TECHNICAL MEMORANDUM

TO:	Docket for Rulemaking, "Revised Cross-State Air Pollution Rule (CSAPR) Update for the 2008 Ozone NAAQS" (EPA-HQ-OAR-2020-0272)
DATE:		March 12, 2021
SUBJECT:	Assessing Non-EGU Emission Reduction Potential  -  Updated for Final Rulemaking

Introduction

Because there are many types of non-EGU emissions sources or units that emit NOx and many control technologies or combinations of control technologies for these units, there are many approaches to assessing emission reduction potential from non-EGU emissions sources/units. The EPA completed an assessment of emission reduction potential from these sources/units on a compressed schedule for the proposed and final rules, and this memorandum presents one approach. The remainder of this memorandum summarizes this approach to assessing non-EGU emission reduction potential and the related air quality impacts associated with the estimated reductions. The memorandum includes the following sections:

 Model and Methodology Used to Assess Non-EGU Emission Reduction Potential
 Background for Determining Source Size/Threshold for Non-EGU Emissions Sources
 Air Quality Impacts from Potential Non-EGU Emissions Reductions
 Further Verifying and Refining Estimated Non-EGU NOx Emissions Reduction Potential
 Detailed Verification and Review of Controls on Non-EGU Sources in Four States
 Conclusions of Verification and Review of Controls on Non-EGU Sources in Four States and Potential Emissions Reductions
 Caveats and Limitations of the Cost Analysis
 Control Installation Timing
 Request for Comment and Additional Information

Model and Methodology Used to Assess Non-EGU Emission Reduction Potential

For this assessment the EPA used the Control Strategy Tool (CoST) with the maximum emission reduction algorithm[,][,], the Control Measures Database (CMDb), and the 2023 emissions projections based off of the 2016 NEIv1. We used the maximum emission reduction algorithm to estimate the largest quantity of potential emissions reductions from each emissions source or unit that might impact downwind receptors. CoST also includes a least cost algorithm that works to identify the set of controls that achieves a given percent reduction or target emissions reduction at the least cost. If that target emission reduction can't be achieved, then the resulting strategy will be, by definition, the maximum emissions reduction strategy. That is, the primary objective of the strategy will be focused on getting emissions reductions and not on lowering costs.

For 2023, we summarized emissions reductions and average annual cost per ton for the 12 states identified from the 2023 air quality modeling and linked to downwind receptors. The cost per ton values are annual costs and the estimated reductions are annual emissions reductions. In addition, in the assessment CoST applied controls to emissions units with a 150 tons per year (tpy) or more pre-control NOx emissions threshold (see section below on Background for Determining Source Size for Non-EGU Emissions Sources for options on NOx emissions thresholds). The results of the CoST run are summarized in an Excel workbook titled CoST Control Strategy - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling - No Replace - 07-23-2020.

The 12 states in this assessment are the 12 states EPA proposes to find linked to a downwind receptor in 2021 in the proposed and final actions: IL, IN, KY, LA, MD, MI, NY, NJ, OH, PA, VA, and WV.

States across the U.S. reported NOx emissions from approximately 81,000 non-EGU facilities with point sources/units. Of these, states reported control information for facilities with one or more controls for approximately 17,000 non-EGU facilities, or 21 percent of these facilities. As such, this assessment of emission reduction potential from non-EGU emissions sources/units reflects a large degree of uncertainty because information about existing controls on emissions sources/units is missing for some states and incomplete for some sources. As an example, Table 1 below includes emissions totals, uncontrolled emissions, and percent of uncontrolled emissions using information from the 2017 NEI.

Table 1. For Facilities w/>150 tpy of Emissions in the 2017 NEI  -  By State,
Total NOx Emissions and Uncontrolled NOx Emissions (ANNUAL tpy)
                                     State
                                     Total
                                   Emissions
                                   (ANNUAL)
                                 Uncontrolled
                                 NOx Emissions
                                   (ANNUAL)
                       Percent of Emissions Uncontrolled
                                      IL
                                    17,655
                                    16,773
                                      95%
                                      IN
                                    32,926
                                    31,567
                                      96%
                                      KY
                                    19,121
                                    16,445
                                      86%
                                      LA
                                    91,952
                                    87,295
                                      95%
                                      MD
                                     6,354
                                     2,339
                                      37%
                                      MI
                                    35,399
                                    34,459
                                      97%
                                      NJ
                                     3,753
                                     2,261
                                      60%
                                      NY
                                    12,418
                                    11,065
                                      89%
                                      OH
                                    35,186
                                    33,891
                                      96%
                                      PA
                                    31,680
                                    30,437
                                      96%
                                      VA
                                    19,394
                                    14,317
                                      74%
                                      WV
                                    11,507
                                    11,255
                                      98%

From the CoST run, Table 2 below summarizes potential emissions reductions by industry sector and the range of annual cost per ton estimates across units to which CoST applied controls in each industry sector. This summary can be found in a worksheet titled Control Summary-by NAICS (2) in an Excel workbook titled Control Summary - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling  -  No Replace  -  05-18-2020.

Table 2. Annual NOx Emission Reduction Potential and Cost Per Ton Ranges by Industry Sector in 2023 for Twelve States

The EPA categorized the CoST results for the control technologies that comprise approximately 92 percent of the total estimated potential emissions reductions from the non-EGU sources/units in the 2023 projected inventory with 150 tpy or more of NOx emissions in the 12 linked states; the technologies and related emissions sources include:
 Layered combustion (lean burn IC engines  -  natural gas),
 NSCR or layered combustion (industrial natural gas IC engines, Source Classification Codes (SCCs) with technology not specified),
 SCR (glass manufacturing  -  container, flat & pressed, ICI boilers, IC engines (oil-fired and natural gas)),
 SNCR (cement manufacturing  -  dry and wet kilns, municipal waste combustors), and
 Ultra-low NOx burner and SCR (ICI boilers).

The EPA incrementally included additional details in these summaries, including:
 Emissions source group (ICI boilers, IC engines, cement kilns, glass furnaces),
 State, and
 Industry sector (cement/glass manufacturing, paper manufacturing, pipeline transportation).

In addition, we calculated a weighted average cost per ton for each technology, plotted the weighted average costs, and observed a clear breakpoint in the curve at $2,000 per ton. This identified two tranches of potential emissions reductions (see Figure 1 below). The summaries discussed above and the figure below are also available in the Excel workbook titled Control Summary - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling  -  No Replace  -  05-18-2020.

Figure 1. Cumulative NOx Emission Reduction Potential (annual tons) by Weighted Average Cost Per Ton (annual cost per ton) for Control Technologies in 2023

Dotted vertical line separates the two tranches.

For the technologies above, we then:
 Within each technology, further organized by emissions source group, and
 Looked closer at cost per ton within these technology/source group "bins".

These summaries are available in the Excel workbook with the CoST run results titled CoST Control Strategy - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling - No Replace - 07-23-2020.

The first tranche of potential emissions reductions had a weighted average annual cost of approximately $2,000 per ton and a cost range from ~$64 per ton - ~$5,700 per ton and included the following technology/source groupings:
             SCR  -  glass manufacturing  -  container, flat & pressed, IC engines, oil-fired and natural gas (in pipeline transportation and oil & gas extraction industry sectors), and
             SNCR  -  cement manufacturing  -  dry and wet kiln, municipal waste combustor.

See Table 3 for details - note that the potential emissions reductions are annual tons not ozone season tons. Additional details on this first tranche, including the potential emissions reductions and number of emissions units by state are shown in Table 4. To analyze potential emissions reductions in step 3 of the 4-step framework, we determined that the potential emissions reductions in tranche 1 are potentially relatively cost-effective because the $2,000 cost per ton for non-EGU emissions reductions is similar to the control stringency for EGUs represented by up to $1,800 per ton (see section below on Further Verifying and Refining Estimated Non-EGU NOx Emissions Reduction Potential for additional discussion).

