003. Alternatively, Utah could leave the current 2003 budget and establish a 2005 budget. This also pertains to Salt Lake County. There are currently approved budgets for Salt Lake County for 2003 that would apply to years prior to 2015. {Comment made by the EPA; B33; includes EPA comments B34} RESPONSE 156: Anticipating final EPA approval of this plan in 2007, the only budget year required for Transportation Conformity in Utah County is for 2017 and beyond. The response to Comment 5 includes rewording of a sentence in Section IX.A.10.c(6)(c) repealing the Utah County mobile source budgets for 2010 and 2020. The Transportation Conformity Budget years established for Salt Lake County and Ogden City are for 2015 and 2017 and beyond anticipating a positive adequacy determination for transportation conformity purposes in 2005 and a final SIP approval in 2007. The WFRC MPO approve this strategy. The existing approved budget for 2003 will not be a transportation planning issue subsequent to the EPA approval of this plan.
COMMENT 157: (EPA B36) In establishing the MVEB for each area, Utah has used a rounding convention (rounding up) that is not consistent with the attainment/maintenance demonstration. This is not appropriate. RESPONSE 157: When the plan was released for public comment, the MVEB projections for the Alternative 2 MVEBs were rounded up to the nearest whole number. Alternative 2 is no longer included in the plan. The Alternative 1 MVEBs were not rounded up and include the safety margins requested by the MPOs. However, to resolve any confusion over rounding errors, the MVEBs for each area now include two significant digits to the right of the decimal place.
COMMENT 158: The estimated motor vehicles emissions for each of the three areas in this SIP are the same for both 2015 and 2017. An explanation for why the emissions estimates and associated factors used to calculate the emissions are the same for different years in a rapidly growing metropolitan area must be included. {Comment made by the EPA; B37} RESPONSE 158: The 2015 budget was provided in anticipation of a positive mobile adequacy determination for transportation conformity purposes for Salt Lake County and Ogden City later this year (2005). The 2017 and beyond budget is established to provide a ten-year maintenance demonstration in anticipation of a final SIP approval in 2007. The motor vehicle emissions budgets provided for 2015 and 2017 and beyond do not jeopardize the validity of the attainment demonstration and meet transportation conformity requirements through 2030.
COMMENT 159: The public should have the opportunity to comment on the final proposed emission budgets before they are submitted to EPA; the present proposal includes alternatives but it is difficult to tell what the final budgets will be. The budgets that are proposed for 2015 and 2017 should apply in later years as well. The safety margin should remain with the AQB; it is unlikely that there will be a safety margin in the future and transportation planners should not count on having a higher emissions budget in the future. {Comment made by Environmental Defense and Utah Chapter, Sierra Club} RESPONSE 159: The AQB requested comments on two proposals for each pollutant for each geographic area; the AQB will choose from those alternatives. Thus, the final budgets have been available for public comment. By rule, the last year for which mobile source budgets are identified in the plan apply to all future years, so whatever budgets are adopted for 2015 and 2017 will continue to apply in subsequent years. SAFETY MARGIN:
COMMENT 160: (EPA B32) On pages 38 - 40 of Section IX.A.10.c(6) Mobile Source Budget for Purposes of Conformity for Salt Lake County, text discusses a "safety margin." The safety margin must be expressed in terms of emissions and not ambient concentration. A safety margin expressed in emissions level might correlate to an amount of pollutant concentration but the state must explain what safety margin it is utilizing in terms of emissions such as tons per day. For example, for Salt Lake County, the State could indicate that the modeling, using 52 tons per day of PM10 and 35 tons per day of NOx mobile source emissions, demonstrates maintenance at 148.5 g/cubic meter. The State could then state that this shows the safety margin is at least 3.14 tons per day of PM10 (52 tons per day minus 48.86 tons per day) and 0.04 tons per day of NOx (35 tons per day minus 34.96 tons per day), and indicate that it is allocating this portion of the safety margin to the mobile source budgets. This same comment applies to the budget discussion for Utah County and Ogden City. {Comment made by the EPA} RESPONSE 160: The discussion of the safety margin in this plan is consistent with the discussion provided in the "Mobile Source Technical Support Document for the Utah County PM10 SIP Revision," dated June 2002 and approved by EPA effective January 22, 2003 (67 FR 78181). CFR 40 Part 93.101 states "Safety margin means the amount by which the total projected emissions from all sources of a given pollutant are less than the total emissions that would satisfy the applicable requirement for reasonable further progress, attainment or maintenance." The MVEB provided for Purposes of Conformity for each area in the plan clearly demonstrates the requested allocation of a portion of the safety margin for the three areas will not exceed the NAAQS for each pollutant throughout the modeling domain. Since the plan uses a dispersion model, expressing the allocation of a portion of the safety margin in concentration is reasonable. Table XX identifies the allocation of each portion of the safety margin in tons/day for PM10 and NOx for each area. However, to provide even greater clarity, DAQ has added the language suggested by EPA to Section IX.A.10.c(6) to show how the safety margin would be expressed in terms of emissions. The calculation was made for each of the three conformity budgets.
COMMENT 161: (EPA B38) It appears that no inspection and maintenance (I/M) credit was taken in the mobile source modeling for the projected years. Please include a discussion regarding why this decision was made, a justification behind this decision, and a rationale concluding this decision is appropriate. Please include impacts of modeling a "no I/M" scenario in future years on safety margin and mobile source transportation conformity budgets. {Comment made by the EPA} RESPONSE 161: The Metropolitan Planning Organizations (Mountainland Association of Governments and Wasatch Front Regional Council) calculated the on-road mobile source emissions for the urbanized areas in the UAM-AERO modeling analysis. The following discussion provides the rationale the MPOs provided for not including the benefits of an I/M program in these calculations: Emissions were calculated with the assumption that the vehicle emissions Inspection and Maintenance (I/M) program implementation may change in the future. This assumption is based on recent state legislation in Utah that has reduced I/M coverage for certain vehicles and model years. Further, as EPA MOBILE models continue to evolve, the emissions credit obtained from I/M programs has significantly decreased, reflecting the benefits derived from advancing vehicle technology and cleaner fuels. The assumption is conservative since most vehicles in the modeling domain fall under the jurisdiction of an I/M program. Therefore, actual vehicle emissions are expected to be lower than projected in the SIP without any I/M controls. The benefits of an I/M program will effectively provide an additional safety margin that should accommodate unanticipated program or demographic changes within the domain. For now, the vehicle emissions inspection is a required part of vehicle registration for most vehicles and will be included in the conformity analysis. I/M programs are currently mandated under the Carbon Monoxide and Ozone SIPs.
COMMENT 162: (EPA B40) On page 43, lines 32 - 35: DAQ needs to add language indicating that these values represent the sum of the additions to the motor vehicle emissions inventories for all three areas. It is not clear from the existing text. {Comment made by the EPA} RESPONSE 162: DAQ agrees, and will clarify the language as follows: "Using the procedure described above, some of the safety margin indicated earlier in Subsection IX.A.10.c.(6) has been allocated to the mobile vehicle emissions budgets. The results of this modification are presented below. Inventory: The emissions inventory was adjusted by adding the following sums to the on road mobile source emissions totals for the entire modeling domain: in 2015: 4.04 ton/day PM10 and 0.19 ton/day NOx; in 2017: 5.41 ton/day PM10 and 2.49 ton/day NOx. " Note also the revision to the reference in the preceding paragraph, and see response to comment 53 for explanation.
COMMENT 163: The SIP shows expected concentrations in 2017 and sets motor vehicle emission budgets (MVEB) for 2017. EPA is concerned that when a conformity analysis is performed for the transportation plan for the year 2030 that the estimated motor vehicle emissions will exceed the MVEB, since little or no safety margin is used or available to establish budgets. {Comment made by the EPA; B35} RESPONSE 163: The MPOs have reviewed the mobile source emission budgets in the plan for 2017 and believe these budgets are adequate for future conformity determinations for years through 2030 and possibly later years barring unforeseen changes in emission modeling practices as presently constituted.
COMMENT 164: We do not believe there will be any safety margin in the future, and mobile sources should not count on having a higher emissions budget in the future. Any supposed safety margin should remain with the AQB. {Comment made by Sierra Club, Utah Chapter} RESPONSE 164: The evaluation of a safety margin is documented in the plan. The magnitude of the safety margin is based on the best available emission projections and airshed modeling. Allocation of a portion of the safety margin to Mobile Sources is within the discretion of the Utah AQB, and DAQ staff will recommend that the Board advance the Maintenance Plan including Alternative 1 as the final set of mobile vehicle emission budgets.
COMMENT 165: UDOT supports the "Alternative 1" analysis method, which sets the direct PM10 and NOx mobile vehicle emission budget for 2025 and 2017 in Salt Lake County, Ogden City and Utah County. UDOT understands that the new budgets for Salt Lake County and Ogden City can be used for conformity as soon as the EPA conducts its adequacy review and publishes a positive finding in the Federal Register; for Utah County, the previously approved Utah County Mobile Source budgets for 2010 and 2020 remain in place until EPA approves the Maintenance Plan. {Comment made by the Utah Department of Transportation} RESPONSE 165: See response to Comment 164.
COMMENT 166: We recommend that the AQB adopt Alternative 1 mobile source emissions budgets for Salt Lake County and Ogden City. WFRC is committed to manage mobile source emissions at a level below the emissions budget proposed. {Comment made by the Wasatch Front Regional Council} RESPONSE 166: See response to Comment 164.
COMMENT 167: We request that the AQB approve the Utah County mobile source emission budget of 21 tpd of NOx and 25 tpd of direct PM10 for the year 2017 and beyond. This will allow a small safety margin that will allow us to maintain continuous conformity with low levels of PM10 throughout the life of the Plan. Utah County's population is expected to more than double in the next 30 years; a robust transportation system is required for the transport of goods, worker commutes, tourism and access to all aspects of a healthy society. The safety margin we request can be compared with the margin that stationary source industries have in being permitted for allowable emissions, instead of actual emissions; Table 37 in the Plan shows the difference between allowable and actual emissions. {Comment made by the Mountainland Association of Governments} RESPONSE 167: See response to Comment 164.
COMMENT 168: While the public notice indicates that the Board requests comment on whether or not to allocate part of the safety margin to the motor vehicle emissions budget, the language of Plan (IX.A.10.c(6) indicates that, should the modeling results show that the area would still be maintaining the PM10 standard using the expanded MVEB, Alternative 1 [that is, allocation of the safety margin to the MVEB] would be included. We believe the Board should retain discretion over any safety margin that might be realized rather than committing it irrevocably to the MVEB or any other particular emissions budget. It is impossible to determine today what will be the best use of any such safety margin for 10 or more years into the future. {Comment made by UIENC and endorsed by Kennecott} RESPONSE 168: See response to Comment 164. EMISSION REDUCTION CREDITS:
COMMENT 169: On page 37, section IX.A.10.c(4), "Emission Reduction Credits": The intent and meaning of this section is unclear. The text should define Emission Reduction Credits and describe how they were included in the modeling. Also, the second sentence of the text may not be consistent with proper principles for banking emissions. What is the significance of establishing a "baseline for the emission rates relied on" by the maintenance plan? What is the intent of the third sentence? What emission reduction credits is it referring to, and for what purpose are they allowed? Finally, we question whether this statement is adequate to ensure that relevant criteria are met for use of banked emissions for offsets or other purposes. We require that banked emissions be surplus (can't be required to meet another requirement), permanent, and quantifiable. We would expect any valid provision regarding banking of emissions to define relevant terms such as "actual," "quantifiable," "enforceable," "permanent," and "surplus," as well as to adequately describe the process for banking and tracking the use of banked emissions. {Comment made by the EPA; B27} RESPONSE 169: The PM10 maintenance plan uses the term "baseline for the emission rates relied upon by this maintenance plan" in accordance with Section 173(a)(1) of the Clean Air Act that establishes the permitting requirements for nonattainment areas: "173(a)...(1) in accordance with regulations issued by the Administrator for the determination of baseline emissions in a manner consistent with the assumptions underlying the applicable implementation plan approved under section 110 and this part, the permitting agency determines that -(A) by the time the source is to commence operation, sufficient offsetting emissions reductions have been obtained..." The baseline for the SIP is also referred to in 40 CFR Part 51, Appendix S and in EPA's 1986 Emissions Trading Policy Statement. The purpose of this section of the maintenance plan is to establish that the registry of existing emission reduction credits was included in the modeling demonstration for the PM10 maintenance plan. The PM10 maintenance plan refers to "Existing Emission Reduction Credits on file with the DAQ." DAQ maintains a registry of emission reduction credits, and all of the registered credits for PM10, SO2 and NOx were included in the modeling analysis as banked emissions. The PM10 maintenance plan does not establish the requirements and procedures for using or banking emission offset credits. R307-403 establishes the requirements for permitting of new major sources and major modifications in the PM10 nonattainment area, including the banking provisions and requirements that emissions offsets must meet before they could be used in the permitting process. DAQ is implementing and enforcing this rule in accordance with EPA's interpretation of the rule in the May 5, 1995 approval of Utah's nonattainment NSR rules (FR Vol. 60, 87, pages 22277 - 22283). The registry is provided to facilitate the negotiations of sources that are seeking to use the credits.
COMMENT 170: Kennecott interprets the language on pages 35 and 37, as well as the language in the rules, to preserve the existing Emission Reduction Credits (ERCs) as well as the existing system for banking ERCs from emission reduction for use as offsets in the future. We ask the Division to confirm this interpretation. {Comment made by Kennecott} RESPONSE 170: The emission reduction credits in Utah's registry were included in the modeling for the maintenance plan to preserve these credits in the baseline for the SIP. The PM10 maintenance plan does not establish the requirements and procedures for using or banking emission offset credits. R307-403 establishes the requirements for permitting of new major sources and major modifications in the PM10 nonattainment area, including the banking provisions and requirements that emissions offsets must meet before they could be used in the permitting process. DAQ is implementing and enforcing this rule in accordance with EPA's interpretation of the rule in the May 5, 1995 approval of Utah's nonattainment NSR rules (FR Vol. 60, 87, pages 22277 - 22283). The registry is provided to facilitate the negotiations of sources that are seeking to use the credits.
COMMENT 171: The proposed Plan and rules do not indicate any changes in the provisions for emission reduction credit. We request confirmation of this, or an explanation of what changes are expected as a result of this Plan. {Comment made by UIENC} RESPONSE 171: The commenter is correct that the maintenance plan does not change any provisions for emissions offset credits. The requirements for the use of emissions offset credits in nonattainment areas are found in R307-403. A new rule that was proposed to support the goals of the maintenance plan will maintain the offset provisions for SO2 and NOx in Salt Lake and Utah Counties when these areas are redesignated to attainment. The new rule relies on the process and procedures established in R307-403 for establishing and using emission offset credits. CONTINGENCY MEASURES:
COMMENT 172: On page 45, line 19, Section IX.A.10.c(10), "Contingency Measures": Per section 175A(d) of the CAA, you must list as potential contingency measures any requirements removed from the SIP for the area. This includes any stationary source limits and requirements that are being removed from the SIP for Salt Lake or Utah Counties. These need not be individually identified. Instead, it can refer to all stationary source requirements that were in effect before adoption of new section IX.H. {Comment made by the EPA; B42} RESPONSE 172: Utah is not removing provisions from the SIP that were needed to attain the standard but are no longer needed to maintain the standard. Instead, Utah is redefining RACM to focus on those emission units that have a significant impact on PM10 levels. The effectiveness of the RACM controls will not change, and the SIP will be more functional. Part H of the SIP will be submitted to EPA as a SIP revision, not as part of the maintenance plan. When the Utah PM10 SIP was developed in the late 1980's and early 1990's detailed requirements for stationary sources were included in the SIP without understanding the future implications. These details were not necessary to establish RACM in the SIP because it was the larger emission units that affected the modeling demonstration. The level of detail quickly became unmanageable because even minor changes required a SIP revision, and the early SIP revisions that were sent to EPA were never approved. In 2002 the State of Utah submitted a PM10 SIP revision that addressed this problem for stationary sources in Utah County. The SIP was focused on the larger emission units, and the level of detail was reduced. The requirements for smaller sources and smaller emission units were moved to approval orders for the sources, and any future changes to those sources will be subject to the permitting requirements in R307-401, R307-403, or R307-405 (BACT or LAER will be required). EPA approved the SIP revision on December 23, 2002, in part because the revised RACM determination was still valid. The proposed revisions to Part H follow the same approach that was used in the 2002 revision to the SIP. Section 175A of the Act requires the maintenance plan to "include a requirement that the State will implement all measures with respect to the control of the air pollutant concerned which were contained in the State implementation plan for the area before redesignation of the area as an attainment area." DAQ anticipates that EPA will approve the revision to Part H prior to, or concurrently with the approval of the maintenance plan. Therefore, the revised RACM determination would be part of the SIP at the time of approval. In the future, if Utah determines that RACM is no longer required to demonstrate attainment or maintenance, it would be appropriate to place the RACM requirements in the SIP as contingency measures.
COMMENT 173: Any control measure removed from the nonattainment SIP must be included in the maintenance plan as a possible contingency measure. Therefore, Utah should include all the control measures that are proposed for removal, such as the more inclusive stationary source requirements that were included in the original SIP. Utah should consider removing or suspending the use of banked emissions if contingency measures are necessary. The state's banking registry includes large amounts of banked PM, SO2, and NOx emissions that could cause problems if these emissions are bought and used by new or expanding sources. {Comment made by Environmental Defense and Utah Chapter, Sierra Club} RESPONSE 173: The response to Comment 172 addresses the issue of including old SIP requirements as contingency measures. The modeling demonstration included all of the PM10, SO2 and NOx emissions that are included in the registry, and still showed attainment. In addition, when the area is redesignated to attainment for PM10, the PSD permitting program and the state permitting program will require an impact analysis for new or modified stationary sources to ensure that the NAAQS is maintained. However, if there are future violations of the PM10 NAAQS, section IX.A.10.c of the plan contains contingency measures that will be considered to address the problem, including further controls on stationary sources. The controls selected will depend on the nature of the violation. A summertime dust problem would require a different solution than a wintertime inversion problem. If the violation is attributed to growth of new sources then changes to the offset provision, such as increasing the offset ratio for PM10 or one of its precursors, may be an option. This approach has already been used as a proactive measure to control the growth of VOC sources in the ozone maintenance area. These types of decisions will be made, as described in section IX.A.10.c of the plan if a future violation of the PM10 standard occurs. CLARIFICATIONS and CORRECTIONS:
COMMENT 174: On page 2, section IX.A.10.a(2), there is a typo in the first paragraph. It states "On February 3, 1995, Utah submittal amendments . . ." which should read "On February 3, 1995, Utah submitted amendments . . ." {Comment made by the EPA; B3} RESPONSE 174: DAQ agrees, and will make the appropriate revision.
COMMENT 175: The discussion of the Magna monitoring station on page 4 says, "It is largely impacted (at times) by blowing dust from a large tailings impoundment..." We believe this clause should be put in the past tense, because the South Impoundment is no longer in use and has been reclaimed, with vegetation on all but a few hundred acres that are either saturated or under water. It is no longer a source of significant dust, and the North Impoundment is well controlled. We suggest adding a broken vertical line to Figure IX.A.26 between 1988 and 1989 with a caption to indicate the implementation of the new dust controls. {Comment made by Kennecott} RESPONSE 175: The discussion, on page 11 (not page 4), concerns the network of air quality monitors and the situating of individual monitors within the context of the network. The PM10 monitor at Magna is described as being located in a suburban residential area and as being largely impacted (at times) by blowing dust from a large tailings impoundment. It is certainly true that improvements have been made at the tailings impoundment, but when wind speeds become excessive the monitor at Magna is still sensitive to windblown dust from the impoundment. This is evidenced by several exceedances recorded in 2001, 2002 and 2003 (see discussions at Comments 6, 7 and 8). DAQ believes the text on page 11 accurately characterizes the significance of a PM10 monitor at Magna.