      Table 3. Annual NOx Emission Reduction Potential and Annual Cost Per Ton Range by Technology and Source Group for Tranche 1 in 2023

      Table 4. Annual NOx Emission Reduction Potential by Technology, State, and Source Group for Tranche 1 in 2023

The second tranche of potential emissions reductions had a weighted average annual cost range from approximately $5,000 per ton to $6,600 per ton and a cost range from ~$1,400 per ton - ~$9,700+ per ton and primarily included the following technology/source groupings:
             Layered Combustion  -  lean burn IC engines - natural gas (in pipeline transportation and oil & gas extraction industry sectors),
             NSCR or Layered Combustion  -  industrial natural gas IC engines, SCCs with technology not specified (in pipeline transportation and oil & gas extraction industry sectors), and
             Ultra-low NOx burner and SCR  -  ICI boilers (in paper manufacturing, petroleum and coal products manufacturing, chemical manufacturing, and primary metal manufacturing industry sectors).

See Table 5 for details - note that the potential emissions reductions are annual tons, not ozone season tons. Additional details on this second tranche, including the potential emissions reductions and number of emissions units by state are shown in Table 6. To analyze potential emissions reductions in step 3 of the 4-step framework, we made no determination as to whether the potential emissions reductions in tranche 2 are cost-effective because we assumed the up to $1,800 per ton cost threshold for reductions from EGU sources was an equivalent cost threshold for comparison. The underlying details and summary Tables 3 through 6 are available in the Excel workbook titled CoST Control Strategy - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling - No Replace - 07-23-2020.

      Table 5. Annual NOx Emission Reduction Potential and Annual Cost Per Ton Range by Technology and Source Group for Tranche 2 in 2023

      Table 6. Annual NOx Emission Reduction Potential by Technology, State, and Source Group for Tranche 2 in 2023

Background for Determining Source Size/Threshold for Non-EGU Emissions Sources

In assessments of non-EGU emission reduction potential that provided supplemental data for review and comment in previous interstate transport rulemakings, we assessed units with pre-control NOx emissions > 100 tpy, which is the major source threshold for moderate ozone nonattainment areas. In addition, in the 2016 Final Technical Support Document (TSD) for the Final Cross-State Air Pollution Rule for the 2008 Ozone NAAQS, Assessment of Non-EGU NOx Emission Controls, Cost of Controls, and Time for Compliance Final TSD, EPA ran CoST for non-EGU point sources for the 37 eastern U.S. states with NOx emissions of greater than 25 tons per year in 2017. This assessment was prepared for the purpose of presenting and seeking comment on the then currently available information on emissions and control measures for emissions sources/units of NOX other than EGUs; it was not prepared for use in conducting a rigorous regulatory analysis under the step 3 multi-factor test, nor for establishing specific emissions limits. Further, this 2016 assessment relied primarily on NEI data that, for reasons explained at proposal of the CSAPR Update, was not considered to be of the quality on which EPA could base regulatory conclusions regarding (a) the need for emissions reductions, and (b) specific emissions control technologies.

The assessment of potential emissions reductions from non-EGU sources/units included in the Revised CSAPR Update proposal was prepared with data and methods for use in making regulatory decisions (e.g., establishing NOx emissions limits on non-EGU emissions sources/units). The assessment was independent of any previous assessments. For this assessment, the EPA included units with pre-control NOx emissions > 150 tpy, which is an emissions threshold that represents a comparable size to 25 MW for EGUs used in prior interstate transport rulemakings. To derive this emissions threshold, we used emissions expected from an average 25 MW EGU unit operating at a median heat rate, emission rate, and capacity factor for a coal-fired unit. A description of this derivation is below.

The CSAPR trading program is currently restricted to EGU sources greater than 25 MW electric generating capacity in the regulation. Since non-EGU sources/units are not all rated in electric generating capacity, we estimated an equivalent threshold for these sources/units on an annual NOx emissions basis. We estimated that 150 tons of NOx emissions per year is a reasonable approximation for the annual NOx emissions from a typical 25 MW EGU.

As mentioned above, this estimate represents a generic 25 MW EGU and relied on assumptions of three factors: heat rate, capacity factor, and NOx emissions rate. To develop an estimate for each of these factors, we evaluated a sample of EGUs ranging from 25 MW  -  30 MW, which represents the smallest EGUs currently included in the CSAPR trading program. This sample included nine units from the following six plants (ORIS codes): 50931, 2790, 50611, 50835, 57046, 2935. We excluded one outlier unit with a NOx rate that was nearly three times higher than the next highest NOx rate. We calculated the median and average heat rate and NOx rate for the remaining eight units based on the assumptions included in NEEDS v6 rev: 3-26-2020. We calculated the median and average annual capacity factor based on Air Markets Program data reported to EPA in 2019. These values are summarized below.

                                    Median
                                    Average
Heat Rate (Btu/kWh)
                                    12,140
                                    12,291
NOx Rate (lbs/MMBtu)
                                     0.18
                                     0.23
Capacity Factor (%)
                                      61%
                                      61%

The estimated annual emissions from a typical 25 MW unit based on the assumptions above ranges from about 141 annual tons (median values) to 188 annual tons (average values). Given the small sample size, we believe the median values are more representative than average values. Therefore, we estimated that 150 tons per year is a reasonable approximation of the annual NOx emissions at a typical 25 MW EGU. Since non-EGUs sources/units are not universally rated in MW electric generating capacity, we believe that NOx emissions of 150 tons per year is an equivalent threshold to a typical 25 MW EGU for use in this assessment.

Air Quality Impacts from Potential Non-EGU Emissions Reductions

Tables 7 and 8 below provide estimates of the air quality impacts at the Westport, CT receptor of the potential non-EGU emissions reductions in linked upwind states. We chose the Westport site for this assessment because it is likely the only site to remain a receptor during the time period when non-EGU controls could be implemented, assuming those controls take longer than 18 months to install. The results for Westport, CT are representative of the impacts for other coastal Connecticut receptors. In Tables 7 and 8 below, the air quality data are provided for individual upwind states and by industry sector, source category, and technology for all linked upwind states combined. Tables 7 and 8 (and the tables that follow) include potential emissions reductions in units of ozone season tons for appropriate comparison to potential EGU emissions reductions.

The estimated air quality impacts of the potential non-EGU emissions reductions are based on multiplying the estimated emissions reductions by the parts per billion (ppb) per ton values for each linkage. The ppb per ton values were derived from the state-by-state contribution modeling. Since the contribution modeling included emissions from all anthropogenic sources in each state, rather than just non-EGUs, the ppb per ton values used for this analysis introduce some degree of uncertainty in the results.

In addition, because the precursor emissions in the New York City portion of New York state are a large portion of the total state emissions and given the proximity of the coastal CT receptors to New York City, the contributions from the state of New York in the modeling largely reflect the contribution from emissions within New York City and adjacent areas of southern New York. As such, the ppb per ton values for New York based on the modeling are likely to overstate, by a large amount, the ppb per ton values from sources outside of New York City. In this assessment, the estimated impacts at Westport and other coastal CT receptors of the potential non-EGU emissions reductions in New York state are likely overstated because the ppb per ton values used in the calculations are dominated by the contributions from New York City, whereas the potential non-EGU emissions reductions are from emissions units in the western part of the state. Also note that there were no potential NOx emissions reductions from New Jersey because the projected 2023 emissions inventory did not include individual non-EGU point sources/emissions units in New Jersey with pre-control NOx emissions greater than 150 tpy for which CoST had applicable control measures.