COMMENT 176: In Part A, page 8, lines 8-11, the text should be modified to address the annual standard in Salt Lake County. {Comment made by Kennecott} RESPONSE 176: DAQ concurs with this suggestion, and will propose additional text as indicated, to read as follows: "Additional information presented in Subsection IX.A10.b(3) shows that the Salt Lake County PM10 nonattainment area has not violated the 24-hour standard since 1992, nor has it exceeded the annual standard since 1993. It actually attained both standards as of December 31, 1995, and has remained in compliance with the PM10 NAAQS through 2004." See the response to comment 8 for an explanation of the language regarding the 24-hour standard.
COMMENT 177: In SIP IX.A.10, on page 12 in line 42, there is a reference to IX.A.10.a(1)(iv). There is no such citation; it should be IX.A.10.a(1)(4). {Comment made by Wasatch Clean Air Coalition} RESPONSE 177: DAQ agrees, and will make the appropriate revision, which should be IX.A.10.a(4).
COMMENT 178: On page 12, section IX.A.10.b(1)(d), "EPA Acknowledgement": The relevant discussion is not whether EPA previously determined that the areas (Salt Lake and Utah counties) were attaining, but whether they are currently attaining the standard. {Comment made by the EPA; B10} RESPONSE 178: Section IX.A.10.b(1)(d) follows sections IX.A.10.b(1) (a) through (c) which do in fact address the question of whether all three areas (Salt Lake and Utah Counties and Ogden City) are currently attaining the standard using the most recent three years of quality assured air quality data. Given however that the language of CAA 107(d)(3)(E)(i) "The Administrator determines that the area has attained the national ambient air quality standard" is in the past tense, the discussion presented in Section IX.A.10.b(1)(d) seems relevant as well.
COMMENT 179: On page 12, section IX.A.10.b(1)(c), lines 9 - 12: The State should describe how modeling indicates that the areas are attaining the standard today, not how modeling shows the areas will maintain the standard through 2017. The latter is the maintenance demonstration, a separate requirement. {Comment made by the EPA; B9} RESPONSE 179: The span of the modeling analysis, conducted as part of the maintenance plan, covers the years 2005 through 2017. DAQ will add clarification language to read as follows (beginning on line 11): "It shows that all three nonattainment areas are presently in compliance, and will continue to comply with the PM10 NAAQS through the year 2017."
COMMENT 180: On page 12, section IX.A.10.b(2), EPA suggests that this section should mention the recent revision to the Salt Lake SIP that established different budgets for conformity. {Comment made by the EPA; B11} RESPONSE 180: This comment refers to R307-310 that permitted limited trading between the PM10 and NOx budgets derived from the existing PM10 SIP for Salt Lake County. However, as part of the PM10 Maintenance Plan, a new section R307-310-5 is being added that keeps the R307-310 in effect until the day that EPA approves the conformity budget in the PM10 Maintenance Plan. Therefore, this flexibility will no longer be permitted, and it is not necessary to provide any further clarrification.
COMMENT 181: On page 13, section IX.A.10.b(3)(a) and on page 27, section IX.A.10.b(3)(b)(III), DAQ points out that Ogden City began implementing a voluntary woodburning program. Voluntary measures are not considered in the request for redesignation because such measures are not permanent and enforceable. {Comment made by the EPA; No.s B12 and B15} RESPONSE 181: DAQ understands that voluntary measures are not creditable. Nevertheless, the effect of the program is likely reflected to some degree, along with other creditable measures, in the ambient air quality data trends, and that is why it was mentioned. However, since the point of the exercise is to reasonably attribute the improvement in air quality to emission reductions that are permanent and enforceable, DAQ will simply strike the language to avoid any confusion. On page 13, section IX.A.10.b(3)(a), the change will read as follows: "In the case of Ogden City, there were a number of control measures incorporated into the Utah SIP on either a state-wide basis or as applicable to nonattainment areas in general. As discussed in Subsection IX.A.10.a(1) above, these measures were at least partly responsible for bringing the area into compliance with the PM10 NAAQS. The introduction of these measures (open burning rule, visible emissions rule, fugitive dust rule, and vehicle I/M) was not so abrupt as was the case in the other two nonattainment areas, but Vehicle I/M did begin in 1990 which is relatively coincident with the peak of measured concentrations for the area. Its effectiveness is seen in all subsequent years." On page 27, section IX.A.10.b(3)(b)(III), the follwoing text will be deleted: "[In addition, Ogden began participating in the woodburning program on a voluntarily basis during the winter of 1993.]"
COMMENT 182: On page 14, the text should be corrected to say that the standard has not been VIOLATED since 1992, as there have been exceedances since then. {Comment made by Kennecott} RESPONSE 182: DAQ presumes this comment to actually pertain to the discussion on page 8, lines 8-11. As such, see discussion under Comment 151.
COMMENT 183: On page 27, section IX.A.10.b(4), pertaining to section 110 of the CAA and Part D requirements, the text doesn't address part D requirements. DAQ should include some discussion regarding the nonattainment area SIPs. For Ogden, this would probably be a statement regarding anticipated EPA approval....Also, under this same section, last sentence located at the top of page 28, DAQ has confused the citations of EPA's federal register actions dated March 9, 2001 and August 15, 1984. EPA suggests changing this sentence to read as follows: "For further detail, see 45 FR 32575 dated August 15, 1984 (Volume 49, 159) or 66 FR 14079 dated March 9, 2001 (Volume 66, 47)." {Comment made by the EPA; B16} RESPONSE 183: DAQ agrees, and will add the following language to the end of section IX.A.10.b(4): "Part D of the Clean Air Act addresses "Plan Requirements for Nonattainment Areas." One of the pre-conditions for a maintenance plan is a fully approved attainment plan for the area. This is also discussed in section IX.A.10.b(2). For Salt Lake County, the Part D requirements for PM10 were addressed in an attainment SIP approved by EPA on July 8, 1994 (59 FR 35036). For Utah County, the Part D requirements for PM10 were most recently addressed in an attainment SIP approved by EPA on December 23, 2002 (67 FR 78181). For Ogden City, it is anticipated that the Part D requirements for PM10 will be found to have been satisfied via EPA's Clean Data Areas Approach (October 18, 1999)." DAQ will also correct the incorrect Federal Register citation identified in the comment.
COMMENT 184: The data for the "Ogden2" monitor that replaced Ogden1-49-057-0001 is not shown in graphs in Section IX.A.10.b(3). {Comment made by the EPA; B17} RESPONSE 184: Section IX.A.10.b(3) of the proposed maintenance plan addresses the role of emissions reductions in the observed improvement in air quality. Ambient data has only been collected at the Ogden2 site since the summer of 2001, and it was thought that this was too short a time span to reveal any significant trends. Nevertheless, the data from Ogden2 could be combined with the data from Ogden1 in the charts that are shown as Figures IX.A.38 and 39. Some text will also be provided in section IX.A.10.b(3)(a) to explain as much.
COMMENT 185: On page 27, section IX.A.10.b(4), pertaining to section 110 of the CAA and Part D requirements, DAQ needs to include a discussion of how they've addressed the commitments that were made to EPA by DAQ in a letter dated April 18, 2002 and included in EPA's federal register action approving revisions to the Utah County SIP, dated December 23, 2002 (67 FR 78181). {Comment made by the EPA; B18} RESPONSE 185: DAQ agrees that this information is pertinent to the discussion of the proposed PM10 maintenance plan. However the commitments made in the above referenced letter are neither section 110 requirements nor Part D requirements, and should not be included in the maintenance plan.
COMMENT 186: On page 30, section IX.A.10.c(a), under Meteorological data: The discussion is not clear. An average reader will be unable to understand the chronology and the importance of the discussion. {Comment made by the EPA; B19} RESPONSE 186: In order to provide more information to the average reader, the following text from the TSD will replace the text presently found in section IX.A.10.c(a): "(a) Meteorological data. Recent DAQ meteorological modeling projects using advanced "state of the science" prognostic meteorological models have proven unsuccessful in simulating highly variable Wasatch Front meteorology during inversion conditions. These problems led DAQ to choose a diagnostic meteorological model called the Diagnostic Wind Model (DWM) model for the January 2001 and February 2002 episodes to avert many of the past modeling problems. The DWM assimilates actual observations of wind speed and direction to diagnose and construct a consistent wind field. DAQ embarked on a 4-phase modeling approach in order to develop the most realistic wind fields possible. Each phase of the 4-phase modeling approach utilized unique combinations of observed meteorological data for each analysis. Each of the 4 phases is described below: Phase 1. The DWM model was run utilizing 60-100 surface observing stations, two radiosondes, and two SODARs per day. The surface station data was taken from the University of Utah MESOWEST database and included a wide variety of station types. Phase 1 of modeling utilized only surface stations with an elevation of 5,500ft or lower. The National Weather Service Salt Lake City radiosonde data was used along with two DAQ SODAR units operated in Utah and Salt Lake valleys. It was thought that the multitude of available data would allow DWM to produce representative wind fields. UAM-AERO results showed modeled PM10 values that were only 40-50% of the observed values. Model output evaluation showed that PM10 was being advected out of the Salt Lake Valley (SLV) and the model domain to the SE. Afternoon up-valley NW winds moved PM10 into the mountains to the SE of the SLV. At night, winds became light and variable at most surface stations and as a result were unable to return the PM10 back to the SLV. Additionally, DAQ's hypothesized benefit of having a multitude of surface stations actually induced unrealistic vertical motions due to surface convergence of widely varying wind directions. Phase 2. The failings of phase 1 encouraged DAQ to be more selective of the surface stations used in DWM. First, the Salt Lake Valley SODAR was discarded due to observations that were incongruent with the Utah Valley SODAR and the Salt Lake City radiosonde. Second, DAQ selected only the DAQ operated surface stations. These surface stations are situated in strategic locations across the Wasatch Front. 11 DAQ stations were used. The phase 2 hypothesis was that the more selective set of surface stations might produce a wind field with less convergence and resultant vertical motions. DAQ found that the phase 2 wind fields produce periods of daytime NW winds that advected pollutants out of the SLV. The nocturnal and morning winds were light and variable and were unable to return the pollutants to the SLV. Most of the observations within the SLV show a trend of daytime up-valley flow and nighttime weak variable flow. In reality, the daytime flown re-circulates within the boundaries of the inversion but in UAM-AERO the continuous grid network cannot retain the flow within the open sided grid cells of the SLV. Phase 3. Phase 2 results showed transport of PM10 out of the SLV. Model evaluation clearly showed a direct link with the observation wind direction and speeds. Phase 3 tested the possibility that a single station located in SLV might produce a wind field that has a more even distribution of wind direction and speeds. In other words, is there a station in SLV that is representative of the valley but where daytime winds and nighttime winds balance each other? If so, developing a wind field from a single station may reduce advection out of the SLV. Three separate wind fields were developed in phase 3. These wind fields utilized the centrally located and well sited DAQ Hawthorne and West Valley monitors as well as another well sited but southeasterly located DAQ Cottonwood station. The results of phase 3 modeling again showed advection out of the SLV and the domain. Stronger daytime NW winds compared to nighttime light and variable winds again forced the loss of PM10. b) Phase 4. Phases 1-3 clearly demonstrated the inability of the DWM model to accurately represent the conceptual understanding of inversion conditions. The model deficiencies arise from the model grid-cell structure. The model grid cells are continuous and are unable to "trap" or contain air within an inversion layer. The real wind observations in the SLV do have advective properties that would allow the pollutants to move beyond the boundaries of the SLV under non-inversion conditions. However, under inversion conditions the advective properties of the real wind observations are negated by a forced recirculation of air within the inversion layer by the containing boundaries of the inversion. In phase 4, a purely idealized flow was created in the attempt to retain pollutants in the SLV. A bimodal wind direction field was created using an afternoon NW wind (330) and an evening, night, and morning SE wind (140). These directions correspond to daytime up-valley flow and nighttime down-valley flow. Wind speeds were chosen so that advection was limited to within the boundaries of the SLV. This wind field, while idealized, fits the conceptual understanding of inversion conditions. Phase 4 modeling retains PM10 within the SLV and UAM-AERO PM10 results show excellent agreement with the observations."
COMMENT 187: Ambient Air at Kennecott Mine and Copperton Concentrator - The text on page 31, section IX.A.10.c(1)(c), notes that a PM10 NAAQS violation was modeled on a 4 km grid cell that was fully contained on Kennecott's property boundary and therefore the grid cell cannot be considered ambient air. In order to be excluded from consideration as ambient air, public access would need to be precluded by means of a fence or other barrier (such as posting "No Trespassing" signs and security guards). Also any leased property within the Kennecott compound would normally be considered ambient air. The plan language should address these requirements. {Comment made by the EPA; B20} RESPONSE 187: According to officials of KUCC, the mine has a centralized access point for entrance to the Mine operations which is manned by security personnel, 24 hours a day, 7 days a week, 365 days a year. Industrial grade fencing is utilized to prevent unauthorized entry to all Kennecott plants and operations. No trespassing signs are posted on the fences and additional security supervisory patrol is mobile 24 hours a day, 7 days a week to monitor the fence line. Security is aided by the use of closed circuit TV in certain areas to monitor unauthorized activity.
COMMENT 188: Part A, page 36, discusses concentrations greater than 150 u/m that were predicted in two grid cells on KUCC property. We understand that one cell was in the Bingham Canyon mine pit and the other was just north of the pit. The general public does not have access to this area and thus these two grid cells do not represent ambient air. In addition, one cell was in an emission source and the other adjacent to the source. For these reasons, these were inappropriate locations for receptors in a modeling demonstration. {Comment made by Kennecott} RESPONSE 188: DAQ agrees that the two grid cells do not represent ambient air. In a grid-based model ambient concentration are not estimated at receptors but rather each grid cell centroid reports hourly concentrations. Therefore, all of the cells in the modeling domain have estimated concentration whether they have emissions sources located within them or not.
COMMENT 189: On page 34, section IX.A.10.c(1)(d), paragraph at the top of the page, 2 and 3 sentence - These sentences suggest that no new control strategies are needed because the 1991 strategies were sufficient to achieve compliance with the 24-hour and annual standards. This misconstrues the point of the maintenance demonstration. It's only because the area can continue to maintain the standard throughout the maintenance period without new control measures that no new measures are needed, not because the area has been meeting the standards with current measures. {Comment made by the EPA; B21} RESPONSE 189: Section IX.A.10.c(1)(d) addresses the demonstration of maintenance with respect to the annual standard for PM10. DAQ acknowledges that the point of the exercise is to demonstrate that a suite of controls is, and will be, sufficient to achieve compliance with the NAAQS. In the case of the annual standard, one follows the other. In other words, because the suite of controls developed to address the 24-hr standard has also proven effective, as assumed, in controlling for the annual standard, we are able to conclude that this assumption was in fact valid. This means that the same assumption may be carried forward into the proposed maintenance plan, which is significant because the UAM-AERO model is built only to assess the 24-hr standard under stagnant wintertime conditions. Since the UAM-AERO analysis models essentially the same suite of controls modeled in the previous CMB analyses, it can therefore be said that this modeling analysis also shows compliance with the annual standard through the year 2017.
COMMENT 190: On page 34, section IX.A.10.c(1)(d), second paragraph at the top of the page - DAQ should include text stating that you expect the Ogden area to continue to maintain the annual standard and explain the basis for this expectation. {Comment made by the EPA; B22} RESPONSE 190: The existing language will be expanded upon to read as follows: "The annual PM10 standard was never violated in Ogden City. In fact the highest single value ever recorded (37.6 ug/m3 in 1991) was only 75% of the standard. Furthermore, as shown in Figure IX.A.39, the general trend in the annual arithmetic mean concentrations observed since 1986 is downward. As explained in section IX.A.10.b(3)(b)(iii), this trend is reflective of permanent and enforceable control measures that were incorporated into the Utah SIP. The continued implementation of these control measures provides a reliable indication that the annual mean concentrations of PM10 will remain well within the standard of 50 ug/m3."
COMMENT 191: On page 34, section IX.A.10.c(2), last sentence on this page - DAQ needs to be specific about what bordering region is included in the modeling domain. {Comment made by the EPA; B23} RESPONSE 191: DAQ will add a cross reference to the graphical picture of the modeling domain, which indicates all county boundaries and nonattainment areas, to read as follows: "The modeling domain encompasses all three areas within the state that were designated as nonattainment areas for PM10: Salt Lake County, Utah County, and Ogden City, as well as a bordering region see Figure IX.A.23."
COMMENT 192: On page 36, section IX.A.10.c(3), line 16 - The text says, "as determined on a short-term basis." DAQ needs to be specific about the time-frame; e.g., "as determined on a 24-hour basis." {Comment made by the EPA; B24} RESPONSE 192: DAQ will change as follows to clarify: "The larger sources within the modeling domain were modeled at their maximum allowable emissions, as determined on a 24-hour basis."
COMMENT 193: On page 37, section IX.A.10.c(3), line 11 - This statement should include a cross-reference to the section of the maintenance plan that describes the maintenance demonstration. {Comment made by the EPA; B26} RESPONSE 193: DAQ will modify the language on page 37 to read as follows: "These conditions demonstrate maintenance through 2017 see subsections IX.A.10c.(1 ) and (2)."
COMMENT 194: On page 37, section IX.A.10.c(5), line 29 - The text refers to "these emission limitations." DAQ needs to specify which limits it is referring to. {Comment made by the EPA; B28} RESPONSE 194: DAQ will modify the language on page 37 to read as follows: "Since the emission limitations discussed in subsection IX.A.10c.(3) remain federally enforceable and have been sufficient to ensure continued attainment of the PM10 NAAQS, there is no need to require any additional control measures to maintain the PM10 NAAQS."
COMMENT 195: On page 37, section IX.A.10.c(5), lines 29 - 31: Use of the past tense - "have been sufficient" - is inappropriate. Change to read, "Since the emissions limitations contained in section 5 data of the SIP remain federally enforceable and are sufficient to ensure continued attainment of the PM10 NAAQS [cross-reference maintenance plan section that describes the maintenance demonstration], there is no need ..." {Comment made by the EPA; B29} RESPONSE 195: DAQ agrees, and will revise the text to read as follows: "Since the emission limitations discussed in subsection IX.A.10c(3) remain federally enforceable and, as demonstrated in IX.A.10.c(1) above, are sufficient to ensure continued attainment of the PM10 NAAQS, there is no need to require any additional control measures to maintain the PM10 NAAQS."
COMMENT 196: On page 43, line 29, reference to IX.A.10.c(1) - Should this be IX.A.10.c(6)? {Comment made by the EPA; B39} RESPONSE 196: DAQ agrees, and will make the appropriate revision.