Table 7. Non-EGU Emissions in 2023 and PPB Reductions at Westport, Connecticut
      for Individual Linked Upwind States

Table 8. Non-EGU Emissions in 2023 and PPB Reductions at Westport, Connecticut by
      Industry Sector or Source Category, Technology, and Weighted Average Cost Per Ton
      from Linked Upwind States

Further Verifying and Refining Estimated Non-EGU NOx Emissions Reduction Potential

Because information for existing controls on non-EGU emissions sources/units is missing in the 2016 base year inventory for some states and incomplete for some sources, the EPA went through a process to further verify existing control information and refine the NOx emission reduction potential estimated by CoST, the CMDb, and the 2023 projected inventory in Tables 3 through 6 above. The steps the EPA took, discussed in more detail below, include:
 Considered the air quality impacts by state and focused on upwind states with the largest estimated potential air quality impacts from potential non-EGU emission reductions;
 Assumed that the potential reductions in tranche 1 were potentially cost-effective because tranche 1's weighted average cost of $2,000 per ton (2016 dollars) is similar to the control stringency for EGUs represented by up to $1,800 per ton;
 Looked at potential emissions reductions in tranche 1 that were estimated to cost less than $2,000 per ton; and
 For those potential reductions in tranche 1 that were estimated to cost less than $2,000 per ton, reviewed online facility permits and industrial trade literature to verify and determine if the estimated emissions reductions may be actual, achievable emissions reductions or if the estimated emissions reductions were associated with emissions units that are already controlled.

First, we considered the potential ppb impacts by state in Table 7 and prioritized the verification and refinement of the NOx emission reduction potential for a subset of the states with the largest estimated potential air quality impacts. We reviewed potential controls and estimated emissions reductions in Pennsylvania, New York, Ohio, Indiana, and West Virginia. The EPA identified these states using an estimate of 0.02 ppb as a threshold for air quality improvement that may be obtained from reductions from non-EGUs in each state. The Agency is not applying a 0.02 ppb impact threshold as a step in the Step 3 multi-factor test. Rather, this threshold value allowed the Agency to better target its verification efforts (i.e., online permit review) toward the potentially effective states for non-EGU NOx emissions reductions. For the final rule, EPA extended its verification and refinement process for tranche 1 to additional linked states, including Maryland, Michigan, and Virginia.

Next, to continue analyzing potential emissions reductions in step 3 of the 4-step framework, we determined that the potential reductions in tranche 1 (Table 3 above) were potentially relatively cost-effective because the $2,000 cost per ton cost for reductions from non-EGU sources/units is similar to the control stringency for EGUs represented by up to $1,800 per ton. We made no determination as to whether the potential emissions reductions in tranche 2 were cost-effective because we assumed the up to $1,800 per ton control stringency for proposed reductions from EGU sources/units was an equivalent cost threshold for comparison. Note that between the Revised CSAPR Update proposed and final rules, we reviewed the potential controls for emissions sources/units in tranche 2 (Table 5 above). The emissions reductions from tranche 1 are in the section of Table 8 with the weighted average cost of $2,000 per ton (2016$), and the emissions reductions from tranche 2 are in the section with the weighted average cost range of $5,000 to $6,600 per ton. Tranche 1 includes:

 SCR:
 glass manufacturing  -  container, flat & pressed,
 IC engines  -  natural gas, oil (in pipeline transportation and oil & gas extraction industry sectors), and
 SNCR:
 cement manufacturing  -  dry and wet kilns,
      municipal waste combustors.

The total estimated potential emissions reductions from non-EGU sources/units in Pennsylvania, New York, Ohio, and Indiana in tranche 1 were 7,556 ozone season tons. Note that West Virginia dropped out because as indicated below CoST estimated control costs for two IC engines inappropriately, and CoST did not apply cost-effective controls to any other emissions units in the state. Below we note exceptions where in tranche 1 CoST applied cost-effective controls that were not included in the results.

 CoST applied controls to two IC engines in West Virginia for additional potential emissions reductions of 341 ozone season tons (in tranche 1 CoST did not apply controls to any other emissions units in the state). However, CoST estimated the control cost inappropriately, as it applied a cost equation to a source much larger than the predictive range of the equation. In such cases, CoST should apply a cost per ton value, which in this instance would be above the $2,000 per ton threshold for cost-effectiveness. As a result, it was determined that there are no actual controls available at the selected level of cost-effectiveness for these units. We reviewed the permits for these units -- the permit indicates that the units currently do not have control devices installed but do require periodic tune-ups and performance tests.
 CoST applied a control to an IC engine in Indiana for additional potential emissions reductions of 292 ozone season tons. Like the West Virginia controls, the cost of this control was underestimated for a source of this size, and the cost per ton for this source is above the threshold for cost-effectiveness. We reviewed the permit for this unit -- the permit indicates that the IC engine currently does not have a control device installed but does require performance tests and a preventive maintenance plan.

Next, we looked at the potential emissions reductions in tranche 1 that were estimated to cost <$2,000 per ton, which were 6,346 ozone season tons, or 84 percent of the estimated reductions in tranche 1 in these states; the remaining 16 percent of estimated reductions, or 1,210 ozone season tons, was above the $2,000 per ton threshold.

The steps taken to verify and refine the NOx emission reduction potential information were based first on technology application and related costs (as detailed above in the section on Model and Methodology for Assessing Non-EGU Emission Reduction Potential), then on a representative sample of states, and then on likely cost-effective reductions (i.e., reductions < $2,000 per ton) in those states, which led to key industry sectors; we did not directly select or eliminate key industry sectors to review for applicability or controls. In the review of the potential controls in tranche 1 for Pennsylvania, New York, Ohio, and Indiana, we concluded that the likely cost-effective emissions reductions were from SCR applied to glass furnaces and SNCR applied to cement kilns. Please see the additional discussion on these estimated emissions reductions in the section below titled Conclusions on Verification and Review of Controls on Non-EGU Sources in Four States and Potential Emissions Reductions.

Between the Revised CSAPR Update proposed and final rules, we reviewed the potential controls for emissions sources/units in tranche 1 for most of the remaining five states in Table 7. We reviewed the potential controls for emissions sources/units in Maryland, Michigan, and Virginia; we did not review the potential controls for emissions sources/units in Illinois because their permits were not available online, and we did not review the potential controls for sources/units in Kentucky because CoST did not identify applicable control measures for any emissions sources/units in the state. In tranche 1, we originally estimated 664 ozone season tons of likely cost-effective emissions reductions from these four states (excluding Kentucky). This additional review identified approximately 62 ozone season tons out of the estimated 664 ozone season tons that are from sources/units already controlled, leaving an estimated 602 ozone season tons of likely cost-effective emissions reductions from these states.

Detailed Verification and Review of Controls on Non-EGU Sources in Four States

After determining it was appropriate to verify the potential emissions reductions that were estimated to cost <$2,000 per ton, we took the additional step of verifying and refining the information on potential controls for emissions sources/units in tranche 1 for Pennsylvania, New York, Ohio, and Indiana. Note that West Virginia dropped out because CoST estimated control costs for two IC engines inappropriately, and CoST did not apply likely cost-effective controls to any other emissions units in the state. To verify and refine the information, we reviewed facilities' online Title V permits for likely cost-effective emissions reductions associated with SCR applied to glass furnaces and SNCR applied to cement kilns, and also reviewed industrial trade literature for these facilities and their parent companies.  These permit and industrial trade literature reviews were completed as of July 31, 2020.

By state, in Tables 9 through 12 below, we include information on 20 emissions units at glass manufacturing and cement manufacturing facilities including the facility name, NEI Unit ID, type of emissions unit, existing NOx control, NOx monitoring device, type of fuel used, and related notes. Of the 20 emissions units, 10 units either (i) have controls and monitors (primarily CEMS) already, (ii) are installing controls and CEMS or consolidating operations in the next few years as a result of recent consent decrees issued as part of the EPA's New Source Review Air Enforcement Initiative, (iii) have shut down, or (iv) are planning to shut down by 2023. In addition, we find that most of the emissions units are natural gas-fired, though a few of the cement kilns can fire either coal or oil.  Based on information collected through the permit review, we believe the units in categories (i) and (iii) don't present an opportunity to generate emissions reductions as part of this analysis and should be removed from further consideration. With respect to categories (ii) and (iv), for purposes of a focused analysis of potential cost-effective non-EGU emissions reductions, we excluded these units from further consideration.

Reviewing online facility permits does not always resolve outstanding questions. Permits can be 100 pages or more in length with detailed information about a facility and the units at the facility, and the accuracy and extent of information can vary by state. Matching NEI information to information in the permit is not always straight forward. For example, the NEI Unit IDs don't always match the unit ID information in the permit and even more research or refinement is needed.

Table 9. Pennsylvania Glass Manufacturing Facilities
Facility Name/NEI Unit ID
Ultimate Parent Company
Type of Emissions Unit
County
2023 Projected NOx Emissions
Estimated Reductions
(OS Tons) from SCR
Existing NOx Control
NOx Monitoring Device/
Technique
Fuel Used by Furnace
Other Notes
Status of Estimated Reductions
Ardagh Glass Inc/Port Allegany Plt
(NEI Unit ID 19110913)
Ardagh Group S.A.
Container Glass: Melting Furnace
McKean
                                                                            152
                                                                          47.43
LNB + OEAS
CEMS
Natural Gas
194.73 tons annual emissions limit
Remove from consideration (Already controlled)
Vitro Flat Glass LLC/Carlisle
(NEI Unit ID 18725313)
 Vitro, Inc.
Flat Glass: Melting Furnace
Cumberland
                                                                         10,514
                                                                       3,285.65
No Control
CEMS
Natural Gas/Oil #2 (permitted for both fuels; natural gas is the typical fuel used)
Emissions limit of 26.75 lb/ton glass produced
Uncertain  -  see notes below
(NEI discrepancy)
Vitro Flat Glass LLC/Carlisle
(NEI Unit ID 18725413)
Vitro, Inc.
Flat Glass: Melting Furnace
Cumberland
                                                                          1,236
                                                                         386.27
SCR
CEMS
Natural Gas/Oil #2 (permitted for both fuels; natural gas is the typical fuel used)
Emissions limit of 7.0 lb/ton glass produced
Remove from consideration (Already controlled)
Pittsburgh Glass Works/Meadville Works 8,
(NEI Unit ID 19025613)
Vitro, Inc.
Flat Glass: Melting Furnace
Crawford
                                                                          1,739
                                                                         543.49
No Control
CEMS
Natural Gas
766.5 tons annual emissions limit
Uncertain  -  closed a line on June 10, 2020 (Shutdown)
Guardian Ind Corporation/Jefferson Hills
(NEI Facility ID 2989611)

Allegheny
                                                                            512
                                                                         159.93

Facility closed at end of 2015.
Remove from consideration (Shutdown)
                                                                       Subtotal

                                                                       4,422.77

Table 10. New York Glass Manufacturing Facilities
Facility Name/NEI Unit ID
Ultimate Parent Company
Type of Emissions Unit
County
2023 Projected NOx Emissions
Estimated Reductions
(OS Tons) from SCR
Existing NOx Control
NOx Monitoring Device/
Technique
Fuel Used by Furnace
Other Notes
Status of Estimated Reductions
Anchor Glass Container Corp
(NEI Unit ID 2854113)
Anchor Glass Container Corp

Container Glass: Melting Furnace
Chemung
                                                                            450
                                                                         140.63
Two furnaces  -  Furnace #1  -  SCR; Furnace #2  -  no control
CEMS
Natural Gas
Furnace #1 has an annual emissions limit of 1.2 lb NOx/ton of glass produced.
Furnace #2 has an annual emissions limit of 4.5 lb NOx/ton of glass produced.
Possible
(Possible emissions reductions)
Owens Brockway Glass Container Inc
(NEI Unit ID 2863113)
O-I Glass, Inc.
Container Glass: Melting Furnace
Cayuga
                                                                            309
                                                                          96.69
Two furnaces  -  No controls indicated
CEMS
Natural Gas
Furnace A has an annual emissions limit of 4.0 lb NOx/ton of glass produced. Furnace B has an annual emissions limit of ?
Possible
(Possible emissions reductions)
Guardian Geneva Float Glass Facility
(NEI Unit ID 18725413)
Koch Industries, Inc.
Flat Glass: Melting Furnace
Ontario
                                                                            790
                                                                         246.83
SCR
CEMS
Natural Gas
Annual emissions limit of 770 tons
Remove from consideration (Already controlled)
                                                                       Subtotal

                                                                         484.15

Table 11. Ohio Glass Manufacturing Facility
Facility Name/NEI Unit ID
Ultimate Parent Company
Type of Emissions Unit
County
2023 Projected NOx Emissions
Estimated Reductions
(OS Tons) from SCR
Existing NOx Control
NOx Monitoring Device/
Technique
Fuel Used by Furnace
Other Notes
Status of Estimated Reductions
Pilkington North America Inc.
(NEI Unit ID 55204113)

Flat Glass: Melting Furnace
Wood
                                                                            755
                                                                            236
Two furnaces - None indicated for furnace #1; 3R technology for furnace #2 (technology is proprietary)
CEMS
Natural Gas or Oil (permitted for both; natural gas the typical fuel used)
Furnace #1 has annual emissions limit of 364.7 tons  -  a recent stack test show emissions at the furnace are 41.64 tons NOx.
Furnace #2 has an annual emissions limit of 945 tons -- CEMS data show recent emissions of 792.98 tons.
Uncertain  -  recent stack test shows emissions well below permit limit
(Already controlled)
                                                                       Subtotal