COMMENT 197: On page 45, line 8, Section IX.A.10.c(9) - there is a spelling error. {Comment made by the EPA; B41} RESPONSE 197: DAQ agrees, and will make the appropriate revision. SECTION IX. PART H - EMISSION LIMITS AND OPERATING PRACTICES: GENERAL COMMENTS:
COMMENT 198: (EPA C general 1) The State is proposing to remove various sources and numerous requirements from existing section IX.H. One overarching concern is that the proposed changes are so extensive that they will render the source-specific provisions unenforceable. We're also concerned that the remaining emissions limits and other requirements may not be consistent with the maintenance demonstration. The prior SIP had far more detailed compliance determining provisions. Another very significant and related concern is that the proposed changes, even if they could be found to be consistent with maintenance of the PM10 NAAQS, may negatively impact other NAAQS and CAA requirements. Based on interpretations of section 110(l) that EPA has recently expressed in letters, and anticipated guidance that EPA is drafting, we would like to advise the State that before we could approve the proposed changes, the State would need to demonstrate (possibly through modeling) that the changes would not interfere with attainment, maintenance, or any other applicable requirements of the CAA, not just for PM10, but for other pollutants as well, including SO2, PM2.5, and ozone. The potential impact on PSD increments is also a concern and would have to be addressed in a demonstration of noninterference. Due to time constraints, we cannot detail every issue related to 110(l) in this letter. Instead, it is essential that the State provide an adequate demonstration for all the proposed changes. {Comment made by the EPA} RESPONSE 198: a) The emission limitations in Part H are enforceable. R307-305-4 requires all sources with emission limitations in Part H of the SIP to comply with those emission limitations. All of the source-specific requirements that were not needed to meet the RACM requirement have not gone away. They are included in federally-enforceable approval orders for the affected sources. Any changes at those sources have occurred through Utah's NSR process and have required LAER (BACT for non-major sources) and emissions offsets to compensate for any emission increase. All of the emission limitations in the SIP and the approval orders are subject to Title V permitting requirements for affected sources, further ensuring the enforceability of the underlying requirements. b) The emission limits are consistent with the modeling demonstration. The larger sources were modeled based on their maximum emission rates because these sources are large enough to individually affect the attainment demonstration. If the individual source operated at the maximum level it could affect the NAAQS. The emission limits for these large sources are included in Part H of the SIP. The projection inventories for these sources may be found at section (3)(b)(iii) of the TSD (see also the response to Comments 241 and 247). The smaller sources were modeled based on their actual emission rate because they contribute more to the background level of PM10 rather than affecting the attainment demonstration as a single source. If a small source was operating at its maximum level it would not significantly affect PM10 levels and most likely another source would be operating at a reduced level to counteract the impact on background levels in the attainment demonstration. c) It is difficult to respond to a comment regarding EPA guidance that has not yet been released. DAQ staff has not developed this maintenance plan in a vacuum without consideration of the effect of this plan on other pollutants. DAQ is currently working on a revised ozone maintenance plan for ozone (due in April 2007) to demonstrate that Salt Lake and Davis Counties will continue to meet the 8-hour ozone NAAQS. Current ozone monitoring data show on-going improvement in ozone levels in the area. Preliminary inventory numbers for that plan show that NOx emissions in the maintenance area will be declining significantly over the next 10 years as more vehicles meet the Tier 2 emissions standards. The State of Utah submitted an SO2 maintenance plan in January of this year that was developed concurrently with the PM10 maintenance plan and that showed maintenance of the standard for the next 10 years. Current monitored values of SO2 are less than a 10 of the standard. Utah also just submitted a regional haze SIP in December 2003 that addressed visibility-impairing pollutants in the state through the year 2018. The pollutant that is of most concern to DAQ at this point in time is PM2.5. The good news is that the control strategies in the both the 1981 TSP SIP for the Wasatch Front, and the 1992 PM10 SIP for Salt Lake and Utah Counties have been focused on the smaller sized particles, and have therefore significantly reduced PM2.5 levels over the last 30 years. The PM10 maintenance plan shows continued improvement in the near term as more vehicles meet the Tier 2 emissions standards. Because so much of PM10 during wintertime temperature inversions is due to fine particles DAQ anticipates that improvement will be seen in PM2.5 levels as well. Now that the PM10 maintenance plan has been completed, DAQ can focus the State's technical resources on better understanding and addressing PM2.5. All of these related SIPs work together to show that the overall pollution control strategy in Utah is working. It is not necessary to do a separate analysis of how each plan affects the others because this work is proceeding concurrently and DAQ deliberately focuses on emission reduction strategies that will meet multiple air quality goals. d) In regards to PSD, the total emissions of PM10 and PM10 precursors have gone down significantly since 1990 due to the PM10 SIPs, ozone maintenance plan, Tier 1 and Tier 2 emission standards for automobiles, federal acid rain regulations, and on-going reductions due to Utah's effective NSR program. DAQ has not done a formal increment analysis, but it is clear that increment has been expanded in the area since 1990 for NOx and since 1979 for SO2 and PM10. The proposed revision to the major source baseline date (see Comment No. [128] for a more detailed discussion) is intended to make the PM10 and SO2 increments a useful tool to prevent air quality from slowly degrading in the area to the level of the NAAQS.
COMMENT 199: The State of Utah prepared a projection year inventory for large point sources, as defined by an agreement between the State and EPA (100 tons per year of PM10, 200 tpy of NOx, or 250 tpy of SO2). The maintenance plan (at page 36, section IX.A.10.c(3), lines 17 and 18) indicates that emission limits in Section IX, Part H were only included for large point sources that are located in one of the PM10 nonattainment areas or that currently have limits in Section IX, Part H. The basis for not including limits for other large sources listed in the projected inventory does not appear to be technically defensible. As a starting point, we would expect large sources included in the modeling domain to be given emissions limits in the SIP. Any exclusion must be based on valid technical grounds. This is also relevant to the commitments made by DAQ in its letter to the EPA dated April 18, 2002. {Comment made by the EPA; B25, includes EPA comments D1 and I3} RESPONSE 199: The identification of a subset of "large sources" for inclusion in Part H is less arbitrary than it may seem. It is important to recognize that the demonstration of maintenance was based on the UAM-AERO model which is regional in scale. Figure IX.A.23 of the proposed Maintenance Plan shows the domain that was modeled, and shows within that domain the outline of the current nonattainment areas. [A figure was provided to show the location of the "large sources" within the domain.] During the course of Plan development, various sensitivity runs were made to ascertain the effects of adjustments that could be made to the projection year inventories. One of the questions that was addressed during the course of this work was the spacial sensitivity of the receptors to adjustments made to the inventories of the "large sources." The inventory adjustment used to address this question involved a choice of two possible sets of projections: 1) the "PTE" approach that was ultimately used and documented as part of the proposal, and 2) the "traditional method" of projecting actual emissions that was employed at the "small sources" throughout the domain. As a general rule, the PTE method results in projection year inventories that are about 2 times as large as those calculated in the traditional way. Using this difference in approach, two sensitivity runs were made with the model. First, a subset of six large sources located nearest to the grid cells (near North Salt Lake) that were predicting the highest concentrations were "discounted" by switching from the PTE approach to the traditional approach. This model run yielded predicted concentrations that were 9% lower than benchmark concentration. A second run was made, wherein a subset of nine large sources located in the outlying regions of the modeling domain were similarly discounted. This time there was no difference in the maximum concentrations predicted by the model. It could therefore be concluded that the impact of large sources within the model is greatly limited in space. The list of (nine) sources that was discounted in the second modeling run is identical to the list of sources that was excluded from Part H, with only two exceptions. Payson City Power was discounted in the sensitivity run, but has been included in Part H because it resides in Utah County (a nonattainment area). Desert Power L.P., located right by U.S. Magnesium (which is excluded from Part H), was also excluded from Part H. Emissions from this source were not discounted in the sensitivity run, though based on the criteria they should have been. The difference in projected emission rates for these sources clearly has no effect on the concentrations predicted by the model in the Salt Lake nonattainment area; and by extension has no effect in the Utah County nonattainment area as well, given that these nine sources are all well north of the county line. It therefore cannot be said that the Maintenance Plan has relied upon the emission rates modeled therein to demonstrate continued compliance with the PM10 standard. It follows then that emission limits are not necessary at these sources to legally support the assumptions used to make the assertion that the NAAQS will be maintained in these areas. Nevertheless, one might still wonder about the validity of these claims with respect to the Ogden City nonattainment area. Looking back at these same sensitivity runs, the difference in predicted concentrations at the Ogden City monitor was less than one percent and less than one microgram per cubic meter. Hence, the same conclusion is reached here as well. As further support for this notion, a report commissioned by DAQ in the SIP development stage for Ogden titled "Source Apportionment Analysis for the Ogden PM10 Nonattainment Area (SECOR, July 1998) concluded the following: "The filter analysis data obtained from the Ogden City monitor was sufficient to resolve PM10 source contributions from primary motor vehicle exhaust, primary vehicle brakewear and re-entrained roadsalt, woodburning smoke, secondary sulfate and secondary nitrate. In addition these measurements were sufficient to determine that industrial sources were not major contributors to PM10 measured at the monitor." The evaluation was done using the Chemical Mass Balance model (CMB 7.0). Speaking specifically about industrial sources, the report says "As indicated in the source profile section discussed previously there were source profiles available for all of the major industries including steel mill, copper smelter , refinery, asphalt, cement, and grain processing to name a few. Repeated attempts were made to achieve a fit from these sources by eliminating other collinear sources, changing fitting species, or other CMB modeling tuning methods. The CMB model was not able to resolve any of the major industrial sources which are located along the Wasatch front as contributors to the exceedances at the Ogden monitor." In conclusion, it is worth noting that SIP limits at these sources were never necessary to bring any nonattainment area for PM10 back into compliance with the NAAQS, and it cannot be shown that they will be necessary now to insure maintenance of the PM10 standards throughout the period addressed by the Maintenance Plan. All "large sources" within the modeling domain were modeled in a very conservative way (see the "jump" in Point Source emissions between the episode year 2002 and the first projection year 2005 shown in Table IX.A.37 on page 36) so that the modeling result would itself have some measure of conservatism built in to it. This however is not reason alone to require that emission limits at those sources be included in the SIP. Furthermore, the nine sources excluded from Part H are, and will continue to be, regulated by Approval Orders, state and federal regulations, and in some cases Part 70 permits. This is sufficient to meet all requirements of the Clean Air Act.
COMMENT 200: EPA requests that DAQ submit a redline/strikeout of the final version of Section IX. Part H, to show exactly where DAQ has made changes in Section IX. Part H as compared to what is currently contained in the federally approved SIP section 9.A, Appendix A, including any changes to the source specific particulate emission limitations. {Comment made by the EPA; C general 2} RESPONSE 200: We will work with EPA to accomplish what they need. The software DAQ has available doesn't create a readable comparison document. This is aggravated by the fact that the original Part H is a WordPerfect document; our version of Word does not deal well with WordPerfect documents that include a great deal of formatting, as Part H does. SIP SECTION IX.H.1 - GENERAL REQUIREMENTS: SOURCE TESTING:
COMMENT 201: On page 1, section IX.H.1.a. - This section says "back half condensibles are required for inventory purposes." This language is currently approved into the existing SIP. However, DAQ has never implemented this requirement. The SIP should also indicate that back half emissions must be considered in permit impact and applicability analyses and other applicability analyses under the SIP and CAA. This is also relevant to the commitments made by DAQ in its letter to the EPA dated April 18, 2002. If the State believes that back-half condensibles and Method 202 testing will not have a substantial impact on the countywide emission inventories or attainment/maintenance demonstrations, the State should explain why not. {Comment made by the EPA; C1, includes EPA comment I8} RESPONSE 201: The language in existing section IX.H requires back-half condensibles to be measured for inventory purposes using method 202 or other method specified by the Executive Secretary. It is not true that DAQ has never implemented this requirement. To the contrary, DAQ has been requiring the back-half test results ever since the PM10 SIP was promulgated. This dates back to before method 202 was even approved by EPA. Concerning permitting actions, DAQ currently requires back-half testing for compliance purposes on all coal fired power facilities as well as gas fired turbines that meet PSD applicability. DAQ also routinely considers back-half emissions in determining applicability to various program elements (e.g. major source determination). Concerning the commitments made by DAQ in its letter to the EPA dated April 18, 2002, "Backhalf emissions measuring for PM10 emissions limit stack testing"; the requirement to test for back-half condensibles for inventory purposes will remain in the maintenance plan. However, using the back-half catch for compliance purposes will not become part of this maintenance plan. DAQ has examined that possibility but concluded it would not be prudent to do so for the following reasons: 1) Although the "back-half catch" is incorporated into many of the emission factors included in AP-42, and consequently in the inventories used in the modeling demonstration, there are still many factors that do not consider this fraction. Consequently, it is used inconsistently throughout the inventory. 2) Similarly, the many emission limits that were established in Part H are inconsistent with respect to their inclusion of back-half emissions. To generally require the subsequent method of compliance determination to count the back-half catch against the established emission limit would unfairly penalize some of the sources. 3) These are "PM10" emissions that aren't present in the stack under stack conditions. 4) It is widely understood that many of the back-half condensable emissions measured by method 202 are either gaseous SO2 or VOC compounds. In many instances there are concurrent emission limits on SO2 or VOC, and this would constitute double-counting. In summary, DAQ is aware of back-half emissions, and will continue to consider them in forthcoming permit actions. Should the need arise to promulgate a PM2.5 SIP, it may be appropriate to consider these emissions for planning purposes at that time.
COMMENT 202: On page 2, section IX.H.1.a, the last sentence indicates that the production rate during compliance testing shall be no less than 90% of the maximum production achieved during the previous three years. This provision should say 90% of the maximum production achieved in the previous three years or 90% of the design capacity, whichever is greater, or the State should explain why the current provision is adequate. {Comment made by the EPA; C2} RESPONSE 202: DAQ believes that the current provision is adequate, and is reflective of normal operating conditions. The provision is consistent with the Utah Air Quality Rules and consistent with the provision in the PM10 SIP. The same provision was re-approved into the Utah County PM10 SIP, by EPA, as recently as 2002. OPACITY:
COMMENT 203: On page 2, section IX.H.1.g, the last sentence indicates that for intermittent sources the requirement to make observations at 15-second intervals over a six minute period shall not apply. The State should clarify what will apply. This issue appears wherever the SIP or regulations specify opacity limits that might apply to intermittent sources. The State should clarify these other provisions as well. {Comment made by the EPA; C3} RESPONSE 203: Many commentors expressed concern with the proposal to refine the method used to determine opacity from intermittent or moving sources. As a result, DAQ will revert back to the existing language found in R307-201-3(9) wherever it applies. As presently construed, all other aspects of method 9 would apply to this method.
COMMENT 204: There is a small revision regarding opacity observations. The current language (IX.H2.a.C): "For intermittent sources and mobile source emissions opacity observations shall be conducted using a modified method 9 (not all 24 readings for a six-minute period required." The new language is found in IX.H.1.g: "For intermittent sources and mobile sources opacity observations shall be conducted using procedures similar to Method 9, but the requirement for observations to be made at 15-second intervals over a six minute period shall not apply and any time interval with no visible emissions shall not be included." The new wording may be somewhat less vague than the old, but it does not remedy the serious objections KUCC has repeatedly expressed concerning this requirement. In summary, any modified form of Method 9 (used as an enforcement standard for intermittent or mobile sources, as opposed to a trigger for further action, is not a verifiable method, is not an approved method, and imposes a standard more restrictive than corresponding federal regulations and, according to Utah Code 19-2-106, cannot be maintained without a written finding after public comment and hearing and based on evidence in the record, that corresponding federal regulations are not adequate to protect public health and the environment of the state. Also, it appears that sources now addressed in Part H do not include intermittent or mobile sources, so that there is no need to address opacity observations for them. Therefore, the second sentence of IX.H.1.g should be deleted. {Comment made by Kennecott} RESPONSE 204: As explained in the response to comment 60, DAQ will revert back to the existing language wherever it appears. See also the response to comment 115 for further discussion concerning the proposed rule revisions.
COMMENT 205: UIENC and others have raised serious issues over the years over similar methods for assessing opacity from mobile and intermittent sources. This proposal is not specific as to how the modified Method 9 test would be conducted, whether a specific number of readings must be taken and at what intervals, nor whether certification would be required for observers. EPA has never completed its 1993 proposal for opacity observations from intermittent sources; and that raises questions as to whether DAQ can, in view of 19-2-106, issue a rule that is more stringent than the federal requirement. {Comment made by UIENC} RESPONSE 205: As explained in the response to comment 60, DAQ will revert back to the existing language wherever it appears. See also the response to comment 115 for further discussion concerning the proposed rule revisions. FUGITIVE DUST:
COMMENT 206: Within the existing federally-approved SIP section IX.H.1.a.H there is a control measure addressing the treatment of unpaved roads in operational areas which are used by mobile equipment. This language is missing from the proposed SIP section IX.H.1. If DAQ intends to remove this control measure from the existing SIP, it will need to correct the statement that Utah will continue to implement all control measures contained in the SIP. Furthermore, Utah will need to supply a demonstration that removal of the measure will not interfere with any requirement of the CAA, including requirements for attainment and maintenance of other NAAQS (see section 110(l) of the CAA), and will need to list the control measures within the contingency plan under section IX.A.10.c.(10) of the maintenance plan (see section 175A(d) of the CAA). {Comment made by the EPA; C general 3} RESPONSE 206: Sources of fugitive dust located in the Maintenance area are required to have a fugitive dust plan, see R307-309-6. DAQ has found that fugitive dust plans work better than this provision. Fugitive dust plans are developed for each source. Thus, the fugitive dust plans can be tailored to address a source's unique issues, and thereby controlling fugitive dust better than one arbitrary requirement. For example, the water application rate to control fugitive dust for an unpaved operational area located in St. George will be different from one located in Heber. However, to ensure that there is a minimum dust control requirement in the SIP, DAQ will include the following condition in the SIP at Section IX.H.1.h that requires sources to control fugitive dust on all unpaved operational areas and keep records of the treatments used to control fugitive dust: "h. All unpaved roads and other unpaved operational areas that are used by mobile equipment shall be water sprayed and/or chemically treated to control fugitive dust. Treatment shall be of sufficient frequency and quantity to maintain the surface material in a damp or moist condition, unless the ambient temperature is below freezing. The opacity shall not exceed 20% during all times. If chemical treatment other than magnesium chloride is to be used, the plan must be approved by the executive secretary. Records of water and/or chemical treatment shall be kept for all periods when the plant is in operation. The records shall include the following items: A. Date; B. Number of treatments made, dilution ratio, and quantity; C. Rainfall received, if any, and approximate amount; and D. Time of day treatments were made. Records of treatment shall be made available to the executive secretary upon request and shall include a period of two years ending with the date of the request." REFINERIES; GENERAL REQUIREMENTS:
COMMENT 207: On page 2, section IX.H.1.h(1)(a) says that SRU efficiency shall be estimated and reported a minimum of once per year. We don't believe this is adequate to protect the NAAQS. {Comment made by the EPA; C5} RESPONSE 207: The annual estimation of SRU efficiency was not required in the current PM10 SIP. It has been added to several of the refinery permits over time. The inclusion of this requirement is an inclusion of the permit condition. Further, the 95% is the design requirement for the sulfur recovery units at the refineries. The emission limit for each SRU was determined by taking 5% of the maximum sulfur input to each unit. The emission limits control what is emitted to the air shed. As long as those limits are not exceeded, the NAAQS are protected.
COMMENT 208: On page 2, section IX.H.1.h.(1)(a) - This section indicates that the relevant requirement (95% sulfur removal efficiency) applies "except for startup, shutdown, or malfunction of the SRU." This is not acceptable. EPA cannot approve provisions into SIPs that provide automatic exemptions from emission limits due to startup, shutdown or malfunction. This also applies to: 1) proposed section IX.H.1.h.(1)(b): which indicates that the relevant requirement (reducing the H2S content of the refinery plant gas to 0.10 grain/dscf (160 ppm) or less) applies "except for startup, shutdown, or malfunction of the amine plant" {Comment made by the EPA; C6, includes EPA comments C7 and C12} RESPONSE 208: DAQ took this condition from EPA Consent Decrees. In Consent Decrees with the two largest refineries, startup/shutdown/malfunctions are exempt from requirement for 95% efficiency. 40 CFR 60 Subpart A also allows such an exemption from Subpart J, Standards of Performance for Petroleum Refineries. 40 CFR 63.6(h)(1) also allows this exemption. The Consent Decree between BP-Amoco and EPA, dated 8/2/02 (http://www.usdoj.gov/enrd/bpcd.htm), requires that "BP shall comply with a 95% recovery efficiency requirement for all periods of operation except during periods of startup, shutdown, or malfunction of the SRP." [clause 21.B.iv.a]. This Consent Decree was signed by "STEVEN A. HERMAN, Assistant Administrator for Enforcement and Compliance Assurance, United States Environmental Protection Agency, Washington, D.C. 20460" - this is the same Steven Herman responsible for the 1999 guidance "State Implementation Plans: Policy Regarding Excess Emissions During Malfunctions, Startup, and Shutdown." Since the Consent Decree is dated more recently, and federal regulations still allow the situation discussed here, DAQ sees no conflict with federal guidance. The recently-drafted (2003) Consent Decree with Chevron requires: "16. Compliance with Specific SO2 Emission Limits (El Segundo, Hawaii, Pascagoula, and Salt Lake City FCCUs): "e: SO2 emissions during periods of Startup, Shutdown, or Malfunction shall not be used in determining compliance with the emission limit of 50 ppmvd SO2 at 0% 02 on a 7 day rolling average basis, provided that during such periods Chevron implements good air pollution control practices to minimize SO2 emissions." "48. Compliance with Emissions Limits at the Salt Lake City SRP. . With respect to the Salt Lake City SRP, Chevron shall comply with a 95% sulfur recovery efficiency requirement for all periods of operation except during periods of startup, shutdown or Malfunction of the SRP." (http://www.epa.gov/compliance/resources/decrees/civil/caa/chevron-cd.pdf) 40 CFR 60 Subpart A at 60.8(c) states "Operations during periods of startup, shutdown, and malfunction shall not constitute representative conditions for the purpose of a performance test nor shall emissions in excess of the level of the applicable emission limit during periods of startup, shutdown, and malfunction be considered a violation of the applicable emission limit unless otherwise specified in the applicable standard." Subpart J does not "otherwise specify." 40 CFR 63 at 63.6(h)(1) states: "(h) Compliance with opacity and visible emission standards- (1) Applicability. The opacity and visible emission standards set forth in this part must apply at all times except during periods of startup, shutdown, and malfunction, and as otherwise specified in an applicable subpart. If a startup, shutdown, or malfunction of one portion of an affected source does not affect the ability of particular emission points within other portions of the affected source to comply with the opacity and visible emission standards set forth in this part, then that emission point shall still be required to comply with the opacity and visible emission standards and other applicable requirements." See also, "Proposed Rule Revisions:" (Excess Emissions), Comments 113 and 114 for further discussion.