                                                                            236

Table 12. Indiana Glass Manufacturing and Cement Manufacturing Facilities
Facility Name/NEI Unit ID
Ultimate Parent Company
Type of Emissions Unit
County
2023 Projected NOx Emissions
Estimated Reductions
(OS Tons) from SCR and SNCR
Existing NOx Control
NOx Monitoring Device/
Technique
Fuel Used by Furnace
Other Notes
Status of Estimated Reductions
Ardagh Glass Inc.
(NEI Unit ID 65375713)
Ardagh Group S.A.
Container Glass: Melting Furnace
Randolph
                                                                            312
                                                                          97.63
No Control
No monitors
Natural Gas
Furnace #2 has an annual emissions limit of 506.9 tons. This furnace may be emitting under its permit limit.
Possible
(Possible emissions reductions)
Ardagh Glass Inc.
(NEI Unit ID 65375813)
Ardagh Group S.A.
Container Glass: Melting Furnace
Randolph
                                                                            280
                                                                          87.65
No Control
No monitors
Natural Gas
Furnace #1 has an annual emissions limit of 389.24 tons. This furnace may be emitting under its permit limit.
Possible
(Possible emissions reductions)
Anchor Glass Container Corporation
(NEI Unit ID 28314513)
Anchor Glass Container Corp.
Container Glass: Melting Furnace
Dearborn
                                                                            276
                                                                          86.28
No control
No monitors
Natural Gas
Facility-wide annual emissions limit of 396 tons, which likely includes additional emissions sources.
Possible
(Possible emissions reductions)
Lehigh Cement Company
(NEI Unit ID 5813813)
Heidelberg Cement
Long Kiln
Clark
                                                                            187
                                                                          38.89
SNCR
CEMS
Natural Gas (coal or oil as backup fuels)
NOx control & monitoring required under consent decree (Essroc). Plant to cease operations during 2022.
Remove from consideration (Shutdown)
Lehigh Cement Company
(NEI Unit ID 5813313)
Heidelberg Cement
Preheater Kiln
Clark
                                                                            394
                                                                          82.08
SNCR
CEMS
Natural Gas (coal or oil as backup fuels)
NOx control & monitoring required under consent decree (Essroc). Plant to cease operations during 2022.
Remove from consideration
(Shutdown)
Lehigh Cement Company
(NEI Unit ID 4232613)
Heidelberg Cement
Preheater Kiln
Lawrence
                                                                            552
                                                                         115.09
No control
No monitoring
Natural gas
Plant is subject to NOx requirements in consent decree; a single kiln will replace all 3 preheater kilns in 2023. Permit indicates MKF or LNB as controls for ozone season, but no evidence of installation.
Remove from consideration
(Lehigh Cement  -  kiln replacements)
Lehigh Cement Company
(NEI Unit ID 4232813)
Heidelberg Cement
Preheater Kiln
Lawrence
                                                                            495
                                                                         103.21
No control
No monitoring
Natural gas
Plant is subject to NOx requirements in consent decree; a single kiln will replace all 3 preheater kilns in 2023. Permit indicates MKF or LNB as controls for ozone season, but no evidence of installation.
Remove from consideration
(Lehigh Cement  -  kiln replacements)
Lehigh Cement Company
(NEI Unit ID 4233913)
Heidelberg Cement
Preheater Kiln
Lawrence
                                                                            711
                                                                         148.10
No control
No monitoring
Natural gas
Plant is subject to NOx requirements in consent decree; a single kiln will replace all 3 kilns by 2023. Plant is subject to NOx control by MKF or LNB in ozone season, but no evidence of installation.
Remove from consideration
(Lehigh Cement  -  kiln replacements)
Lehigh Cement Company
(NEI Unit ID 65392513)
Heidelberg Cement
Wet Kiln
Cass
                                                                            314
                                                                          65.49
WI (water injection)
CEMS
Coal or oil
Kiln #2 has an emissions limit of 4.75 lb NOx/ton clinker produced
Possible (Possible emissions reductions)
Lehigh Cement Company
(NEI Unit ID 65392613)
Heidelberg Cement
Wet Kiln
Cass
                                                                            242
                                                                          50.33
SNCR + WI
CEMS
Coal or oil
Kiln #1 does not have an emissions limit indicated in the permit
Remove from Consideration
(Already controlled)
Lone Star Industries Inc.
(NEI Unit ID 9180513)
Buzzi Unicem
Semi-Dry Kiln
Putnam
                                                                          1,578
                                                                         328.66
Low NOx calciner + good combustion practice (GCP)
CEMS
Coal or Oil
Kiln has an emissions limit of 5.514 lb NOx/ton of clinker produced
Possible
(Possible emissions reductions)
                                                                       Subtotal

                                                                       1,203.41

Conclusions of Verification and Review of Controls on Non-EGU Sources in Four States and Potential Emissions Reductions

CoST identified likely cost-effective (i.e., $2,000 per ton or less) control technologies for 20 emissions units at glass manufacturing and cement manufacturing facilities in Pennsylvania, New York, Ohio, and Indiana. None of these units are owned by small businesses as defined by the Small Business Administration's (SBA) small business size standards for these two industry sectors. The total potential emissions reductions in Pennsylvania, New York, Ohio, and Indiana in tranche 1 were 7,556 ozone season tons. We looked at potential emissions reductions in tranche 1 that were estimated to cost <$2,000 per ton (likely cost-effective), which were 6,346 ozone season tons. We reviewed online permits for these 20 units and as indicated in Tables 9 through 12, 10 of these units either (i) have controls and monitors (primarily CEMS) already, (ii) are installing controls and CEMS or consolidating operations in the next few years as a result of recent consent decrees issued as part of the EPA's New Source Review Air Enforcement Initiative, (iii) have shutdown, or (iv) are planning to shut down by 2023. Table 13 below summarizes the status of the potential NOx emissions reductions.

Table 13. Status of Estimated Potential Emissions Reductions

                             # of Emissions Units
                                    OS Tons
                                 (% of Total)
Shutdowns
                                       4
                                      824
                                      13
Lehigh Cement - Kiln Replacements
                                       3
                                      366
                                       6
NEI Discrepancy/Uncertain
                                       1
                                     3,286
                                      51
Already Controlled/Uncertain
                                       5
                                      967
                                      15
Possible Emissions Reductions
                                       7
                                      903
                                      14
                                                                          TOTAL
                                      20
                                     6,346

Based on the 2023 projected inventory, the emissions reductions from the plant shutdowns and consolidated operations (between 2015 and 2023) are estimated to be approximately 824 tons, or 13 percent of the potentially cost-effective ozone season emissions reductions in tranche 1. These emissions reductions are not currently reflected in the estimated air quality impacts shown above in Tables 7 and 8.

In addition, for the Lehigh Cement manufacturing facility in Lawrence County, Indiana (emissions reductions estimated to be 366.40 tons, or 6 percent of the potentially cost-effective ozone season emissions reductions in tranche 1) that is subject to a consent decree, the 2023 projected inventory emissions are 1,758 tons and we currently do not know what the expected emissions reductions may be. We have found that the three older kilns currently in operation will shut down by 2023 and be replaced with a single new kiln whose production capacity will be almost 3 times as large (2.8 million tons of clinker compared to 1 million tons of clinker currently) and whose NOx emissions are unknown.

Ten facilities, summarized again below in Table 14, were estimated to have the potential to generate some emissions reductions. However, results from the review of online permit review and industrial trade literature suggest that some of those potential reductions may not be true potential reductions. The status of the potential reductions at the ten facilities is summarized below, along with an assessment of the likelihood that recommended controls could generate emissions reductions. The assessment for each facility concludes with either "uncertain" or "possible" depending on the likelihood of potential emissions reductions.

 Vitro Flat Glass LLC/Carlisle, PA (NEI Unit ID 18725313), 3,285.65 OS tons  -  The cost per ton and estimated emissions reductions for this emissions unit reflect a high degree of uncertainty. The uncertainty comes from the following two sources: (i) discrepancies between the underlying information for this unit in the 2023 projected inventory and other more recent emissions data reported to the state, and (ii) the equation in CoST that is used to estimate the emissions reductions and cost per ton value. In the 2023 projected inventory, the pre-control 2023 emissions for one of the emissions units (10,514 tons) are much larger than what appears in the 2018 PA Air Emissions Report for the entire facility (1,770 tons) and six times larger than any other glass furnace in this analysis. This discrepancy in emissions (roughly 8,700 tons) likely leads to an overestimate of potential emissions reductions (3,285.65 ozone season tons, or 51 percent of the likely cost-effective ozone season emissions reductions in tranche 1) that are not currently reflected in the estimated air quality impacts shown above in Tables 7 and 8. If total facility emissions are approximately 1,770 annual tons (or 737.5 ozone season tons), it is not possible to achieve 3,285 tons of ozone season reductions from only one unit at the facility. In addition, the projected inventory does not show a control on any unit at this facility, even though a review of the permit indicates that one unit does have a control.
      Emission Reduction Potential: Uncertain, 2023 projected inventory discrepancy

 Pittsburgh Glass Works/Meadville Works 8, PA (NEI Unit ID 19025613), 543.49 OS tons -- This facility shut down one of its two production lines effective June 10, 2020. The company stated that it is too expensive to rebuild the production line.
      Emission Reduction Potential: Uncertain, potentially shutdown

 Anchor Glass Container Corp, NY (NEI Unit ID 2854113), 140.63 OS tons -- Furnace #2 has an annual emissions limit of 4.5 lb NOx/ton of glass produced and no current control.
Emission Reduction Potential: Possible

 Owens Brockway Glass Container Inc., NY (NEI Unit ID 2863113), 96.69 OS tons  -  The permit shows two furnaces with no controls.
Emission Reduction Potential: Possible

 Pilkington North America Inc., OH (NEI Unit ID 55204113), 236 OS tons  -  In the permit, Furnace #1 was listed with an annual emissions limit of 364.7 tons, but a recent stack test indicates emissions at the furnace are 41.64 tons of NOx.
      Emission Reduction Potential: Uncertain, potentially already controlled

 Ardagh Glass Inc., IN (NEI Unit ID 65375713), 97.63 OS tons  -  In the permit, Furnace #2 has an annual emissions limit of 506.9 tons and the 2023 projected emissions are 312 tons. It is possible the source is currently operating under its permit limit.
      Emission Reduction Potential: Possible

 Ardagh Glass Inc., IN (NEI Unit ID 65375813), 87.65 OS tons  -  In the permit, Furnace #1 has an annual emissions limit of 389.24 tons and the 2023 projected emissions are 280 tons. It is possible the source is currently operating under its permit limit.
      Emission Reduction Potential: Possible

 Anchor Glass Container Corporation, IN (NEI Unit ID 28314513), 86.28 OS tons  -  Facility-wide annual emissions limit of 396 tons, which likely includes additional emissions sources.
Emission Reduction Potential: Possible

 Lehigh Cement Company, IN (NEI Unit ID 65392513), 65.49 OS tons  -  Currently uses water injection as control technology.
Emission Reduction Potential: Possible

 Lone Star Industries Inc., IN (NEI Unit ID 9180513), 328.66 OS tons  -  Currently uses low NOx calciner + good combustion practice (GCP) as control technology.
Emission Reduction Potential: Possible

Table 14. Potential Emissions Reductions from Glass Manufacturing Facilities in Pennsylvania, New York, Ohio, and Indiana
Facility Name/NEI Unit ID
Type of Emissions Unit
County (State)
2023 Projected NOx Emissions
Estimated Reductions
(OS Tons)
Existing NOx Control
NOx Monitoring Device/
Technique
Status of Estimated Reductions
Vitro Flat Glass LLC/Carlisle
(NEI Unit ID 18725313)
Flat Glass: Melting Furnace
Cumberland (PA)
                                                                         10,514
                                                                       3,285.65
No Control
CEMS
Uncertain, NEI discrepancy
Pittsburgh Glass Works/Meadville Works 8
(NEI Unit ID 19025613)
Flat Glass: Melting Furnace
Crawford (PA)
                                                                          1,739
                                                                         543.49
No Control
CEMS
Uncertain, potentially shutdown
Anchor Glass Container Corp
(NEI Unit ID 2854113)

Container Glass: Melting Furnace
Chemung (NY)
                                                                            450
                                                                         140.63
Two furnaces  -  Furnace #1  -  SCR; Furnace #2  -  no control
CEMS
Possible
Owens Brockway Glass Container Inc
(NEI Unit ID 2863113)
Container Glass: Melting Furnace
Cayuga (NY)
                                                                            309
                                                                          96.69
Two furnaces  -  No controls indicated
CEMS
Possible
Pilkington North America Inc.
(NEI Unit ID 55204113)
Flat Glass: Melting Furnace
Wood (OH)
                                                                            755
                                                                            236
Two furnaces - None indicated for furnace #1; 3R technology for furnace #2 (technology is proprietary)
CEMS
Uncertain, potentially already controlled
Ardagh Glass Inc.
(NEI Unit ID 65375713)
Container Glass: Melting Furnace
Randolph (IN)
                                                                            312
                                                                          97.63
No Control
No monitors
Possible
Ardagh Glass Inc.
(NEI Unit ID 65375813)
Container Glass: Melting Furnace
Randolph (IN)
                                                                            280
                                                                          87.65
No Control
No monitors
Possible
Anchor Glass Container Corporation
(NEI Unit ID 28314513)
Container Glass: Melting Furnace
Dearborn (IN)
                                                                            276
                                                                          86.28
No control
No monitors
Possible
Lehigh Cement Company
(NEI Unit ID 65392513)
Wet Kiln
Cass (IN)
                                                                            314
                                                                          65.49
WI (water injection)
CEMS
Possible
Lone Star Industries Inc.
(NEI Unit ID 9180513)
Semi-Dry Kiln
Putnam (IN)
                                                                          1,578
                                                                         328.66
Low NOx calciner + good combustion practice (GCP)
CEMS
Possible

In summary, the total potential emissions reductions in Pennsylvania, New York, Ohio, and Indiana in tranche 1 were 7,556 ozone season tons. We looked at potential emissions reductions in tranche 1 that were estimated to cost <$2,000 per ton, which were 6,346 ozone season tons. Between unit shutdowns and potentially incorrect emissions data in the 2023 projected inventory (and the resulting infeasible estimate of potential emissions reductions), of the 6,346 tons approximately 4,110 tons, or 64 percent, of the likely cost-effective emissions reductions are not or may not be true, achievable emissions reductions. The potential emissions reductions associated with applying CoST-recommended controls that are considered possible are 903 ozone season tons, or 14 percent of the likely cost-effective emissions reductions.

Also, as noted above in the section Further Verifying and Refining Estimated Non-EGU NOx Emissions Reduction Potential, between the Revised CSAPR Update proposed and final rules, we reviewed the potential controls for emissions sources/units in tranche 1 for additional linked states in Table 7 -- Maryland, Michigan, and Virginia. We did not review the potential controls for emissions sources/units in Illinois because their permits were not available online, and we did not review the potential controls in Kentucky because CoST did not identify applicable control measures for any emissions sources/units in the state. In tranche 1, we originally estimated 664 ozone season tons of likely cost-effective emissions reductions from these four states (excluding Kentucky). This additional review identified approximately 62 ozone season tons out of the estimated 664 ozone season tons that are from sources/units already controlled, leaving an estimated 602 ozone season tons of likely cost-effective emissions reductions from these states.

Finally, between the proposed and final rules, we also reviewed the potential controls for emissions sources/units in tranche 2 (Table 5 above). Of the approximately 11,119 ozone season tons of estimated emissions reductions, ten percent of those reductions are from sources/units already controlled.

Caveats and Limitations of the Cost Analysis

The EPA acknowledges several important caveats and limitations of the non-EGU cost assessment included in this memorandum, which include the following:

Boundary of the cost analysis: In this cost analysis we include only the impacts to the sectors and facilities that are the focus of this analysis. We include the costs for purchase, installation, operation, and maintenance of control equipment over the lifetime of the equipment. Recordkeeping, reporting, testing and monitoring costs are not included. Additional revenue may be generated by vendors that would build, install, and test new control technologies for use at sources in the directly affected sectors, especially for control equipment manufacturers, distributors, or service providers. These revenue and employment impacts are not included in this cost analysis.

Cost and effectiveness of control technologies: The application of control technologies reflect average retrofit factors nationally and average estimates of equipment life. We do not account for regional or local variation in capital and annual cost items such as energy, labor, and materials. The estimates of control technology costs may over- or under-estimate the costs depending on how the difficulty of actual retrofitting and equipment life compares with the control and cost assumptions. In addition, the estimates of control efficiencies for control technologies included in the assessment assume that the control devices are properly installed and maintained.