COMMENT 209: IX.H.1.h.(1)(e): opacity at catalytic cracking units - This section indicates that the opacity for catalytic cracking units shall not exceed 20% if Method 9 is the compliance determination method, and 30% if a continuous opacity monitoring system (COMS) is the compliance determination method. The requirement regarding the 30% opacity and COMS is new and was not in the original 1991 PM10 SIP. We have two concerns with this provision: First, before we could approve a relaxation in the opacity limit to 30%, the State would need to demonstrate that the relaxation would not interfere with any applicable requirement concerning attainment and reasonable progress (as defined in CAA section 171) or any other applicable requirement of the Act, including maintenance. See CAA section 110(l). Second, as a general matter, the opacity limits should not vary based on the method used to determine compliance. We do not accept the proposition that a switch to COMS renders an opacity limit more stringent. {Comment made by the EPA; C10} RESPONSE 209: DAQ was attempting to be consistent with federal standards and to avoid a credible-evidence issue with the two standards. However, the data required to justify a relaxation of the opacity limit to 30% is not readily obtainable in the time allowed. DAQ will remove the 30% with COMS option, and return to the current 20% opacity with Method 9 as the compliance method in IX.H.1.h.(1)(e). If the required data become available, DAQ will readdress the issue at that time. The 20% opacity is clarified to read as follows to show that all refineries must meet the same opacity limit, regardless of facilities or installations between the regenerator and the exit point. "(e) not exceed 20% opacity at any process flare. Opacity at catalytic cracking units, including those with ESP facilities, shall not exceed 20%, with compliance to be determined in accordance with Subsection (g) above."
COMMENT 210: IX.H.1.h.(2): Compliance demonstrations for refinery wide emission limits - Subsection IX.H.1.h.(2)(a) says "Compliance with the maximum daily (24-hr) plantwide emission limitations for PM10, SO2 and NOx shall be determined by adding the calculated emission estimates for all fuel burning process equipment to those from any stack-tested or CEM-measured source components." This language is not specific enough to be enforceable as a practical matter. For the fuel burning process equipment, standard language from current Approval Orders for the refineries is much more specific and should be used in this section. For the fuel burning process equipment, since this language is standardized for all the refineries, we recommend it be included in the General Requirements at IX.H.1, rather than under each refinery in IX.H.2 as was done in the original PM10 SIP. This will avoid redundancy. Specifically, this has been proposed as "multiplying the quantity of each fuel burned at the affected units by the appropriate emission factor for that fuel and summing the results." This is not specific enough to be enforceable. It should be made clear how the quantity of fuel combusted is to be determined and how the appropriate emission factor is to be determined. This comment applies to the following locations within the proposed section IX.H.2: For Chevron: plantwide PM10 limit, Subsection IX.H.2.c.(1); plantwide SO2 limit, Subsection IX.H.2.c.(2)(a), also the phrase "and summing the results for the affected units" should be added. plantwide NOx limit, Subsection IX.H.2.c.(3)(a) also the phrase "and summing the results for the affected units" should be added. For Flying J/Big West Oil Co. plantwide PM10 limit, Subsection IX.H.2.d.(1), also the phrase "and summing the results for the affected units" should be added. plantwide SO2 limit, Subsection IX.H.2.d.(2)(a)(ii), also the phrase "and summing the results for the affected units" should be added. plantwide NOx limit, Subsection IX.H.2.d.(3)(a)(ii), also there is no statement about how emissions from the fuel burning process equipment are to be determined. For Holly: plantwide PM10 limit, Subsection IX.H.2.h.(1), also the phrase "and summing the results for the affected units" should be added. plantwide SO2 limit, Subsection IX.H.2.h.(2), also the phrase "and summing the results for the affected units" should be added. plantwide NOx limit, Subsection IX.H.2.h.(3)(a), also the phrase "and summing the results for the affected units" should be added. For Tesoro: plantwide PM10 limit, Subsection IX.H.2.q.(1). plantwide SO2 limit, Subsection IX.H.2.q.(2)(a)(ii), also the phrase "and summing the results" should be added. plantwide NOx limit, Subsection IX.H.2.q.(3)(a), also the language should be more consistent with the others. {Comment made by the EPA; C11} RESPONSE 210: DAQ proposes to include additional compliance information in IX.H.1.h.2(a) regarding emission factors as shown below. Also, the source-specific sections cited in the above EPA comments have been edited to read as follows to make the compliance demonstrations more consistent with each other and EPA's proposed changes: "(2) Compliance Demonstrations. (a) Compliance with the maximum daily (24-hr) plant-wide emission limitations for PM10, SO2, and NOx shall be determined by adding the calculated emission estimates for all fuel burning process equipment to those from any stack-tested or CEM-measured source components. NOx and PM10 emission factors shall come from AP-42 or test data. For SOx, the emission factors are: Natural gas: EF = 0.60 lb/MMscf ; Propane: EF = 0.60 lb/MMscf. Plant gas: the emission factor shall be calculated from the H2S measurement required in IX.H.1.h(1)(b). The emission factor, where appropriate, shall be calculated as follows: EF (lb SO2/MMscf gas) = (24 hr avg. ppmv H2S)/10^6 * (64 lb SO2/lb mole) * (10^6 scf/MMscf) /(379 scf / lb mole). Fuel oils (when permitted): The emission factor shall be calculated based on the weight percent of sulfur, as determined by ASTM Method D-4294-89 or approved equivalent, and the density of the fuel oil, as follows: EF (lb SO2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt.% S/100 * (64 lb SO2/32 lb S). Where mixtures of fuel are used in an affected unit, the above factors shall be weighted according to the use of each fuel." SRU TURNAROUND AND UPSET FLARING EMISSIONS:
COMMENT 211: Sections IX.H.1.h.(2)(e) and (f) - These sections say that the emissions increase (above normal operations) experienced during SRU routine turnarounds, as well as emissions due to upset flaring, shall not be included in the daily (24-hr) or annual compliance demonstrations. DAQ needs to address the refinery SRU and flaring issue in the Utah SIP. We partially approved and partially disapproved the Billings/Laurel SO2 SIP for several reasons, including the fact that the flare emissions were considered in the attainment demonstration but the SIP did not establish enforceable emission limits for these emission points. This is also relevant to the commitments made by DAQ in its letter to the EPA dated April 18, 2002. {Comment made by the EPA; C6; includes EPA comments C7, C12 and I5} RESPONSE 211: Concerning SRU maintenance downtime, Part IX.H of the proposed SIP does not excuse any emissions increase above normal operations at the refineries during routine turnaround maintenance of the sulfur recovery units, unless such maintenance is scheduled during the period of April 1 through October 31. These summer months lack the cold temperatures and other atmospheric conditions necessary to drive secondary aerosol formation from PM10 precursors such as SO2. This seasonal approach is consistent with that of the approved SIP, but the proposed SIP revision has essentially added the month of March to the "winter PM10 season." Concerning flares: DAQ has established enforceable limits regarding flares. Under recent consent decrees with a majority of the refineries in the PM10 Maintenance Area, EPA has negotiated federally enforceable language requiring injunctive relief for flares at Salt Lake's refineries. Requirements that have been inserted into the federally enforceable permits include applying the requirements of 40 CFR Part 60, Subpart J, "Standards Performance at Petroleum Refineries" for flaring devices and the requirements to investigate acid gas and tail gas flaring incidents, perform a root cause analysis of the incident and take corrective actions to minimize the likelihood of reoccurrence. The State's position is that the injunctive relief in the consent decrees is adequate to address emissions from flares at the Salt Lake refineries.
COMMENT 212: Flares at refineries should not be exempt from site-wide caps and should be used only for their permitted uses: true emergencies. Flares are a significant episodic source of toxic emissions, particularly when wind prevents complete combustion. Each flare should have a flow meter at the inlet and the waste gas composition should be recorded. Accurate inventories of sulfur content in flare fed streams should be collected and critically analyzed; each flare should be video-monitored and the images preserved. Ambient monitoring should be conducted to determine the effects of wind speed and direction on combustion efficiency and to provide realistic emission factors to calculate the emissions of particulate matter and hydrocarbons. These projects could be undertaken as Supplemental Environmental Projects as settlements for Notices of Violation as they occur. All information should be available to the public, as is done by the Bay Area Air Quality Management District in California; see their web site at http://www/baaqmd.gov. {Comment made by Wasatch Clean Air Coalition} RESPONSE 212: See response to Comment 211.
COMMENT 213: The refineries should install some type of monitoring devices at the flares, because they emit large amounts of measured and unmeasured SO2, NOx, VOC and particulates annually. Also, their combustion efficiency can be much lower, in certain conditions such as high wind speeds, than their historically assumed 98% destruction efficiency. Areas requiring flare monitoring for other pollutants include Billings, MT; California; and Houston, TX. The Billings SO2 SIP requires use of continuous emissions monitoring on refinery flares to measure H2S concentrations. Air quality management districts in California require flow monitors and video monitors. Texas requires continuous flow monitoring systems at flares to measure and record emissions of highly reactive volatile organic compounds (HRVOCs). Monitoring particulates would require different monitoring devices by the above examples provide a precedent for monitoring flare emissions. {Comment made by Environmental Defense and Utah Chapter, Sierra Club} RESPONSE 213: See response to Comment 211. CLARIFICATIONS and CORRECTIONS:
COMMENT 214: On page 2, section IX.H.1.h(1) - refers to the "PM10 nonattainment area." This should be revised to "PM10 maintenance area." {Comment made by the EPA; C4} RESPONSE 214: DAQ will clarify the statement to cover either situation. The sentence at IX.H.1.h.(1) will be revised to read as follows: "All petroleum refineries in or affecting the PM10 nonattainment/maintenance area shall..."
COMMENT 215: IX.H.1.h.(1)(b): H2S content in plant gas at petroleum refineries - The term "plant gas" needs to be defined in the SIP. In section IX.H.1.h.(1)(b), the term apparently means only the fuel gas at refineries which is run through the amine unit for H2S removal. However, in the Approval Orders for the refineries (example: condition 15.A of the April 8, 2005 AO for Chevron), the term could be construed to mean not only the fuel gas which requires H2S removal at the refinery, but also pipeline quality natural gas supplied from outside the refinery. Also, the statement that "Compliance shall be based on a rolling average of 24 hours or less" needs to be reworded to make it clear what specific averaging time shall be used. The expression "24 hours or less" is not specific. {Comment made by the EPA; C8} RESPONSE 215: "Plant gas" as used in this document is intended to have the same meaning as "fuel gas," as defined in 40 CFR Subpart J at 60.101(d): "Fuel gas means any gas which is generated at a petroleum refinery and which is combusted. Fuel gas also includes natural gas when the natural gas is combined and combusted in any proportion with a gas generated at a refinery. Fuel gas does not include gases generated by catalytic cracking unit catalyst regenerators and fluid coking burners." The terms "plant gas," "common refinery fuel gas" and "fuel gas" were used interchangeably in the current PM10 SIP and approval orders. Refinery representatives in the noted meeting agreed on use of the Subpart J language. The averaging time for the H2S limit was stated as "24 hours or less" to allow for use of records of the 3-hr averaging time required in Subpart J at 60.105(e)(3). Refinery representatives agreed to deleting the phrase "or less," in order to maintain consistency with the usual PM10 averaging period. The language in condition IX.H.1.h.(1)(b) will be changed to read as follows: "(b) reduce the H2S content of the refinery plant gas to 0.10 grain/dscf (160 ppm) or less, except during startup, shutdown, or malfunction of the amine plant. Compliance shall be based on a rolling average of 24 hours. The owner/operator shall install and maintain a continuous monitoring system for monitoring the H2S content of the refinery plant gas and a continuous recorder to record the H2S in the plant fuel gas. The monitoring system shall comply with all applicable sections of R307-170 and 40 CFR 60, Appendix B, Specification 7. As used herein, refinery "plant gas" shall have the meaning of "fuel gas" as defined in 40 CFR 60, Subpart J, and may be used interchangeably. If the monitor reading is not available, the refinery plant gas shall be sampled as closely to the monitor location as safely possible at least once each day. The sample shall be analyzed for sulfur content by use of a chemical detector tube capable of reading the required concentration (e.g., Drager Hydrogen Sulfide 1/D or equivalent). For natural gas, compliance is assumed while the fuel comes from a public utility."
COMMENT 216: IX.H.1.h.(1)(c): The State has inserted the phrase "in external combustion equipment." We need to understand the basis for this change to determine whether it is appropriate. {Comment made by the EPA; C9} RESPONSE 216: In IX.H.1.h(1)(c), the text states that refineries "may no longer burn fuel oil in external combustion devices...." The point sources affected by this restriction are intended to be the fuel gas combustion units, such as boilers and furnaces, that combust at atmospheric pressure. There was concern from the refineries that the prohibition as stated in the current SIP ("no longer burn fuel oil" without clarification) did not allow for use of diesel engines used in the refineries. All cited concerns were internal combustion units, so the phrase "in external combustion equipment" was added to the intended restriction. "External combustion" shall be defined in IX.H.1.h.1(c) to incorporate the wording of R307-413-4(1): "(c) no longer burn fuel oil in external combustion equipment, except during periods of natural gas curtailment or as specified in IX.H.2. External combustion shall mean combustion that takes place at no greater pressure than one inch of mercury above ambient pressure."
COMMENT 217: IX.H.1.h.(3)(b) - This section should refer back to IX.H.1.h.(2) (e), not (f). {Comment made by the EPA; C13} RESPONSE 217: DAQ agrees, and will make the appropriate correction to condition IX.H.1.h(3)(b). SIP SECTION IX.H.2. - SOURCE SPECIFIC PARTICULATE EMISSION LIMITATIONS: IX.H.2.A. BOUNTIFUL CITY POWER.
COMMENT 218a. Subsection IX.H.2.a.(1)(a) contains a NOx emission limit of 0.0721 tons/day for a turbine (equivalent to 6.0 lb/hr). The original 1991 PM10 SIP has limits for a 9750-hp engine of 79.5 lb/hr and 3.70 grams/hp-hr (13 times more emissions than the turbine). This is engine No.8, which is listed in the current AO. It would seem important to place limits on engine No.8. RESPONSE 218a: This source is a peaking plant, and operates only intermittently to meet temporary power demands that occur more often in the warm summer months when air conditioners are being used, and less often in the winter when there is less demand for power in general. When the source does operate, the turbine is the primary source of power generation, not the engine. Therefore, for purposes of the PM10 plan, it is the emissions from the turbine that should be included.
COMMENT 218b: Subsection IX.H.2.a.(1)(b) contains a plantwide NOx emission limit only for a rolling 12-month period. A plantwide NOx emission limit in tons per day should also be included. RESPONSE 218b: As explained in the response to comment 218a, it is the turbine that is primarily used to generate power at the plant. As proposed, there is a daily NOx limit on the turbine.
COMMENT 218c. Subsection IX.H.2.a.(3) requires a NOx CEMS be installed, if plantwide NOx emissions exceed 200 tons over a 12-month period. This subsection should say which engine(s) the CEMS would have to monitor (there are 5 other large engines). {Comments made by the EPA} RESPONSE 218c: DAQ finds it difficult to pre-specify the details of a monitoring plan when the reasons triggering the need for monitoring are not yet determined. To insure such monitoring plan yields useful data to verify compliance with established limits, DAQ believes it should retain the ability to tailor the CEMS plan to suit the conditions at the time that the requirement is triggered. IX.H.2.b. CENTRAL VALLEY WATER RECLAMATION FACILITY:
COMMENT 219a: The last two sentences of IX.H.2.b.(1)(b) should be deleted, as they are redundant with General Requirements. RESPONSE 219a: DAQ agrees with this comment and will remove the duplicated sentences.
COMMENT 219b. Also, stack testing should be more frequent than once every five years. Emissions of NOx from engines could change considerably over five years. {Comments made by the EPA} RESPONSE 219b: EPA's comment stems from the argument that NOx emissions from the engines could change considerably over a five-year period. The most recently issued AO for the source (DAQE-AN04145005-02) specifies that the engines shall also be retested whenever a new baseline is established as a result of adjustments in fuel-to-air ratio, maintenance, or repair of the emission unit. DAQ feels that this sort of requirement is most properly placed within the domain of the AO, as it can then be adjusted to become more frequent should the situation necessitate such a change. IX.H.2.c. CHEVRON PRODUCTS CO.:
COMMENT 220a: Subsection IX.H.2.c.(1) does not contain a 12-month limit on plantwide PM10 emissions. It is not clear to us why another refinery in IX.H.2. (Flying J) would have a 12-month limit but Chevron would not. RESPONSE 220a: It was demonstrated in the review for DAQE-243-98 that many of the existing annual limits were equal to or less stringent that the corresponding daily limits. In preparation for title V permits, redundant limits were removed, including the limit addressed here, and only the shorter-term limits were retained.
COMMENT 220b: Subsection IX.H.2.c.(2)(a) says the SO2 emission factor for the FCC CO Boiler and Catalyst Regenerator, as well as compliance with General Requirements at IX.H.1.h(1)(d), shall be determined by a stack test at least once every three years, with SO2 CEMS allowed as an alternative. This subsection should be reworded to require a SO2 CEMS, along with a volumetric flow measurement device. The Chevron Consent Decree, filed October 16, 2003 in U.S. District Court, requires a CEMS to be installed by June 2004. RESPONSE 220b: The CEMS allowed as an alternative monitoring solution for the maintenance plan is a recognition that the consent decree required the installation of a CEMS on the FCC. However, the limits given in the consent decree are all in terms of "ppmvd," or dry concentration; the CEMS already required in the consent decree is sufficient for that limit. The consent decree did not impose mass limits, nor did it require a volumetric flow device. The limits in the MP are in tons/day. The required stack testing is adequate for demonstrating compliance with those limits. The language as written allows Chevron the option to use the consent-decree CEMS for compliance with the mass limits at a later date if it so chooses; at that time, a flow device or other alternate monitoring plan would be required. Also, the comparison to Tesoro is inappropriate. Tesoro is monitoring SOx under an alternative monitoring plan that requires the use of both concentration and flow monitors. Chevron is not under an alternative plan at this time.
COMMENT 220c. It is not clear why no point-specific emission limits are proposed for the FCC CO Boiler and Catalyst Regenerator. The original 1991 PM10 SIP included emission limits for PM10, SO2 and NOx. The emission limit for SO2 was nearly as high as the emission limit for the SRU. The magnitude of emissions would seem to warrant emission limits. {Comments made by the EPA} RESPONSE 220c: Comment on "no point-specific limits for FCC": There are no point-specific limits for the FCC/CO boiler because the FCC and associated equipment was moved under the various emission caps in 2000, and the cap limitations were adjusted appropriately. See DAQE-6323-00. IX.H.2.d. Flying J/Big West Oil Co. :
COMMENT 221a. Subsection IX.H.2.c.(1)(ii) says the PM10 emission factor of 22 lbs/kbbl for the Catalyst Regeneration System "may be re-established by stack testing." This is not an enforceable requirement. This subsection should specify the circumstances or timeframe under which it would be necessary to re-establish the PM10 emission factor by stack testing. RESPONSE 221a: The PM10 emissions from the Catalyst Regeneration System are calculated as: PM10 = F*EF, where F is feed rate to the FCC in kbbl/time and EF is 22 lbs/kbbl. The calculation is enforceable. The language in the maintenance plan is written to allow an update of the emission factor if requested. There is no fixed cycle for revisiting this factor or determined need at this time, nor was there any such language in the existing SIP. During development of the title V permit, a schedule or conditions may be negotiated, and the MP should not interfere with that effort.