Interest rate:  We apply an interest rate of 7 percent to annualize capital costs in the analysis.  In addition, while this interest rate may potentially be consistent with guidance as found in the EPA Air Pollution Control Cost Manual, (hereafter called the "Control Cost Manual") the actual interest rate may vary for control cost estimation at each facility included in this analysis.

Accuracy of control costs: We estimate that there is an accuracy range of +/- 30 percent for non-EGU point source control cost estimates. This level of accuracy is described in the Control Cost Manual, which is a basis for the estimation of non-EGU control cost estimates included in this memorandum. This level of accuracy is consistent with either the budget or bid/tender level of cost estimation (or Class 4) as defined by the American Association for Cost Engineering International (AACEI) and explained in Section 1, Chapter 2 of the Control Cost Manual. In addition, the accuracy of costs is also influenced by the availability and extent of data underlying the cost estimates for individual control technologies.

Control Installation Timing

We previously examined the time necessary to install the controls listed above for different industries. The 2016 Final Technical Support Document (TSD) for the Final Cross-State Air Pollution Rule for the 2008 Ozone NAAQS, Assessment of Non-EGU NOx Emission Controls, Cost of Controls, and Time for Compliance Final TSD (CSAPR Update non-EGU TSD) provided preliminary estimates of installation times for a variety of NOx control technologies applied to a large number of sources in non-EGU industry sectors. For virtually all NOx controls applied to cement manufacturing and glass manufacturing units, information on installation times was not available to provide an estimate, and we concluded that the installation time for these controls was "uncertain." There was an exception for SNCR applied to cement kilns, and the installation time estimate of 42-51 weeks listed in the CSAPR Update non-EGU TSD does not account for implementation across multiple sources, the need to have NOx monitors installed, and other steps in the permitting and construction processes.

To improve upon information from the CSAPR Update Non-EGU TSD on installation times for SCR on glass furnaces and SNCR on cement kilns, EPA reviewed information from recent permitting actions and a consent decree. For two glass manufacturing facilities that installed SCR on glass furnaces, from the time of permit application to the time of SCR operation was approximately 19 months for one facility and is currently at least 20 months for another facility. These installation times do not reflect time needed for pre-construction design and engineering, financing, and factors associated with scaling up construction services for multiple installations at several emissions units. With respect to cement kilns, an April 2013 consent decree between EPA and CEMEX, Inc. required installation of SNCR at a kiln within 450 days, or approximately 15 months, of the effective date of the consent decree. Similarly, this installation time does not reflect time associated with scaling up construction services for multiple control installations at several emissions units.

Request for Comment and Additional Information

To develop a more complete record, at proposal the EPA requested comment on several questions related to specific control strategies the Agency evaluated, and in particular sought feedback and data from stakeholders with relevant expertise or knowledge. For a general discussion of comments received and Agency responses, please see the Revised Cross-State Air Pollution Rule Update for the 2008 Ozone NAAQS final rule preamble. For the detailed comments and responses, please see and the Non-EGUs section in the Revised Cross-State Air Pollution Rule Update for the 2008 Ozone Season NAAQS  -  Response to Comment document available in the docket.

As indicated above, information about existing controls on non-EGU emissions sources/units in the inventory was missing for some states and incomplete for some sources/units. The approach the EPA used was to assess emission reduction potential using CoST and the projected 2023 inventory to identify emissions units that were uncontrolled. Given that the EPA's assessment of any other NOx control strategies would also rely on CoST, the CMDb, and the inventory to identify emissions units that were uncontrolled and to assess emission reduction potential from non-EGU sources/units, the Agency believed such an assessment would likely lead to a similar conclusion that estimated emission reduction potential is uncertain.

As such, for this and future regulatory efforts, to improve the underlying data used in an assessment of emission reduction potential from non-EGU sources, we requested comments on: (i) the existing assessment of emission reduction potential from glass furnaces and cement kilns; (ii) emission reduction potential from other control strategies or measures on a variety of emissions sources/units in several industry sectors; and (iii) the feasibility of further controlling NOx from IC engines and large ICI boilers, including optimizing combustion and installing ultra-low NOx burners. The three sections below introduce the areas for comment and describe workbooks generated by CoST, the CMDb, and the 2023 projected inventory with the underlying data to review.

First, the EPA requested comment on the aspects of the assessment presented above of emission reduction potential from the glass and cement manufacturing sectors. To help inform review and comments, the Agency referred commenters to the following Excel workbooks available in the docket: (i) for a summary of the CoST run results CoST Control Strategy - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling - No Replace - 07-23-2020, and (ii) for summaries of emissions reductions by control technologies, Control Summary - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling  -  No Replace  -  05-18-2020. Note that the CoST Control Strategy - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling - No Replace - 07-23-2020 Excel workbook includes a READ ME worksheet that provides details on the parameters used for the CoST run.

Specifically, the EPA solicited comment on the following:
 Are applying SCR to uncontrolled or under-controlled glass furnaces and SNCR to uncontrolled or under-controlled cement kilns in the linked states feasible approaches to achieve cost-effective emissions reductions? If not, what types of cost-effective controls can be applied to these sources?
 Does the EPA have the right and most up to date information on emissions and existing control technologies for the units included in this assessment? If not, what is the correct and more up to date information?
 After looking at the underlying CoST run results, are the cost estimates accurate and reasonable? If not, what are more accurate cost estimates?
 What is the earliest possible installation time for SCR on glass furnaces?
 What is the earliest possible installation time for SNCR on cement kilns?
 For the non-EGU facilities without any emissions monitors, what would CEMS cost to install and operate? How long would CEMS take to program and install?

In addition to the assessment of emission reduction potential from the glass and cement manufacturing sectors, for the 12 linked states the EPA attempted to summarize all potential control measures for emissions units with 150 tpy or more pre-control NOx emissions in 2023 in several industry sectors. This information illustrated that there are many potential approaches to assessing emissions reductions from non-EGU emissions sources or units. We used the Least Cost Control Measure worksheet from a CoST run. By state for the 12 linked states and then by facility, this information was summarized in the Excel workbook titled CoST Control Possibilities $10k 150 tpy cutoff 12 States Updated Modeling - 06-30-2020, also available in the docket.

Second, specifically the EPA requested comment on the following:
 Other than glass and cement manufacturing, are there other sectors or sources that could achieve potentially cost-effective emissions reductions? What are those sectors or sources? What control technologies achieve the reductions? What are cost estimates and installation times for those control technologies?
 Are there other sectors where cost effective emission reductions could be obtained by, in lieu of installing controls, replacing older, higher emitting equipment with newer equipment?
 Are there sectors or sources where cost effective emission reductions could be obtained by switching from coal-fired units to natural gas-fired units?
 For non-EGU sources/units without emissions monitors, what would CEMS cost to install and operate? How long would CEMS take to program and install? Are monitoring techniques other than CEMS, such as predictive emissions monitoring systems (PEMS), sufficient for certain non-EGU facilities that would not be brought into a trading program? If so, for what types of non-EGU facilities, and under what circumstances, would PEMS be sufficient? What would be the cost to install and operate monitoring techniques other than CEMS?

Third, in the workbook titled CoST Control Possibilities $10k 150 tpy cutoff 12 States Updated Modeling - 06-30-2020 the EPA included two worksheets with information on controls for ICI boilers and IC engines: (i) Boilers  -  ULNB and (ii) IC Engines - LEC. For the 12 linked states, the EPA summarized CoST's application of ultra-low NOx burners (ULNB) on ICI boilers and low emission combustion (LEC) on IC engines. Assuming that the estimated emissions reductions from CoST's application of these controls are real and cost-effective in the context of this ozone transport rule, there could be approximately 5,000 ozone season tons of emissions reductions from 52 ICI boilers and 8,000 ozone season tons of emissions reductions from 69 IC engines. This information is summarized in Table 15 below.