COMMENT 221b: Subsection IX.H.2.d.(2)(a)(ii) says the scalar values of 43.3 lb SO2/hr, 7688 bbl feed/day, and 0.1878 wt% sulfur in feed, shall be re-established by stack testing at least every five years. It is not clear to us how stack testing could re-establish a feed rate or a wt% sulfur in feed. This subsection needs clarification. RESPONSE 221b: The current equation for determining SOx emissions is as follows: SOx = [F/x][(wt% sulfur in feed)/(z)][y][hours of operation per day], where F = operational feed rate, bbl/day, for which the SO2 emission is to be calculated; x = Feed rate, bbl/day, at the latest test. Until another test, use x = 7,688 bbl/day; y = SO2 emission rate, lbs/hr, corresponding to x bbl/day feed rate. Until another test, use y = 43.3 lbs/hr; z = Sulfur content, in weight %, measured in feed x at the latest test. Until another test, use Z = 0.1878%. This equation uses ratios, and follows the instructions in the existing SIP for determining the SO2 contribution of the Plume Burner (the exit point for the old TCC). The feed rate, feed sulfur content and SO2 emission rate are determined during a stack test; then the daily process variables (feed rate, feed sulfur content) are measured and inserted into the equation to calculate the current emissions. Future stack tests would allow for changes in the constants (scalar values) of the equation.
COMMENT 221c: Also, once every five years is not frequent enough. The crude slate and the performance of the Catalyst Regeneration System could change considerably in five years. This also appears to be a relaxation of the existing federally approved SIP. The existing SIP requires the weight % sulfur be determined by the refinery lab on a monthly basis and the gravity of the feed determined daily. RESPONSE 221c: Flying J is currently required in its approval order (DAQE-AN0122033-04) to determine feed sulfur content every 30 days and to determine the feed rate daily. The sulfur content monitoring will be included in this source's section of the MP. Changes in the crude that affect SO2 emissions are addressed by this sulfur testing and reflected in the equation above. However, gravity of the feed is not used in any calculation in this MP, so that has not been included. The existing SIP has no stated testing frequency for verifying the constants for this FCC, so the state's five-year rule was used as a default. The language for retesting will be modified to "at least every five years" so that the MP does not interfere with development of a suitable interval in the title V permit.
COMMENT 221d. Subsection IX.H.2.d(a)(ii) says the scalar value of 180 ppm NOx in Catalyst Regeneration System flue gas "may be re-established by stack testing." This is not an enforceable requirement. This subsection should specify the circumstances or timeframe under which it would be necessary to re-establish the scalar value by stack testing. {Comments made by the EPA} RESPONSE 221d: The current equation for determining NOx emission is as follows: NOx = (Flue Gas, moles/hr) x (180 ppm /1,000,000) x (30.006 lb/mole) x (operating hr/day). The calculation is enforceable. The language in the maintenance plan is written to allow an update of the emission factor determined at the last stack test if requested. There is no fixed cycle for revisiting this factor or determined need at this time, nor was there any such language in the existing SIP. During development of the title V permit, a schedule or conditions may be negotiated, and the MP should not interfere with that effort. IX.H.2.f. GENEVA ROCK PRODUCTS, OREM PLANT.
COMMENT 222: Subsection IX.H.2.f.(1) specifies daily emission limits for PM10, SO2 and NOx, but no 12-month limits. It is not clear to us why. {Comment made by the EPA} RESPONSE 122: This comment appears in a number of instances, and the general response is as follows: During the review of the latest permit(s) for these sources it was determined that many of the existing annual limits were equal to or less stringent that the corresponding daily limits. In fact, many of these sources did not have a specified annual limit but instead only had hourly limitations on individual emission units. When DAQ established the daily emission limits for these sources, the corresponding annual limits were established by simply multiplying the daily limit by 365 days. No added value would be realized by the inclusion of an additional and mathematically redundant limitation. IX.H.2.g. GENEVA ROCK PRODUCTS, POINT OF THE MOUNTAIN.
COMMENT 223: Subsection IX.H.2.g.(1) specifies a daily emission limit for PM10, but no 12-month limit. It is not clear to us why not. {Comment made by the EPA} RESPONSE 223: The annual limit was redundant. See response to Comment 222 for a more complete explanation. IX.H.2.h. HOLLY REFINING AND MARKETING CO.
COMMENT 224: Subsection IX.H.2.h.(1) does not contain a 12-month limit on plantwide PM10 emissions. It is not clear to us why another refinery in IX.H.2. (Flying J) would have a 12-month limit but Holly Refining would not. {Comment made by the EPA} RESPONSE 224: The annual limits listed in the current approval order (DAQE-AN0123019-05) are equivalent to and redundant with the daily limits. In preparation for title V permits, redundant limits were removed, including the limit addressed here, and only the shorter-term limits were retained. IX.H.2.i. INTERSTATE BRICK.
COMMENT 225a: Subsection IX.H.2.i.(1) specifies daily emission limits for PM10, SO2 and NOx, but no 12-month limits. It is not clear to us why not. RESPONSE 225a: The annual limitation was redundant. See response to comment No.79 for a more complete explanation.
COMMENT 225b: Also, a stack test frequency of once every five years for PM10 and NOx is not frequent enough. {Comments made by the EPA} RESPONSE 225b: This frequency of stack testing is consistent with the rule (R307-165-1), and is identical to the most recent AO issued to the source (DAQE-296-99). IX.H.2.j. KENNECOTT - BINGHAM CANYON MINE AND COPPERTON CONCENTRATOR. (1) BINGHAM CANYON MINE:
COMMENT 226a: The only proposed limitation for the Mine is a limit on sulfur content of diesel fuel. The original 1991 PM10 SIP has a limit of 27,500,000 gallons per year of fuel consumed and a limit of 150,500,000 tons per year of ore and overburden moved. By eliminating these limits, DAQ would eliminate any enforceable limit on the emission potential of the Mine. This is not acceptable. Since this source is listed in SIP section IX.H.2, there must be enforceable emission limits (or surrogates for emission limits) that reflect the amount of potential emissions used for modeling for NAAQS attainment/maintenance (2,560 tons/yr for PM10, 22.6 tons/yr for SO2, and 5,078 tons/yr for NOx). Also, DAQ should explain why the "modeled PTE" for the Mine is only 22.6 tons/yr for SO2, when the current AO for the Mine lists the PTE for SO2 at 97 tons/yr. RESPONSE 226a: DAQ agrees with this comment. The limitation on ore and overburden moved will be replaced as per the value listed in the AO. The most recent AO for this source (DAQE-178-02) changed the value of this limitation. The limitation will now be 197,000,000 tons per year of ore and overburden moved. The fuel usage limitation is an artifact of the original 1991 SIP, and must be updated to reflect the changes in diesel fuel that are required by recent rules. Rather than limiting the source to a total number of gallons of fuel consumed, DAQ will modify the limitation to read as follows: "Annual emissions of SO2 from the combustion of fuel shall not exceed 97 tons per year. SO2 emissions from fuel burning shall be determined by applying the appropriate emission factors to the relevant quantities of fuel combusted." The general requirements will then cover the recordkeeping and reporting requirements. DAQ will make the revisions discussed above such that IX.H.2.j reads as follows: "j. KENNECOTT UTAH COPPER: MINE and COPPERTON CONCENTRATOR. (1) BINGHAM CANYON MINE: (a) Total material moved (ore and waste) shall not exceed 197,000,000 tons per 12-month period. (b) Annual emissions of SO2 from the combustion of fuel shall not exceed 97 tons per year. SO2 emissions from fuel burning shall be determined using the following equation: tpy SO2 = (gal fuel / year) * (7.05 lb/gal) * (% S by wt.) / 2000 lb/ton * (2 lb SO2 / lb S). (c) The sulfur content of diesel fuel oil burned in the equipment engines shall not exceed 0.03 pounds of sulfur per million BTU heat input as determined by the appropriate ASTM Method. This represents 0.05% sulfur by weight in the fuel oil." DAQ also agrees with the final section of this comment, specifically that the reference to the "modeled PTE of 22.6 tons/yr of SO2, is in error. The correct value should indeed be 97 tons/yr as listed above. The difference between the two values is 75 tpy. Nevertheless, the model is not sensitive to a difference of this magnitude, and any increase or change in the overall impacts as a result of this error would be extremely minor.
COMMENT 226b: The original PM10 SIP includes requirements for control of fugitive emissions at the Mine, including a requirement for a Fugitive Dust Control Plan. A copy of the current approved Fugitive Dust Control Plan is attached to the AO for the Mine, dated March 22, 2002. If emission projections for modeling assume credit for these controls, then the requirements for these controls should be included in section IX.H.2.j. {Comments made by the EPA} RESPONSE 226b: DAQ did not rely on the dust control measures as outlined in the Fugitive Dust Control Plan when establishing the emission projections for modeling. Rather, it was the emission inventory submitted for 2001, in conjunction with the Approval Order, that acted as the basis for the modeled emissions. (2) COPPERTON CONCENTRATOR:
COMMENT 227: The section in Part H applying to the Copperton Concentrator should be deleted, because the rotary kiln has been shut down and removed, and the Molybdenite Plant is being upgraded with improved technology. A Notice of Intent covering these changes was submitted to DAQ on February 8, 2005. The net effect will be reduced emissions for PM10 and NOx, and SO2 emissions will be nearly eliminated. Therefore, there are not now and will not be any sources at the Concentrator with high enough potential to emit to be included in Part H. {Comment made by Kennecott} RESPONSE 227: DAQ agrees. The final Approval Order is about to be issued. The following is the abstract from the engineering review associated with the project: "Kennecott Utah Copper Corporation (KUCC) has requested approval to install a pebble crushing process at KUCC's Copperton Concentrator. The KUCC Copperton Concentrator is currently operating under the Approval Order DAQE-862-01, dated November 20, 2001. KUCC intends to add two pebble-crushing units and related material handling equipment. This will allow KUCC to increase the throughput of copper ore through the concentrator and improve process efficiency. KUCC has stopped operation of the Feed Molybdenite Dryers and Molybdenite Rotary Kiln and has requested that they be removed from the AO. The stack testing requirements for this equipment and for the Product Molybdenite Dryers have been removed. KUCC is also requesting replacement of one of its product molybdenite dryers and associated heater with a larger product molybdenite dryer that will use the existing product molybdenite dryer scrubber and one of the existing feed molydbenite dryer heaters to supply hot oil to the new product molybdenite dryer. New Source Performance Standards (NSPS) Subpart LL (Standards of Performance for Metallic Mineral Processing Plants) apply to this source. Title V of the 1990 Clean Air Act applies to this source. Salt Lake County is a non-attainment area of the National Ambient Air Quality Standards (NAAQS) for PM10 and SO2, and is a maintenance area for ozone. The KUCC Copperton Concentrator is also included as a regulated PM10 source in the Salt Lake County PM10 State Implementation Plan (SIP). This AO modification will result in a modification to the existing SIP limits. Therefore, this modification will require approval by the AQB. The emissions will decrease in tons per year (tpy) as follows: PM10 = 1.19, SO2 = 86.30, NOx = 6.95, CO = 5.84, VOC = 23.38. The changes in emissions will result in the following, in tons per year, potential to emit totals: PM10 = 7.35, SO2 = 0.10, NOx = 10.75, CO = 9.06, and VOC = 2.32." Subsection IX.H.2.j will be modified to remove paragraph (2) Copperton Concentrator. IX.H.2.k. KENNECOTT POWER PLANT AND TAILINGS IMPOUNDMENT. (1) For the Power Plant:
COMMENT 228a: Subsection IX.H.2.k.(1)(a) should be re-arranged to make clear what fuel consumption limits (or emission limits) apply to the Power Plant outside of the period Nov-Feb. {Comment made by the EPA} RESPONSE 228a: DAQ agrees, and will insert the appropriate conditions from the most recent Approval Order. See revised construct of Section IX.H.2.k.(1) below.
COMMENT 228b: In condition (a)(ii), the fuel limits should be expressed in terms of Btu/day, not volume or weight of fuel. The language should match that used in the revised Approval Order [NOTE: the new Approval order was approved by the AQB on May 11, 2005.] {Comment made by Kennecott} RESPONSE 228b: DAQ agrees, and will insert the appropriate conditions from the most recent Approval Order. See revised construct of Section IX.H.2.k.(1) below.
COMMENT 228c: Regarding Kennecott's Power Plant (IX.H.2.k), We request that (a) - (e) be added after requirements in the first sentence. {Comment made by Kennecott} RESPONSE 228c: DAQ agrees in concept, but will instead add the appropriate clarification into this statement. Note that the summertime limits will be included as well (see comment 85a above). See revised construct of Section IX.H.2.k.(1) below.
COMMENT 228d: In conditions (a)(iii) and (iv), "and concentrations" should be deleted because all the limits for all sources in Part H are in tons/day. {Comment made by Kennecott} RESPONSE 228d: DAQ agrees. See revised construct of Section IX.H.2.k.(1) below.
COMMENT 228e: Subsection IX.H.2.k.(1)(e) says metering of natural gas to the boilers "shall be installed if necessary." This same language appears in the original 1991 PM10 SIP. Thirteen years has passed, and the State should make a determination. {Comment made by the EPA} RESPONSE 228e: DAQ agrees, and will insert the appropriate language from the most recent Approval Order, which no longer includes this option. Note that this language (paragraph (f)) is slightly different than what was proposed given that the fuel consumption limits are now expressed in terms of MMBTU per day. See revised construct of Section IX.H.2.k.(1) below.
COMMENT 228f: Subsection IX.H.2.k.(1)(f) says that the requirements in IX.H.2.k.(1) for the Power Plant apply "unless and until" a Notice of Intent is submitted for "specific technologies" and an Approval Order is issued. This subsection goes on to discuss the Approval Order and the Title V Operating Permit. The entire subsection IX.H.2.k.(1)(f) is unacceptable and must be removed. PM10 SIP requirements cannot be made contingent on issuance of Approval Orders, nor can Approval Orders supersede the PM10 SIP. Treatment of requirements in permits that might serve as alternatives to SIP requirements is already addressed in section IX.H.3. of the PM10 Maintenance Plan. {Comment made by the EPA} RESPONSE 228f: Subsection IX.H.2.k.(1)(f), as proposed, requires the issuance of an Approval Order as only one of a sequence of events that would need to occur in order to alter the proposed SIP requirements. As foreseen, this process would need to address a RACT determination made in the original PM10 SIP, whereby the Utah Power Plant was required to burn natural gas during the winter. That determination was made fifteen years ago when the price of natural gas was significantly lower than it is at the present. Given today's economics, it may be for example that the combination of a baghouse with lime injection and low NOx burners would represent a more economical RACT (with summertime benefits for ozone as well). Since the CAA requires RACT, at a minimum, to demonstrate attainment/maintenance of the NAAQS, the emissions from such technology would have to be modeled to ascertain as much. Such modeling has also been included as a necessary step in paragraph (f), yet no such requirement exists in section IX.H.3. RACT however is less stringent than BACT, and this is precisely why the Approval Order process, as outlined in R307-401, has been included as a necessary step in this process. R307-401 requires a BACT analysis as part of any Approval Order issued by the Executive Secretary. Should the Executive Secretary be able to make such a finding and issue an AO, the BACT requirements would then be eligible for inclusion in a Part 70 permit, just as is required by section IX.H.3. The Part 70 process would give the EPA veto authority over any such permit, approval of which is yet another required element in the process outlined in paragraph (f). It is not until the Part 70 permit becomes effective, after approval by EPA, that the requirements contained therein would supercede the requirements in the SIP. Hence, DAQ disagrees with the comment, and will leave the condition as proposed.
COMMENT 228g: Finally, Kennecott agrees with DAQ's approach for addressing future RACM by specifying how such a modification would be adopted as part of an Approval order, Title V permit, and incorporation into the SIP. Specifically, concurs with condition (f)(vii) that incorporates into the SIP only the Title V provisions that are appropriate for the SIP. However, the new section IX.H.3 does not address the circumstance where the SIP specifies the process for RACM (RACT) modification. It appears that IX.H.3 would create an inconsistency with subsection (f) in IX.H.2.k. We recommend adding the following sentences at the end of IX.H.2.k(1)(f)(vii): "As of the effective date of the Operating Permit, the PM10. SO2, and NOx emission limits for the Utah Power Plant boilers, including applicable monitoring requirements, set forth in that permit as most recently amended, shall become incorporated by reference into the Utah SIP. Henceforth, those terms and conditions specified in the operating Permit shall supersede conditions (a) - (e) above. The implementation of this subsection (f) shall not require compliance with the provisions of Subsection IX.H.3." {Comment made by Kennecott} RESPONSE 228g: The procedure outlined in condition H.2.k.(1)(f) establishes a process that could be used to establish a new RACT determination for the Kennecott Power Plant. If this procedure is followed, then Kennecott will be in compliance with the SIP and it will not be necessary for Kennecott to establish an alternative requirement under Subsection IX.H.3. The suggested language is not necessary in this case. Provided below is a markup copy of the proposed Subsection IX.H.2.k.(1) which reflects the responses to Comments 228a - g. "k. KENNECOTT UTAH COPPER: POWER PLANT and TAILINGS IMPOUNDMENT. (1) UTAH POWER PLANT. The following requirements, subsections (a) through (f), are applicable unless and until the owner/operator has complied with the requirements set forth in Subsection (g) below. (a) During the period from November 1, to the last day in February, inclusive, the following conditions shall apply: (i) The four boilers shall use only natural gas as a fuel, unless the supplier or transporter of natural gas imposes a curtailment. The power plant may then burn coal, only for the duration of the curtailment plus sufficient time to empty the coal bins following the curtailment. (ii) Fuel usage shall be limited to the following: (A) 42,706 MMBTU per day of natural gas; (B) 31,510 MMBTU per day of coal, only during curtailment of natural gas supply. (iii) Natural gas used as fuel: Except during a curtailment of natural gas supply, emissions to the atmosphere from the indicated emission point shall not exceed the following rates: (A) For each of boilers 1, 2, and 3: NOx 1.91 ton/day. (B) For boiler 4: NOx 3.67 ton/day. (iv) Coal used as fuel: Emissions to the atmosphere from the indicated emission point shall not exceed the following rates: (A) For each of boilers 1, 2, and 3: (I) PM10 0.208 ton/day; (II) NOx 2.59 ton/day; (B) For boiler 4: (I) PM10 0.402 ton/day; (II) NOx 4.52 ton/day. (v) Owner/operator shall provide monthly reports to the Executive Secretary showing daily total emission estimates based upon boiler usage, fuel consumption and previously available results of stack tests. (b) During each annual period from March 1 to October 31, inclusive, the following conditions shall apply: (i) KUCC shall use coal, natural gas, oils that meet all the specifications of 40 CFR 266.40(e) and contains less than 1000 ppm total halogens, and/or number two fuel oil or lighter in the boilers. (ii) The following limit on fuel usage shall not be exceeded: 50,400 MMBTU per day of heat input. (iii) Emissions to the atmosphere from each emission point shall not exceed the following rates and concentrations: (A) For each of boilers 1, 2 and 3: (I) PM10 0.208 ton/day; (II) NOx 2.59 ton/day; (B) For boiler 4: (I) PM10 0.402 ton/day; (II) NOx 4.52 ton/day. (c) Stack testing to show compliance with the above emission limitations shall be performed as follows for all four boilers and the following air contaminants: Pollutant and Testing Frequency: (i) NOx every year; (ii) PM10 every year. The heat input during all compliance testing shall be no less than 90% of the design rate. To determine mass emission rates (ton/day) the pollutant concentration as determined by the appropriate methods shall be multiplied by the volumetric flow rate and any necessary conversion factors to give the results in the specified units of the emission limitation. The limited use of natural gas during startup, for maintenance firings and break-in firings does not constitute operation and does not require stack testing. (d) Visible emissions from the boiler stacks shall not exceed the associated opacity on a six-minute average, based on 40 CFR 60, Appendix A, Method 9, or as measured by a Continuous Opacity Monitor except as provided for in R307-201-1(7): (i) Natural Gas as Fuel 10% opacity. (ii) Coal as Fuel 20% opacity. (e) The sulfur content of any fuel burned shall not exceed 0.52 lb of sulfur per million Btu (annual running average), nor shall any one test exceed 0.66 lb of sulfur per million Btu. The owner/operator shall submit monthly reports of sulfur input to the boilers. The reports shall include: sulfur content, gross calorific value and moisture content of each gross coal sample, the gross calorific value of all coal and gas, the total amount of coal and gas burned, and the running annual average sulfur input calculated at the end of each month of operation. (f) To determine compliance with a daily limit owner/operator shall calculate a daily limit. The BTU limit shall be determined by monitoring the daily natural gas, and/or coal consumption and multiplying that value with the BTU rating of the fuel consumed. The natural gas BTU used shall be that value supplied by the natural gas vendor from the previous months bill. The BTU limit for coal shall be determined by monitoring the daily coal consumption and multiplying that value with the coal BTU rating. KUCC shall provide test certification for each load of coal received. Test certification for each load received shall be defined as test once per day for coal received that day from each supplier. Certification shall be either by their own testing or test reports from the coal marketer. Records of BTU fuel usage shall be kept on a daily basis. (g) The requirements set forth in conditions (a) - (f) above shall apply at the Utah Power Plant unless and until the following occur: (i) A Notice of Intent is submitted to the Executive Secretary, pursuant to the procedures of R307-401, that describes the specific technologies that will be used. (ii) An Approval Order is issued that authorizes implementation of the approach set forth in the Notice of Intent. (iii) Notwithstanding the requirements specified in R307-401, the Notice of Intent must demonstrate that the technologies specified in the Approval Order would represent Reasonably Available Control Measures (RACM), as required by Section 172(c)(1) of the Clean Air Act. (iv) To the extent that the current SIP requirements outlined above in conditions (a) - [(f)][(e)] above have been relied upon by the Utah SIP to satisfy Section 172(c)(4) or Section 175A(a) of the Clean Air Act, demonstrate that the technologies specified in the Approval Order would also provide for attainment or maintenance of the National Ambient Air Quality Standards. The demonstration required in this paragraph may incorporate modeling previously conducted by the State for the purpose of a maintenance demonstration. (v) The technologies specified in the Approval Order have been installed and tested in accordance with the Approval Order. (vi) The terms and conditions of the Approval Order implementing the approach set forth in the Notice of Intent have been incorporated into a Title V Operating Permit, in accordance with R307-415. (vii) As of the effective date of the Operating Permit, the PM10 SO2 and NOx emissions limits for the Utah Power Plant boilers, including applicable monitoring requirements, set forth in that permit as most recently amended , shall become incorporated by reference into the Utah SIP. Henceforth, those terms and conditions specified in the Operating Permit shall supersede conditions (a) - (f) above." FOR THE TAILINGS IMPOUNDMENT:
COMMENT 229a: The approach of incorporating the Title V permit by reference (IBR) is not acceptable, for several reasons. First, no specific edition of the Title V permit is referenced. Second, Utah can amend the Title V permit without going through a SIP revision process. Third, the Title V permit expires after 5 years. Fourth, there is considerable language in the Title V permit about other Kennecott operations that is extraneous to the Tailings Impoundment. This IBR approach is also unacceptable because the Federal Register notice that EPA will be publishing on the PM10 Maintenance Plan must reference a SIP submittal that contains the requirements directly, not reference a submittal that references other documents for source-specific requirements. We are aware that DAQ proposes to issue an updated AO for the Tailings Impoundment, after presenting it to the Utah AQB for approval in May of 2005. The draft AO has already gone through public comment period. We have examined the draft AO and find that AO conditions 9 through 21, along with Appendix A of the AO, are specific requirements that should be included in section IX.H.2.k.(2) of the PM10 Maintenance Plan. {Comment made by the EPA}
COMMENT 229b: Part A, page 34, line 20 says "The terms of this dust plan have been incorporated into the SIP at Section IX, Part H." The specific requirements for the North Tailings Impoundment should be explicitly incorporated into Part H, not incorporated by reference along with everything else in the Title V permit. For all sources except the Kennecott Tailings Impoundment, DAQ has removed all but essential detail from the SIP; Kennecott recommends the same approach be used for the Tailings Impoundment. The items that should be included in the emissions limits address the cycle time, the tailings distribution system, revegetation of the North Impoundment, dust from the embankment, stabilization methods, and requirements for a temporary or permanent shutdown. {Comment made by Kennecott} RESPONSE 229: DAQ staff recommends including specific conditions for the Kennecott Tailings Impoundment in Part H of the PM10 SIP as suggested in the above comments. Recommended Staff SIP conditions incorporate all of the above except for the incorporation of Appendix A (Fugitive Dust Plan). Appendix A was not included for the following three reasons: 1) Many of the conditions in the Fugitive Dust Plan duplicate the conditions already found in the SIP. 2) Many of the conditions in the Fugitive Dust Plan have little or no bearing on dust control and the site. 3) Many of the conditions in the Fugitive Dust Plan provide information and requirements that are not appropriate to be included in the SIP. The following is the recommended language to be incorporated in Part H of the PM10 SIP: "Section IX, Part H.2.k. (2) TAILINGS IMPOUNDMENT: (a) Visible emissions caused by fugitive dust shall not exceed 10% at the property boundary, and 20% onsite except during periods when wind speeds exceed the value specified in UAC R307-309 and control measures in the most recently approved dust control plan are being taken. The fugitive dust control plan shall utilize the fugitive dust control strategies listed in UAC R307-205 and R307-309. (b) Kennecott shall submit reports and conduct on site inspections on the fugitive dust abatement program activities for the executive secretary as specified in the most current Approval Order and operating permit. (c) All unpaved roads and other unpaved operational areas that are used by mobile equipment shall be water sprayed or chemically treated to control fugitive dust. Treatment shall be of sufficient frequency and quantity to maintain the surface material in a damp/moist or crusted condition. (d) On the North Tailings Impoundment, as the embankment cells are filled during continual raising of the embankment, dust shall be controlled by the inherent high water content of the hydraulically placed cyclone underflow. Portions of the embankment that are not under active construction shall be kept wet or tackified by applying chemical stabilizing agents or water pumped from the toe ditch. Newly formed exterior slopes shall be stabilized with chemical stabilizing agents or vegetation. (e) Disturbed or stripped areas of the North Tailings Impoundment shall be kept sufficiently moist during the project to minimize fugitive dust. This control, or other equivalent control methods, shall remain operational during the project cycle and until the areas have been reclaimed. The control methods used shall be operational as needed 24 hours per day, 365 days per year or until the area has been reclaimed. (f) The minimum cycle time required for wetting all interior beach areas of the North Impoundment between February 15 and November 15 shall be at least every four days. (g) On the North Tailing Impoundment Kennecott shall conduct wind erosion potential inspections monthly between February 15 and November 15. The tailings distribution system consisting of the North Tailing Impoundment shall be operated to maximize surface wetness. Wind erosion potential is the area that is not wet, frozen, vegetated, crusted or treated and has the potential for wind erosion. No more than 50 contiguous acres or more than 5% of the total North tailings area shall be permitted to have the potential for wind erosion. If it is determined that the total surface area with the potential for wind erosion is greater than 5%, or at the request of the Executive Secretary, inspections shall be conducted once every five working days. Kennecott shall immediately initiate the revised inspection schedule and the results reported to the Executive Secretary within 24 hours of the inspection. The schedule shall continue to be implemented until Kennecott measures a total surface with the potential for wind erosion of less than or equal to 5%. If Kennecott or the Executive Secretary, determines that the percentage of wind erosion potential is exceeded, Kennecott shall meet with the Executive Secretary, or Executive Secretary's staff, to discuss additional or modified fugitive dust controls/operational practices, and an implementation schedule for such, within five working days following verbal notification by either party. (h) On the closed South Tailings Impoundment Kennecott shall conduct wind erosion potential inspections on inactive non-reclaimed areas monthly between February 15 and November 15. No more than 50 contiguous acres or more than 5% of the South Tailings impoundment tailings area shall be permitted to have the potential for wind erosion. Wind erosion potential is the area that is not wet, frozen, vegetated, crusted or treated and has the potential for wind erosion. Inactive but non-reclaimed areas are to be stabilized by chemical stabilizing agents, ponded water, sprinklers, vegetation or other methods of fugitive dust control. If it is determined by Kennecott or the Executive Secretary, that the total surface area with the potential for wind erosion is greater than 5% of total tailings area, or at the request of the Executive Secretary, inspections shall be conducted once every five working days. Kennecott shall immediately initiate the revised inspection schedule and the results reported to the Executive Secretary within 24 hours of the inspection. The schedule shall continue to be implemented until Kennecott measures a total surface with the potential for wind erosion of less than or equal to 5% total tailings area. If Kennecott or the Executive Secretary, determines that the percentage of wind erosion potential is exceeded, Kennecott shall meet with the Executive Secretary, or Executive Secretary's staff, to discuss additional or modified fugitive dust controls/operational practices, and an implementation schedule for such, within five working days following verbal notification by either party. (i) Exterior tailings impoundment areas determined by Kennecott or the executive secretary to be sources of excessive fugitive dust shall be stabilized through vegetation cover or other approved methods. The exterior tailings surface area of the North Impoundment shall be re-vegetated or stabilized so that no more than 5% of the total exterior surface area shall be subject to wind erosion. (j) If between February 15 and November 15 of each calendar year Kennecott's weather forecast is for a wind speed at more than 25 mph for more than one hour within 48 hours of issuance of the forecast, the procedures listed below shall be followed: A. Alert the DAQ promptly. B. Continue surveillance and coordination. (k) If a temporary or permanent shutdown occurs that would affect any area of the Kennecott Tailings Impoundment, Kennecott shall submit a final dust control plan for all areas of the Tailings Impoundment to the Executive Secretary for approval at least 60 days prior to the planned shutdown. IX.H.2.l. KENNECOTT SMELTER and REFINERY. FOR THE SMELTER:
COMMENT 230a: Subsection IX.H.2.l.(1)(a)(i)(B) lists allowable SO2 emissions at the main stack as 5,700 lb/hr on a 24-hour average and 3,240 lb/hr on an annual average. These are the same allowable emissions listed in the 1991 PM10 SIP. After the original PM10 SIP was promulgated, Kennecott modernized the smelter and banked the emission reductions. (Reference: State "banking order" to Kennecott dated June 9, 1999, lists 17,685.50 tons per year of banked SO2 emissions.) Since the current Approval Order for the Smelter allows only 211 lb/hr on an annual average, it appears that 13,267 tons per year of banked SO2 emissions are to be given back to Kennecott, in terms of increased allowable emissions at the main stack: (3240-211) lb/hr x 8760 hr/yr/2000 lb/ton = 13,267 tons/yr increase. It is our understanding that the State intends to allow these 13,267 tons/yr of emissions to also remain in the bank, available for sale from Kennecott to other sources. This constitutes double-counting of emission credit and is not acceptable. {Comment made by the EPA} RESPONSE 230a: The larger limits were included in Part H with the idea of preserving the banked emissions (ERCs). The thinking was that if they had not been relied upon then it might be construed that the difference between the limits in the AO and those in the SIP was no longer creditable. What was actually modeled however, was the smaller limits plus the banked ERCs. These then add back up to the higher limits. Since the banked ERCs were included in the modeling, they were relied upon in the demonstration. So long as this is generally understood, then DAQ agrees with EPA, and will put the lower limits into the SIP. See revised construct of Section IX.H.2.l.(1)(a)(i) below.
COMMENT 230b: Also, there appears to be conflicting information in the PM10 Maintenance Plan regarding what SO2 emission rate at Kennecott's main stack was used for modeling. Volume VII of the Technical Support Document, at page 3.b.iv-1, says that, regarding "the SO2 emission credits attributed" to the Kennecott smelter, "4,328 tpy was modeled at ground level, like all other banked emissions, but the remaining 12,567 tpy was modeled as if they were emitted from the 1,200 foot tall stack." Page 3.b.iii-120, however, lists the "modeled PTE" for SO2 at 867.22 tons/yr for "Smelter - Fugitives," 867.22 tons/yr for "Copper smelting (main stack)" and 213.16 tons/yr for "recycle and crushing." The total is only 1,947.6 tons/yr of SO2 emissions. The State should explain, and reconcile if necessary, the apparent discrepancy between these two pages of the Maintenance Plan. {Comment made by the EPA} RESPONSE 230b: There is no discrepancy between the totals described in the comment. The SO2 emission credits attributed to the Kennecott Smelter, described at Volume VII of the Technical Support Document, at page 3.b.iv-1, are the banked emissions or ERCs presently held by Kennecott. The origin of the ERCs from the smelter could be grouped into two categories; ground level "fugitive" emissions and 2) emissions eminating directly from the 1,200 foot stack (see existing SIP; Table IX.A.13, page 4 of 5 for distinction). In the model, 4,328 tpy was represented as low-level SO2 and 12,567 tpy was assigned to the 1,200 foot stack. The model also included allowable emissions from the smelter. These emissions are documented at page 3.b.iii-120, and do in fact show 1,947.6 tons/yr of SO2 emissions (867.22 tons/yr for "Smelter - Fugitives," 867.22 tons/yr for "Copper smelting (main stack)" and 213.16 tons/yr for "recycle and crushing.") However, as pointed out in Comment 100, this total has incorrectly "double-counted" the 867.22 tons/yr of emissions from the smelter. If this error had underestimated the inventory, DAQ would have re-run the modeling analysis using the correct numbers. Because the change overestimated emissions, the conclusions of the analysis are not affected. See also the response to Comment 243.
COMMENT 230c: Subsection IX.H.2.l.(1)(a)(ii) proposes an allowable SO2 concentration in acid plant tailgas of 1,050 ppmdv on a 3-hr rolling average. No other ppmdv limits are proposed for the acid plant. This is not acceptable. The original PM10 SIP specified 650 ppmdv on a 6-hr average as RACT. We have no information to suggest that 1,050 ppmdv on a 3-hr average should be considered at least as stringent as 650 ppmdv on a 6-hr average. We are aware that EPA approved a revision to the SO2 SIP several years ago that included a figure of 1,050 ppmdv on a 3-hr average, but that SIP revision also retained the figure of 650 ppmdv on a 6-hr average (i.e., both limits must be met, not just the 1,050). EPA has never approved the removal of the 650 ppmdv limit. Considering that the current Approval Order for the Smelter, dated December 22, 2000, allows only 250 ppmdv on a 6-hr average, 170 ppmdv on a 24-hr average, and 100 ppmdv on an annual average, we consider 650 ppmdv on a 6-hr average to be easily achievable and see no justification to remove it from the SIP. {Comment made by the EPA} RESPONSE 230c: The limit of 1,050 ppmdv SO2 on a 3-hr average was retained for the purpose of the SO2 plan. Recall that for the SO2 NAAQS there is a 3-hr secondary standard of 0.5 ppm. For PM10, it was felt that, in general, there was no need for a limit on the acid plant tail-gas concentration since these emissions are ultimately released from the 1,200 foot stack, and there are already mass emission limits governing that release point. Nevertheless, EPA makes a good point that the tail-gas concentration was a significant element of the original RACT determination for the PM10 SIP. DAQ concurs that the 6-hr. limit of 650 ppmdv should be retained in Part H, and will make the necessary addition. See revised construct of Section IX.H.2.l.(1)(a)(ii) below.
COMMENT 230d: Subsection IX.H.2.l.(1)(c)(i) says Kennecott "shall calibrate, maintain and operate the measurement systems for continuously monitoring SO2 and NOx concentrations and stack gas volumetric flow rates in the main smelter stack." This language is not specific enough for practical enforceability. This subsection should include the language from condition 10 of the current AO dated December 22, 2000. {Comment made by the EPA} RESPONSE 230d: DAQ agrees that additional specificity is needed, but does not think that the language from the Approval Order is necessary. There are other instances within the proposed Part H where CEMs are required to demonstrate compliance with various emission limits. In every such case, (Chevron's and Flying J's and Holly's say "that meets the requirements of R307-170." Tesoro's says "...that meets or exceeds the requirements contained in 40 CFR 60, Appendix B, Performance Specification 2." Pacificorp (Gadsby's) says "...as required by 40 CFR Part 75 for the Acid Rain Program.") a reference was made to an existing regulation that already contains such details. DAQ will add the appropriate reference to Subsection IX.H.2.l.(1)(c)(i). See revised construct of Section IX.H.2.l.(1)(c)(i) below.
COMMENT 230e: Regarding the Kennecott Smelter (IX.H.2.l), we see no rationale for keeping the opacity limit for the acid plant tailgas, because the gas is SO2 and it is invisible. The 15% opacity limit will remain in the Approval Order and the Title V permit, and the NSPS opacity limit continues to apply. We request that condition (d)(ii) and the reference to tailgas in condition (d)(iii) be deleted. {Comment made by Kennecott} RESPONSE 230e: DAQ agrees that this condition is not necessary as part of the SIP. The acid plant tailgas is ducted to the 1,200 foot stack which has an opacity limit at its release to the atmosphere. See revised construct of Section IX.H.2.l.(1)(d) below.
COMMENT 230f: In condition (c)(ii), first line, change "permittee" to "owner/operator." {Comment made by Kennecott} RESPONSE 230f: DAQ agrees, and will make the necessary revision. See revised construct of Section IX.H.2.l.(1) below.
COMMENT 230g: Condition (e) has been copied directly from the Title V permit and reads like a permit; subpart (iii) can be deleted, and perhaps subpart (i) as well. If subpart (i) is kept, delete for this permit condition. {Comment made by Kennecott} RESPONSE 230g: DAQ agrees, and will make the necessary revisions. See revised construct of Section IX.H.2.l.(1) below.
COMMENT 230h: In the last paragraph of condition (f), the reference should be corrected (f), not (g). {Comment made by Kennecott} RESPONSE 230h: DAQ agrees, and will make the necessary revision. See revised construct of Section IX.H.2.l.(1) below. Provided below is the revised Subsection IX.H.2.l.(1) which reflects the responses to Comments 230a - h: "l. KENNECOTT UTAH COPPER: SMELTER and REFINERY. (1) SMELTER: (a) Emissions to the atmosphere from the indicated emission points shall not exceed the following rates and concentrations: (i) Main Stack (Stack 11) (A) PM10 89.5 lbs/hr (24 hr. average). (B) SO2 (I) 552 lbs/hr (3 hr. average - rolling); (II) 422 lbs/hr (24 hr. average - calendar day); (III) 211 lbs/hr (annual average). (C) NOx 35.0 lbs.hr (annual average). (ii) Acid Plant Tail Gas. SO2 (I) 1,050 ppmdv (3 hr. rolling average); (II) 650 ppmdv (6 hr. rolling average). All annual average emissions limits shall be based on rolling 12-month averages. Based on the first day of each month, a new 12-month total shall be calculated using the previous 12 months. Reference to stack in Condition No.1 above and Condition No.2 below may not necessarily refer to an exhaust point to the atmosphere. Many emission sources are commingled with emissions from other sources and exit to the atmosphere from a common emission point. "Stack" in these conditions refers to the point prior to mixing with emissions from other sources. (b) Stack testing to show compliance with the emissions limitations of Condition (a) above shall be performed as specified below: Emission Point, Pollutant, and Test Frequency: (i) Main Stack: PM10, every year (Stack 11); SO2 CEM; NOx CEM. (ii) Acid Plant Tailgas, SO2, CEM. (c) Testing Status (To be applied to (a) and (b) above) (i) To demonstrate compliance with the main stack mass emissions limits for SO2 and NOx of Condition (a)(i) above, KUC shall calibrate, maintain and operate the measurement systems for continuously monitoring SO2 and NOx concentrations and stack gas volumetric flow rates in the main smelter stack. Such measurement systems shall meet the requirements of R307-170. (ii) In addition to the stack test required to measure PM10 in (b) above, the owner/operator shall calibrate, maintain and operate a system to continuously measure emissions of particulate matter from the main stack. For purposes of determining compliance with the emission limit, all particulate matter collected shall be reported as PM10. Compliance with the main stack emission limit for PM10 shall be demonstrated using the smelter main stack continuous particulate sampling system to provide a 24-hour value. The owner/operator may petition the AQB at any time to discontinue the operation of the continuous monitor. An analysis of the potential PM10 uncontrolled emissions from the main stack shall be submitted to the Executive Secretary at the time of such a petition. (iii) The owner/operator shall install, calibrate, maintain, and operate continuous monitoring systems on the acid plant tail gas. (iv) All monitoring systems shall comply with all applicable sections of R307-170. (v) KUC shall maintain records of all measurements necessary for and including the expression of PM10, SO2 and NOx emissions in terms of pounds per hour. Emissions shall be calculated at the end of each day for the preceding 24 hours for PM10, SO2 and NOx and calculated at the end of each hour for the preceding three-hour period for SO2. Results for each measurement or monitoring system and reports evaluating the performance of such systems shall be summarized and shall be submitted to the Executive Secretary within 20 days after the end of each month. (d) Visible emissions from the following emission points shall not exceed the following values: (i) Smelter Main Stack (stack 11), 20% opacity. (ii) Sources equipped with continuous opacity monitors (acid plant tailgas and main stack) shall use the compliance methods contained in 40 CFR 60.11. (e) All gases produced during smelting and/or converting which enter the primary gas handling system shall pass through an online sulfuric acid plant. During the start-up/shutdown process of any equipment, the gas emissions shall be ducted, as necessary, either to the acid plant or to the secondary scrubber for control. (i) A log shall be kept of any time the gases produced during smelting and/or converting are not passed through an online sulfuric acid plant. An additional log shall be kept and include the dates, times and durations of all times any gases from smelting and/or converting bypass both the acid plant and the secondary gas system. The log will serve as the monitoring requirement. (f) The owner/operator shall employ the following measures for reducing escape of pollutants to the atmosphere and to capture emissions and vent them through a stack or stacks: (i) Maintenance of all ducts, flues, and stacks in such a fashion that leakage of gases to the ambient air will be prevented to the maximum extent practicable. (ii) Operation and maintenance of gas collection systems in good working order. (iii) Making available to the Executive Secretary the preventive/routine maintenance records for the hooding systems, dust collection mechanism of waste heat boilers, furnace wet scrubbing systems, and dry electrostatic precipitators. (iv) Weekly observation of process units. (v) Monthly inspection of gas handling systems. (vi) Maintenance of gas handling systems, available on call on a 24-hour basis. (vii) Operation and maintenance of an upwind/downwind fugitive monitoring system. The owner/operator may petition the Executive Secretary to discontinue the operation of this system. (viii) Contained conveyance of acid plant effluent solutions. Within 90 days of approval of these conditions, KUC submitted to the Division examples of the forms and records that will be used to comply with Conditions (f) (iv) and (v) above. KUC may modify these forms and records after approval in accordance with R307-401-1. (g) Secondary hoods and ventilation systems shall be installed on the following points to capture fugitive emissions into the secondary ventilation system or other approved pollution control devices: (i) Concentrate Dryer Feed Chute. (ii) Slag and Matte Granulators. (iii) Smelting and Converting Furnaces. (iv) Slag Pot Filling Stations." FOR THE REFINERY:
COMMENT 231. The KUC Refinery should have one limit on NOx that covers both boilers combined, as is done for petroleum refineries, the Gadsby Power Plant, and several small power plants. There should not be a separate limit for each boiler. {Comment made by Kennecott} RESPONSE 231: DAQ agrees, and will revise the language to read as follows: "(a) Emissions to the atmosphere from the indicated emission point shall not exceed the following rate: Emission Point and Maximum Emission Rate: The sum of Two (Tankhouse) Boilers 0.11 tons NOx / day" IX.H.2.m. PACIFICORP GADSBY POWER PLANT.
COMMENT 232a: Subsection IX.H.2.m.(1) contains a daily plantwide NOx emission limit but no 12-month plantwide NOx emission limit. It is not clear to us why. RESPONSE 232a: The annual limit was redundant. See the response to comment 79 for a more complete explanation.
COMMENT 232b: Also, the fourth sentence in subsection IX.H.2.m.(1) is redundant with the third sentence and should be deleted. RESPONSE 232b: DAQ agrees with this comment. The redundant sentence will be removed.
COMMENT 232c: Subsection IX.H.2.m.(2) contains a 12-month plantwide PM10 emission limit but no daily plantwide PM10 emission limit. It is not clear to us why. RESPONSE 232c: The sources in question (three primary boilers and three combustion turbine/generators) burn nothing but natural gas, and as such have never been subject to an hourly PM10 limitation.
COMMENT 232d: Also, this subsection says that PM10 emissions from all boilers and turbines shall be determined by using emission factors from AP-42. It is not clear to us why PM10 stack tests should not be required, at least at a representative boiler and turbine, if not all boilers and turbines. {Comments made by the EPA} RESPONSE 232d: PM10 emission estimates for this source are based on AP-42 emission factors. This is reflected in the most recent AO for the source (DAQE-204-02, now incorporated into Title V permit No.3500068001). The combustion of natural gas is well understood and documented, and little change in PM10 emissions are anticipated with regular maintenance. The pollutants of concern for this source are NOx and CO, and stack testing is required to verify compliance with those limits. IX.H.2.p. SPRINGVILLE CITY CORP.
COMMENT 233: Subsection IX.H.2.p.(2) says "The owner/operator shall calculate a new 12-month total by the twentieth day of each month using data from the previous 12 months." This conflicts with the General Requirement at IX.H.1.b, which says "By the last day of each month..." This subsection for Springville City Corp. should refer back to the General Requirements. {Comment made by the EPA} RESPONSE 233: DAQ agrees with this comment. The source specific requirement will be changed to read as follows to agree with the general requirements: "(2)Compliance with the above limitations shall be determined by a continuous emissions monitoring system (CEM) meeting the requirements of R307-170. Daily NOx emissions shall be calculated for each individual engine and summed into a monthly output. The monthly outputs shall be summed into a rolling 12-month total of NOx in tons/year. The owner/operator shall calculate a new 12-month total by the last day of each month using data from the previous 12 months. Records of emissions shall be kept for all periods when the plant is in operation." IX.H.2.q. TESORO WEST COAST.
COMMENT 234: Subsection IX.H.2.q.(1) does not contain a 12-month limit on plantwide PM10 emissions. It is not clear to us why another refinery in IX.H.2. (Flying J) would have a 12-month limit but Tesoro would not. {Comment made by the EPA} RESPONSE 234: During the NSR review for DAQE-694-97, emission limits were reviewed. The annual limit for PM10 was equivalent to and redundant with the daily limit. In preparation for title V permits, redundant limits were removed, including the limit addressed here, and only the shorter-term limits were retained. IX.H.2.r. WEST VALLEY POWER PLANT.
COMMENT 235: A daily plantwide NOx limit is proposed, but no 12-month plantwide NOx limit. It is not clear to us why not. {Comment made by the EPA} RESPONSE 235: The annual limit was redundant. See the response to Comment 222 for a more complete explanation. SIP SECTION IX.H.3 - ESTABLISHMENT OF ALTERNATIVE REQUIREMENTS:
COMMENT 236: On page 33, Section IX.H.3.a - These paragraphs generally track the language in Attachment B of White Paper 2, but omits the following: "Noncompliance with any provision established by this rule constitutes a violation of this rule." We think it is possible to change this language somewhat, but that it is necessary to make explicit that violation of a substitute provision constitutes a violation of the SIP. We suggest inserting the following language after the first two paragraphs on page 33: "Noncompliance with any provision established under this provision shall constitute a violation of the state implementation plan." {Comment made by the EPA} RESPONSE 236: DAQ agrees, and will add the following sentence at the end of Subsection IX.H.3.a. "Noncompliance with an alternative requirement approved under this plan shall constitute a violation of the underlying SIP condition that was established in Subsections IX.H.1 or 2 of this plan."
COMMENT 237: On page 33, Section IX.H.3.b(1)g - DAQ needs to add a question mark. {Comment made by the EPA} RESPONSE 237: DAQ agrees, and will make the appropriate revision.
COMMENT 238: On page 34, Section IX.H.3. - The following language should be added (at the end of b. or somewhere in c.): "If the source fails to demonstrate that the proposed alternative is as or more stringent than the provision to be replaced, the executive secretary shall disapprove the proposed alternative." {Comment made by the EPA} RESPONSE 238: DAQ agrees, and will make the appropriate revision.
COMMENT 239: On page 34, Section IX.H.3.c(1): Please change to read, "A source can request an equivalent emission limitation or other requirement by submitting ...." {Comment made by the EPA} RESPONSE 239: DAQ agrees, and will make the appropriate revision.
COMMENT 240: On page 34, Section IX.H.3.c(1)(b): We think it would be more appropriate for the executive secretary, rather than the source, to issue a written determination regarding relative stringency. Perhaps this section should indicate that the source should provide a "proposed written determination" regarding stringency. {Comment made by the EPA} RESPONSE 240: DAQ agrees, and will make the appropriate revision.
COMMENT 241: On page 35, Section IX.H.3.c(4): Consistent with White Paper 2, change to read, At the time he or she transmits a source's part 70 application to EPA, the executive secretary will notify EPA if a source has requested an alternative requirement. {Comment made by the EPA} RESPONSE 241: DAQ agrees, and will revise the language as shown below: "At the time the executive secretary transmits a source's part 70 application to EPA, the executive secretary will notify EPA if a source has requested an equivalent emission limitation. The executive secretary will review the request, and if the executive secretary agrees that the source has demonstrated that the alternative requirement is as or more stringent that the existing SIP requirement, the executive secretary will submit the equivalence demonstration and supporting documentation to EPA in advance of draft permit issuance. If the executive secretary disapproves the requested changes, the disapproval notice will be submitted to EPA. PM10 EMISSION INVENTORY:
COMMENT 242: The State says in its description of the emission inventory that only the 24-hour standard for PM10 was violated and that it is therefore the controlling standard; however, the emission inventory provided shows only annual emission rates. In its current format, EPA cannot determine what 24-hour emission rates were used in the modeling analysis to show attainment of the 24-hour standard. For the baseline episodes, we believe DAQ should have developed 24-hour emission inventories based on actual 24-hour emission data for episode days and included it in the PM10 maintenance plan. For the projection years, we are unable to determine what 24-hour emissions rates were used for the large point sources, or whether the 24-hour emission rates that appear in Section IX, Part H are consistent with the modeling analysis. This is also relevant to the commitments made by DAQ in its letter to the EPA dated April 18, 2002. For these reasons, we cannot currently determine the validity or adequacy of the maintenance demonstration. EPA is aware of the difficulty in obtaining this information from the SMOKE program which was initially developed for ozone modeling where individual stationary source impacts/emissions are of less importance. To help resolve this issue we will confer with EPA experts familiar with the SMOKE program, and DAQ technical staff to try and find a simple way to extract this information from the UAM-Aero/SMOKE database. {Comment made by the EPA; D2, includes also E3 and I4} RESPONSE 242: DAQ began using SMOKE in 2001 with the help of its contractor, Sonoma Technology, and had its own staff members go directly to MCNC, the model developer, for training. Regarding paragraph two, comment No.99, DAQ attempted to create a 24-hour emission inventory for point sources for the base year. This was done in consultation with both Sonoma Technology and MCNC. After a number of failed attempts to process the 24-hour data through SMOKE all concurred that the model, although it was supposed to have that capability, could not process a 24-hour data set. It was decided to use the standard method that uses an annual inventory and uses the model temporal profiles to create an episode-specific, daily inventory. DAQ modeled sources that have limitations in their permits for individual components not to exceed certain thresholds on an hourly basis in a very conservative way. Limits that are expressed, typically, in lb/hr were multiplied by 24 to get lb/day and multiplied again by 365 to get lb/year. These were converted to ton/year and then processed through SMOKE. The graphic below, with the blue background, shows lines from the SMOKE profile and cross-reference files. These files are the means by which the program uses indices and SCC identifiers to convert the annual values into hourly rates. Values reported out of SMOKE are for the point source inventory for Salt Lake County, day 5, Tuesday, February 5, 2002 episode. Values are for the base year, 2002, and one future year episode, 2005. All future year values from 2005 to 2017 are equal since they represent allowable rather than actual levels and show the considerable increase in point source emissions by using allowable levels for future years. [A description of how SMOKE operates on individual sources, by SCC code, to change the emissions from an annual to an hourly average input for the air quality model was attached.] SMOKE uses its own customizable report generator and at the time of model development at DAQ the only reporting format available was for county-level emissions. This report format was created during the initial model development with the help of MCNC and the county-level format is the one that we have continued to use. Technical staff at DAQ will work with EPA, Region 8, and provide any of the data files requested to extract more detailed information from the SMOKE output files.
COMMENT 243: Emissions for PM10, SO2, NOx, CO, and VOC from Kennecott's main stack for 2001 were double counted and thus projected emissions used in modeling for the Smelter and Refinery are too high. This error arose from the structure of the inventory; the TSD spreadsheet entitled "Potential to Emit, 2002 PM10 Modeling, Kennecott Smelter and Refinery, shows emissions from the Main Stack by two different components, "Copper Smelting (main stack)" with Fuel shown "n/a," and "Copper Smelting (main stack) with Fuel shown "natural gas." These are the same emissions. This gives the reader of the Technical Support Document the impression that the Smelter and Refinery emit more than their permits allow, and that is not true. These errors do not invalidate the modeling demonstration of maintenance of the PM10 NAAQS; in fact, they make the demonstration more conservative than it needs to be. Finally, several units are labeled as "not permitted," which is not the case. {Comment made by Kennecott} RESPONSE 243: DAQ agrees, and acknowledges that the emissions from the main smelter stack at Kennecott were double-counted. This error, however, did not originate in the original 2001 emissions inventory submittal, but rather arose during manipulation of the inventory data in preparation for SIP modeling. The original submittal remains correct. As explained in Comment 230b, this error does not invalidate the conclusion that the PM10 standard will be maintained. The model demonstrates attainment and maintenance with the emissions that were included in the inventory.
COMMENT 244: (EPA G1) The mobile source inventory portion of the Technical Support Document (TSD - "Supplement III-05 to the PM10 SIP (Maintenance Plan), Draft April 2005, Volume I of IX") notes that fugitive dust emissions from unpaved roads will be addressed in the area source inventory. However, section 1.a only addresses fugitive dust sources from paved road dust and does not include inventories from unpaved roads. Please include an emission inventory from unpaved roads in either the mobile source or area source inventory. If dust from unpaved roads is included in the transportation plans (developed by the MPOs) then the SIP must include them in the overall maintenance demonstration and as part of the motor vehicle emissions budget. These emissions must be included appropriately and consistently as either an area source or mobile source. {Comment made by the EPA} RESPONSE 244: Unpaved roads are included in the area source base year inventory (see Volume III 2.c.ii(1) and (2)). They are also projected (see Volume VIII pages 3.c.iii-8 and 3.c.iii-61). PM10 MODELING:
COMMENT 245: In EPA's comments on the original modeling protocol we stated that the final maintenance plan should also address the annual NAAQS for PM10 and we suggested that an emissions-based analysis be used to demonstrate continued compliance with the standard. Annual concentrations at the North Salt Lake City monitor have been as high as 46 ug/m3 as recently as 2000 and that in the future the standard could be threatened at that location with a small increase in local emissions. Emissions inventory projections showing a downward trend in future year emissions near the monitor would be a reasonable method to demonstrate NAAQS maintenance. Annual concentrations at the other monitors in the Salt Lake City area are well below the annual standard and the current SIP plus additional reductions to address the 24-hour NAAQS should ensure compliance with the NAAQS at these locations. {Comment made by the EPA; E1} RESPONSE 245: The annual standard has been addressed at Section IX.A.10.c(1)(d). It is explained therein that the control strategy developed as part of the 1991 PM10 SIP was based on the 24- hour NAAQS (not the annual) because that approach resulted in the more stringent control requirements. Many of the control strategies that were implemented to reduce the 24-hour PM10 concentrations also result in a reduction of the annual PM10 concentrations, particularly since the ambient data shows that the winter season is the period that has the greatest impact on the annual average. The data presented in Section IX.A.10.b(3) shows a downward trend in the annual arithmetic mean concentrations, thus corroborating the assumption made in the 1991 SIP. This is particularly important at the North Salt Lake monitor, where the values of the arithmetic mean concentrations are closest to the NAAQS (Figure IX.A.29). The downward trend in the data collected here from 1994 through 2004, representing the period of Post-SIP RACT control, may be described by a line of best fit in which the slope is -0.577 ug/m3 per year. For a discussion as to why the trend over this period of time is relevant to the proposed demonstration of maintenance through 2017, see the response to Comment 46.
COMMENT 246: In the UAM-Aero modeling, banked emissions were sited in core industrial areas in the county in which they were registered and included in the modeling in 2005 and subsequent years. In general, EPA believes that this is a reasonable approach. However, 12,567 tons/yr of Kennecott's banked SO2 emissions were modeled as if they were emitted from Kennecott's 1200 foot stack. Under wintertime inversion conditions it is unlikely that pollutants emitted from a 1200 foot stack (above the persistent inversion) would be mixed to the surface and contribute to PM10 concentrations at the surface. These SO2 emissions should be remodeled using the same method that UDEQ used for NOx and PM10. {Comment made by the EPA; E2} RESPONSE 246: These emission reduction credits were created by achieving emission rates that were lower than what was required by the 1991 PM10 SIP. The lower limits will be included in the maintenance plan (see response to Comment 230a). The banked credits were modeled so as to preserve them in the baseline for the SIP (see response to Comment 169). DAQ is implementing the nonattainment area permitting program (R307-403) in accordance with EPA's interpretation of the rule in the May 5, 1995 approval of the program. Interpollutant trading between PM10, NOx and SO2 is not allowed under this rule for new major sources or major modifications. It is unlikely that 13,000 tons of SO2 emission reduction credits will be used in the nonattainment area. Therefore, it would not be appropriate to model these emissions throughout the nonattainment area. When the area is redesignated to attainment for PM10 and SO2 the method that was used to estimate where banked emissions would be used will no longer be an issue because the PSD program will require modeling to demonstrate that any major source or major modification will not cause a violation of the NAAQS. If such modeling showed a violation of the NAAQS, the permit would not be issued.
COMMENT 247: On page 38, section IX.A.10.c(6), says that the road dust inventory was discounted by 75% for purposes of demonstrating maintenance, but that it was not discounted for purposes of establishing motor vehicle emissions budgets. We question whether the 75% discount is appropriate. Utah must include a reasoned and valid rationale for this discount, including the air quality monitoring data and the original modeling results. Any technical reports by Sonoma Technologies, Inc. explaining this adjustment factor should be included in the TSD (at Tab 2.d.iii (3)(iii) page 17). {Comment made by the EPA; B30, includes EPA comments B31 and F3} RESPONSE 247: The inventories and budgets appropriately reflect the output of the EPA-approved mobile source model. The 75% reduction is a performance adjustment to the air dispersion model and is consistent with guidance provided in the documents identified below. These two EPA-authored documents provide valid rationale for this approach and will be included in the TSD. The second sentence in the first reference speaks to the lack of value that a comparison to monitored data would provide. Without the 75% reduction, the airshed model would significantly over-predict the primary PM component. "Conclusions. Our understanding of factors affecting particle removal near ground level fugitive dust sources has improved greatly since the late 1990s. Models are limited in their ability to fully account for near source removal of particles for a variety of physical and practical reasons and this limitation is a major reason for the disparity between modeled and monitored estimates of fugitive dust. The Transportable Fraction concept is consistent with research on windbreaks and has been at least partially quantified by the field work of DRI and MRI. In its current form, the TF concept does provide a useful way to account for this removal process in grid models by applying a variable adjustment across the U.S. This variable adjustment is an improvement upon the national divide-by-four adjustment that has been used for several years. However, this area of research is still emerging and other approaches or assumptions may be useful, especially when considering a specific air shed. Also, it will be prudent to review the TF methodology as new studies are published." (A Conceptual Model to Adjust Fugitive Dust Emissions to Account for Near Source Particle Removal in Grid Model Applications. pg. 10, Thompson G. Pace, US EPA 8/22/2003.) "ADJUSTMENTS FOR MODELING THE NET INVENTORY. Three source types in the NET inventory were given special treatment for this modeling exercise. First, we made an adjustment to PM2.5 and PM10 emissions from certain fugitive source categories to remove what is termed the "non-transportable" component of these emissions. This component represents an approximation of the portion of fugitive emissions that settle out and are not dispersed more than a few meters from where they are emitted. Particulate emissions for the source categories listed in Table 1 were reduced by 75 percent to simulate the effects of this settling process. This adjustment was made because the emissions factors and activity data used in calculating fugitive emissions are designed to provide total emissions estimates whereas the nature of the processes which lead to such emissions (e.g., vehicles traveling on unpaved roads) result in much of the particle mass being deposited close to the location of the release. [Table 1 was included.] Development of an Anthropogenic Emissions Inventory for Annual Nationwide Models-3/CMAQ Simulations of Ozone and Aerosols. pp. 3-4, Norman Possiel, et al. (Date unknown).
COMMENT 248: Documentation of Modeled Emission Rates for Stationary Sources - For the projection years, we are unable to determine what 24-hour emissions rates were used for the large point sources, or whether the 24-hour emission rates that appear in Section IX, Part H are consistent with the modeling analysis. We cannot currently determine the validity or adequacy of the maintenance demonstration. (See related comment under "PM10 Emission Inventory.") {Comment made by the EPA; E3} RESPONSE 248: See response to Comment 242. TECHNICAL SUPPORT DOCUMENT - "SUPPLEMENT III-05 TO THE PM10 SIP (MAINTENANCE PLAN), DRAFT APRIL 2005":
COMMENT 249: (EPA F1) Tab 2.d.iii (1)(a) PM10 Mobile Source Protocol Using MOBILE6.2, Overview, 2nd paragraph, the last sentence should be corrected to indicate PART5 was only used to model fugitive dust from paved roads and that MOBILE6.2 was used for tail pipe, brake and tire wear as noted in the maintenance plan. {Comment made by the EPA} RESPONSE 249: As submitted, the PM10 Mobile Source Protocol Using MOBILE6.2, Overview, 2 paragraph is correct. PART 5 was to estimate tail pipe, brake and tire wear, not MOBILE6.2. The inventories were prepared in accordance with the EPA-approved methodology in place in October 2003. Concurrently, MOBILE6 was used to estimate tailpipe emissions of CO, NOx, and VOC only. PART5 was used to estimate road dust, SO2 gas, direct tailpipe emissions of SO4, direct tailpipe emissions of particulates, brake wear and tire wear. Modeling was accomplished consistent with an EPA memo dated November 2002. At the time the Mobile Source inventories were prepared, MOBILE6 was not approved to assess emissions other than CO, NOx, and VOC.
COMMENT 250: Tab 2.d.iii (3)(iii) page 6, PART5 Model. This paragraph indicates that the February 1995 version of the PART5 model was used. AP-42 was updated in November 2003 to reflect more accurate emission factors. According to our Policy Guidance at http://www.epa.gov/otaq/models/mobile6/mobil6.2_letter.pdf, the 24-month grace period for using MOBILE6.2 and AP-42 for PM SIPs started May 14, 2004. The use of PART5 is satisfactory for now but we would like to make Utah aware that the use of AP-42 for fugitive dust and MOBILE6.2 for tailpipe/tire/brakes will soon be mandatory. {Comment made by the EPA; F2} RESPONSE 250: The future termination of PART5 and replacement with AP-42 fifth edition is noted. The use of PART5 in this plan is consistent with the approved EPA guidance. H. EPA COMMENTS REGARDING THE OUTSTANDING DAQ APRIL 18, 2002 COMMITMENTS:
COMMENT 251: As the Utah AQB works toward adoption of a maintenance plan and a request to redesignate Utah County, Salt Lake County, and Ogden City PM10 nonattainment areas to attainment, the EPA would like to remind the Board and the DAQ of the commitments made to EPA in a letter dated April 18, 2002. Based on our preliminary review of DAQ's proposed draft PM10 maintenance plan submittal, the commitments below remain an issue. DIRECTOR'S DISCRETION:
COMMENT 251a: EPA informed DAQ that the director's discretion provisions that allow for changes to be made to the SIP without EPA's approval and have resulted in SIP enforceability issues are counter to sections 110(a) and 110(i) of the Clean Air Act (CAA). We informed DAQ that all directors' discretion provisions need to be removed from the SIP. DAQ indicated that the State is interested in using authority under 40 CFR 70.6(a)(1)(iii) and EPA's White Paper 2 to modify SIP provisions through the Tile V permitting process. EPA indicated that we will support the State's use of this authority. The proposed SIP package includes draft SIP language based on this authority, and with some changes (see prior comments), we believe the draft SIP language will address the principles of White Paper 2. In addition, we note that the State's proposal would remove a number of director's discretion provisions from the PM10 SIP, and we endorse the State's efforts in this regard. However, we note that the proposed SIP revisions retain a number of director's discretion provisions and add new ones as well. We have made an effort to identify these individually in our comments on the proposed language. We are also concerned that problematic director's discretion provisions may remain in parts of the SIP that the State is not revising as part of this effort. Failure to remove director's discretion provisions from the SIP could jeopardize our ability to approve the redesignation. {Comment made by the EPA; I1} RESPONSE 251a: DAQ has removed language from R307-305-2 allowing sources to modify SIP requirements through permitting. Further the PM10 SIP has been modified in Appendix H, where individual source specific requirements are delineated removing director's discretion. Concurrently, DAQ has drafted enabling language in Appendix H of the proposed PM10 SIP revisions that incorporates procedures to modify the SIP through a Title V, Operating Permit as permitted by 40 CFR 70.6(a)(1)(iii). VARIANCE PROCEDURES:
COMMENT 251b: The variance language that exists within the current SIP should be removed. As with director's discretion provisions, variance provisions approved into a SIP may make it appear that we have authorized the State to unilaterally change SIP requirements. This is inconsistent with the Clean Air Act, and the DAQ variance procedures will not change this basic problem. {Comment made by the EPA; I2} RESPONSE 251b: Section 110(i) of the federal Clean Air Act was added to the federal law by the 1977 amendments to the Act. Section 110(i) provides that except for a number of listed exceptions, "no order, suspension, plan revision, or other action modifying any requirement of an applicable implementation plan may be taken with respect to any stationary source by the State or by the Administrator." Because of issues raised by EPA concerning the consistency between the Utah variance provisions and Section 110(i) of the federal Clean Air Act, the Utah rules were amended in November, 1979, to add a restriction on the granting of variances -- allowing the granting of variances as provided by law "unless prohibited by the Clean Air Act." That language has existed in the Utah rules since that date and is currently a part of Utah Administrative Code R307-102-4. The variance rule and its limitation were included in numerous State Implementation Plans and revisions submitted to EPA since 1979. EPA has approved the language as part of those implementation plans and revisions to those plans. A written opinion concerning the variance provisions by Fred Nelson, Assistant Attorney General, is attached to these comments. DAQ clarified to the EPA the procedures for implementing the variance provisions, in a copy of the Variance Procedures Memo, dated February 21, 2003, and signed by Richard Sprott. This memo details the procedures that staff follows to assure that all variance requests are processed to determine their consistency with all applicable requirements, including the CAA. Therefore, there is no inconsistency between the CAA and Utah Rule R307-102-4.
COMMENT 251c: (EPA Comment I3) Enforceable Emission Limits for Major Sources (including 24-hour emission limits): RESPONSE 251c: DAQ has included enforceable emission limits for all significant sources located in Salt Lake and Utah Counties (as well as some others in southern Davis County), and these limits are consistently expressed in terms of tons per day. These limits appear in Part IX.H of the proposed SIP, and would replace all that is currently in that Part. RESPONSE 251c: See complete discussion at Comment 200, "Section IX. Part H - Emission Limits and Operating Practices:" (General Comments).
COMMENT 251d: (EPA Comment I4) Emission Inventory and Modeling Analysis for Sources in Nonattainment areas: RESPONSE 251d: See discussion at comment 99, "PM10 Emission Inventory"
COMMENT 251e: (EPA Comment I5) Refinery SRU and Flaring: RESPONSE 251e: See discussion at comment 68, "Section IX. Part H - Emission Limits and Operating Practices:" (SRU Turnaround and Upset Flaring Emissions). NSR/BANKING/TRADING:
COMMENT 251f: DAQ needs to address the emission banking and interpollutant trading issue. DAQ has expressed concern regarding EPA's NSR Reform Rule and the impacts that the reform rule may have on what EPA has identified as deficiencies in Utah's NSR rules. EPA has expressed to DAQ in the past that the State could still continue to work on the emission banking and interpollutant trading issues despite NSR Reform. DAQ has also questioned whether EPA's concerns with DAQ's NSR program would become moot once the areas are redesignated to attainment and fall under the State's PSD rules. We believe these issues will not become moot for the following reasons. First, areas of the State may remain nonattainment for other pollutants even if Salt Lake and Utah counties are redesignated attainment for PM10. Second, we think Utah must have an adequate nonattainment NSR program in place in case any part of the State is designated nonattainment in the future. Finally, some of the issues we have identified apply to PSD and minor source permitting as well as nonattainment NSR. {Comment made by the EPA; I6} RESPONSE 251f: DAQ agrees with EPA that there are issues in Utah's nonattainment NSR rule (R307-403) that need to be addressed. However, these issues do not affect the PM10 maintenance plan and should be addressed separately. When EPA approves the maintenance plan and redesignates Utah County, Salt Lake County and Ogden City to attainment, R307-403 will no longer apply in the new maintenance areas. The PSD rule, R307-405 will become the permitting program for major sources and major modifications. Utah has either been redesignated to attainment or has submitted a maintenance plan to EPA for all nonattainment areas in the state. When those remaining plans are approved, R307-403 will not apply anywhere in the state, and so any issues in that rule will be academic. DAQ also agrees with EPA that Utah needs to have an NSR program in place that will apply in any new nonattainment areas that are designated in the future. When looking at current monitoring data, it is clear that the two pollutants that are of most concern in Utah are PM2.5 and ozone (8-hour standard). EPA has delayed finalizing the NSR reform provisions in the nonattainment permitting rules in 40 CFR 52.24 and 40 CFR Part 51, Appendix S to ensure that these rules are consistent with the implementation guidance for the PM2.5 and 8-hour ozone standards. There are significant issues, such as precursors and increment, that must be addressed and it is unreasonable to expect Utah to resolve these issues at the state level prior to resolution of these issues at the national level. DAQ anticipates that the federal nonattainment area permitting requirements will be finalized sometime this year. DAQ plans to act expeditiously to revise Utah's nonattainment area permitting rules based on the new federal requirements. In the meantime, the current program is effective and will continue to function during the interim period. EPA mentions that there are some portions of their comments that apply to Utah's PSD program. DAQ staff has reviewed EPA's earlier comments, and they seem to apply solely to the nonattainment area permitting program. Utah is in the process of developing a draft revision to R307-405 to incorporate the federal NSR reform provisions into Utah's rule. Utah intends to submit this rule to EPA by the end of the year, as required. If there are any issues with the revised rule, DAQ welcomes comments from EPA during the public comment period for the revised PSD permitting rule.
COMMENT 251g: (EPA Comment I7) Unavoidable Breakdown Rule: RESPONSE 251g: DAQ has re-proposed a draft of the Excess Emissions rule and submitted it to the EPA on March 3, 2005. DAQ is committed to continue this rulemaking process.
COMMENT 251h: (EPA Comment I8) Backhalf Emissions Measuring: RESPONSE 251h: See discussion at Comment 202, "Section IX. Part H - Emission Limits and Operating Practices:" (Source Testing). DIESEL PARTICULATE AND NOx EMISSIONS:
COMMENT 252: Strategies to reduce diesel emissions would be appropriate due to the rail and truck yards near the North Salt Lake monitor that exceeds the PM2.5 health standard. We recognize that Utah supports tightening federal standards for locomotive emissions, but there are local strategies that could be implemented. Last year, California Air Resources Board sponsored a risk assessment of diesel exhaust at a rail yard near Sacramento. The study concluded that dangerous concentrations of ultra-fine particulate extend widely outside the rural yard and affect residents for miles around. Specifically, it contributes an additional cancer risk at a rate between 100 and 500 cases per million people over an area in which 14,000 - 16,000 people live, and at a rate of 1 - 100 cases per million people over a larger area in which 140,000 - 155,000 people now live. The small size of the particles makes it an efficient means of delivering chemicals into our bodies. Diesel exhaust is easily inhaled deep into the lungs, where up to 85% of fine particles remains in the lungs 24 hours after initial exposure; this means that diesel exhaust has easy, long-lasting access to the most sensitive parts of the lungs. There are several strategies that could be used, in conjunction with ultra low sulfur fuel, to reduce diesel emissions. First, there are catalyzed diesel particulate filters (DPFs) and diesel oxidation catalysts (DOCs) that reduce PM dramatically. Currently, DPF retrofits for school buses and construction equipment cost in the $500 - 10,000 range; DOCs do not require ultra low sulfur fuel and are cheaper at $700-2500 for school buses and construction equipment, but are less effective. Strategies to reduce idling should be considered; alternatives are auxiliary power generators, auxiliary power units, truck stop electrification, engine idle management technology, and no-idle hear and/or HVAC systems. Union Pacific is now using its first hybrid switching engine at Los Angeles area ports; it operates on an electric battery and a diesel engine that recharges the battery. Union Pacific estimates it will see 80-90% reductions in NOx, and will use 40-60% less fuel. Reducing NOx from locomotive emissions by replacing older engines with newer hybrids is also used in the Houston Galveston area as part of the Texas ozone reduction strategies. In Chicago, idle reduction strategies are in place, with reduction of 12.5 tons of NOx at a cost of $1420 per ton. {Comment made by Environmental Defense and Utah Chapter, Sierra Club} RESPONSE 252: Generally, an engine used in a switching yard is idling 70% of the time, and thus wastes significant amounts of fuel, as well as generating emissions of NOx and other pollutants. There are two recent technologies that are promising for the future. The diesel-electric hybrid engine uses a 600-volt battery bank to power a 290-horsepower inline 6-cylinder diesel truck engine; it uses 40 - 60% less fuel and emits 80 - 90% fewer pollutants than conventional train engines. It is also cheaper to purchase, and cleaner, than the newest generation of diesel locomotives. Union Pacific has leased hybrid engines for use in California and Texas. The other technology is the diesel truck-engine switch locomotive (TES), which uses two state-of-the-art diesel engines developed for large, over the road trucks. EPA is expected to certify TES under its new Tier 2 standards. Utah DAQ encourages Union Pacific to evaluate the positive environmental and economic benefits and expand the use of this technology within Utah, especially in urban areas. DAQ staff has been consulting with personnel in school districts along the Wasatch Front to encourage use of cleaner school buses. HEALTH AND HIGH PM2.5:
COMMENT 253: EPA's Clean Air Science Advisory Committee has deemed PM2.5 to be more dangerously unhealthy than was known when the standard was set in 1997, and EPA will issue a stronger standard soon. The pollutants that cause PM2.5 are the same as those causing PM10. Yet we have before us a Plan that proposes that says we don't have to worry about PM10 any more and can begin discussing increments available to add more PM10 to an area with a rapidly growing population including many young children, pregnant women and people with heart and lung problems--those sensitive populations that are susceptible to health effects even below the federal health standard. What this Plan proposes in terms of increased PM10 pollution is really about how much more PM2.5 pollution we can add to the Wasatch Front. We should be addressing how we can reduce the PM2.5 levels that we have now. {Comment made by Sierra Club, Utah Chapter} RESPONSE 253: DAQ began addressing PM2.5 pollution long before EPA issued a federal health standard for it and expects to continue to do so; some of the provisions that EPA adopted to regulate PM2.5 were based on the knowledge gained through data collected and analyzed in Utah and other states. Most of the strategies that Utah adopted to control PM10 also control PM2.5 because PM2.5 is a large portion of the overall PM10 measurements during wintertime temperature inversions. Within a year after EPA issued the PM2.5 standard, Utah began proceedings to regulate woodburning based on monitored and projected levels of PM2.5 (see response to No. [136] above). DAQ will continue to work to find ways to reduce PM2.5 throughout the state, and is developing strategies by working with local communities.
COMMENT 254: We are very concerned about the reported exceedances at the North Salt Lake monitor. We should be trying to reduce PM2.5. This monitor is near refineries, gravel operations, construction sites, and residential areas. {Comment made by Sierra Club, Utah Chapter} RESPONSE 254: DAQ will take action to correct high PM2.5 values, as needed, in any area. It is possible that the excessive PM2.5 in 2004 at the North Salt Lake monitor had natural causes. One such possibility is blowing dust from the beaches of the Great Salt Lake; due to the 6-year drought, the beach area was both larger and drier in 2004 than it had been historically. DAQ staff are acquiring and analyzing data needed to understand the precise nature of the problem; we will know more when we receive the results of the filter analysis.
COMMENT 255: PM10 and PM2.5 are closely related and Utah should consider them together, especially since Salt Lake County is currently violating the annual PM2.5 standard [at the North Salt Lake monitor]. We understand that the data will not be certified until June 1, the average of 15.2 u/mis a concern. This monitor is near several refineries, highway and railway corridors, rail and truck yards, gravel pits, and several residential areas. Because must of the particulate pollution in the Salt Lake area is due to industrial emissions and is in the smaller particle size range, the PM10 plan should set the framework for complying with the PM2.5 standard as well. Moreover, there is a large body of new health effects studies showing further evidence of the serious adverse health effects of PM2.5, including respiratory and cardiovascular events that explain morbidity and mortality observed in epidemiological studies. Fine particles exacerbate preexisting illness in children with asthma, emergency room visits, and premature deaths. With this maintenance plan, Utah has the responsibility and the ability to begin to protect its citizens from fine particles and to fulfill the Clean Air Act's bedrock mandate to restore healthy air "as expeditiously as practicable." {Comment made by Environmental Defense and Utah Chapter, Sierra Club} RESPONSE 255: DAQ understands the importance of maintaining all of the health-based standards, including the PM2.5 standard, throughout the state.
COMMENT 256: North Salt Lake is currently very close to a violation of the PM2.5 health standard, and a recent permitting action indicated that a sulfur dioxide dispersion analysis model predicted an exceedance of the 24-hour sulfur dioxide standard in terrain directly east of a refinery in North Salt Lake. Dispersion modeling does not account for large flaring events; thus, there could be episodic events with emissions far beyond that modeled. {Comment made by Wasatch Clean Air Coalition} RESPONSE 256: For discussion of the North Salt Lake monitor, see the response to comment 146 above. For a discussion of upset flaring events see the response to Comment 212.
COMMENT 257: Monitoring refinery flares for emissions of PM2.5 precursors would be an important start in knowing more about what is in the flares in order to better control such emissions. Sulfur dioxide emissions have been detected as a problem in the refinery area. {Comment made by Sierra Club, Utah Chapter} RESPONSE 257: Again, this Plan appropriately addresses PM10, not PM2.5. However, as noted in the response to 145 above, DAQ is already taking action to reduce PM2.5 emissions. As to any problems with sulfur dioxide in the area of the refineries, see the response to 256 above.
Reasoned justification for continuation of the rule, including reasons why the agency disagrees with comments in opposition to the rule, if any:
The rule must be continued to meet federal requirements that the State adopt enforceable plans to reduce air pollution. If the State failed to adopt such plans and incorporate them by reference into Utah's rules, EPA would impose federal plans and rules instead. Responses to all comments are included under "the summary of written comment" above.
The full text of this rule may be inspected, during regular business hours, at the Division of Administrative Rules, or at:
Environmental Quality
Air Quality
150 N 1950 W
SALT LAKE CITY UT 84116-3085Direct questions regarding this rule to:
Jan Miller at the above address, by phone at 801-536-4042, by FAX at 801-536-4099, or by Internet E-mail at janmiller@utah.gov
Authorized by:
M. Cheryl Heying, Planning Branch Manager
Document Information
- Publication Date:
- 10/01/2005
- Filed Date:
- 09/08/2005
- Agencies:
- Environmental Quality,Air Quality
- Authorized By:
- M. Cheryl Heying, Planning Branch Manager
- DAR File No.:
- 28224
- Related Chapter/Rule NO.: (1)
- R307-110. General Requirements: State Implementation Plan.