Table 15. Summary of Potential Emissions Reductions from ULNB on ICI Boilers and LEC on IC Engines

                                  ICI Boilers
                                  IC Engines
Number of Emissions Units in the 12 Linked States (>150 tpy NOx emissions)
                                      52
                                      69
2023 Projected Total NOx Emissions in the 12 Linked States (ozone season tons, reflects any existing control before ULNB or LEC were applied)
                                     6,779
                                     9,260
2023 Projected Total NOx Emissions in the 12 Linked States after Applying ULNB to Boilers (ozone season tons)
                                     1,695
                                      --
2023 Projected Total NOx Emissions in the 12 Linked States after Applying LEC to IC Engines (ozone season tons)
                                      --
                                     1,231

Number of Units with No Known Existing Control
                                      51
                                      57

The EPA requested comments on the feasibility of further controlling NOx from IC engines and large ICI boilers, including optimizing combustion and installing low NOx burners. The Agency understands that it is generally possible to install low NOx burners on EGU boilers fairly quickly and that these burners can significantly reduce NOx emissions. We note that in the original interstate transport rule, the NOx SIP call, the Agency concluded that controls on large, non-EGU boilers and turbines were cost effective and allowed states to include those emissions sources in their budgets as a means of providing additional opportunities to reduce state-wide NOx emissions in a cost-effective manner. Therefore, we solicited comment on whether the EPA should require that large non-EGU boilers and turbines -- as defined in the NOx SIP call as boilers and turbines with heat inputs greater than 250 mmBTU per hour or with NOx emissions greater than 1 ton per ozone season day -- within the 12 states employ controls that achieve emissions reductions greater than or equal to what can be achieved through the installation of low NOx burners.  In their comment on the Revised CSAPR Update proposal, the Council of Industrial Boiler Owners (CIBO) indicated that many of their members' industrial boilers already have low NOx burners installed, and that they are installed for the sole purpose of reducing NOx emissions and are thus an add-on controls.

Also, five of the 12 states that are subject to this rulemaking are also within the Ozone Transport Region (OTR) -- Maryland, New Jersey, New York, Pennsylvania, and Virginia. As member states of the OTR, these five states are required under the Clean Air Act to implement reasonably available control technology (RACT) state-wide on major sources of emissions. It is likely that NOx controls, such as low NOx burners, are already in wide-spread use within these five states, which is consistent with the statement above from CIBO's comment on NOx controls installed on industrial boilers. However, such controls may not be as widely used in states outside of the OTR. Therefore, we also solicited comment on the (i) magnitude of the emissions reductions that could be achieved by requiring that large non-EGU boilers and turbines install controls that achieve emissions reductions greater than or equal to what could be achieved through the installation of low NOx burners, (ii) prevalence of these or better NOx controls already in place on this equipment in these 12 states, and (iii) time it typically takes to install such controls.

In addition to the above, the EPA requested comments on the following:
 How effective are ultra-low NOx burners or low NOx burners in controlling NOx emissions from ICI boilers?
 Are they generally considered part of the process or add-on controls? If they are part of a process, how could the EPA estimate the cost associated with changing the process to accommodate ultra-low NOx burners and low NOx burners?
 What are the costs (capital and annual) for these as add-on control technologies on ICI boilers?
 What are the earliest possible installation times for these control technologies on ICI boilers? The EPA believes it is generally possible to install low NOx burners on EGU boilers relatively quickly and that low NOx burners can significantly reduce NOx emissions. The EPA solicits comment on whether this is also true for large non-EGU ICI boilers.
 Do some of the emissions units included in the summary already have either add-on controls or controls that are part of a process? If so, what control is on the unit and what is the control device (or removal) efficiency?
 Natural gas compressor stations are the largest NOx-emitting non-EGU sector affecting the 12 states that are the subject of the proposal, and many of these facilities are powered by decades-old, uncontrolled IC engines. Should emissions reductions be sought from the IC engines at these stations, either through installing controls, upgrading equipment, or other means?
 How effective is low emission combustion in controlling NOx from IC engines?
 What is the cost (capital and annual) for low emission combustion on IC engines?
 What is the earliest possible installation time for low emission combustion on IC engines? In lieu of installing controls, is replacing older, higher emitting equipment with newer equipment a cost-effective way to reduce emissions from IC engines?
 Do some of the emissions units included in the summary already have either add-on controls or controls that are part of a process? If so, what control is on the unit and what is the control device (or removal) efficiency?

In a comment on the Revised CSAPR Update proposal from the American Forest and Paper Association (AF&PA) and the American Wood Council (AWC), the organizations asserted that up to 4 years are required for implementation of NOx controls at industrial boilers at their facilities when considering all aspects of installation such as design, engineering, permitting, procurement, and installation. These associations also stated that project timelines would increase with implementation of a NOx regional rule, since many facilities would be competing for the same vendor expertise.

Attachments

 CoST Control Strategy - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling - No Replace - 07-23-2020.xlsx
 Control Summary - Max Reduction $10k 150 tpy cutoff 12 States Updated Modeling  -  No Replace  -  05-18-2020.xlsx
 CoST Control Possibilities $10k 150 tpy cutoff 12 States Updated Modeling - 06-30-2020.xlsx
 2017 NEI Data_Twelve States_Merged_Greater than 100 Tons.xlsx


[Federal Register: July 14, 2010 (Volume 75, Number 134)]
[Notices]
[Page 40846-40847]
[DOCID:fr14jy10-97]

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    Form Titles and Numbers: No Form.
    Abstract: The State Administrative Plan is a procedural guide that
details how the State will administer the Hazard Mitigation Grant
Program (HMGP). An approved plan is a prerequisite of receiving HMGP
funds and is used by FEMA in making a determination of the approval for
a grant and how much each grant will be. The administrative plan may
take any form including a chapter within a comprehensive State
mitigation program strategy.
    Affected Public: State, local, or Tribal Government.
    Estimated Number of Respondents: 32.
    Frequency of Response: On Occasion.
    Estimated Average Hour Burden per Respondent: 16 Hours.
    Estimated Total Annual Burden Hours: 512 Hours.
    Estimated Cost: There are no capital, operations and maintenance,
or start-up costs associated with this collection.

    Dated: July 7, 2010.
Tammi Hines,
Acting Director, Records Management Division, Mission Support Bureau,
Federal Emergency Management Agency, Department of Homeland Security.
[FR Doc. 2010-17084 Filed 7-13-10; 8:45 am]
BILLING CODE 9110-13-P


[Federal Register Volume 80, Number 101 (Wednesday, May 27, 2015)]
[Proposed Rules]
[Pages 30181-30182]
[FR Doc No: 2015-12570]

========================================================================
Proposed Rules
                                                Federal Register
________________________________________________________________________

This section of the FEDERAL REGISTER contains notices to the public of
the proposed issuance of rules and regulations. The purpose of these
notices is to give interested persons an opportunity to participate in
the rule making prior to the adoption of the final rules.

========================================================================

Federal Register / Vol. 80, No. 101 / Wednesday, May 27, 2015 /
Proposed Rules

DEPARTMENT OF TRANSPORTATION

Federal Aviation Administration

14 CFR Part 71

[Docket No. FAA-2014-1134; Airspace Docket No. 15-ANM-7]

Proposed Amendment of Class E Airspace; Chehalis, WA

AGENCY: Federal Aviation Administration (FAA), DOT.

ACTION: Notice of proposed rulemaking (NPRM).

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SUMMARY: This action proposes to modify Class E airspace extending
upward from 700 feet above the surface at Chehalis--Centralia Airport,
Chehalis, WA, to enhance the safety and management of Instrument Flight
Rules (IFR) operations for Standard Instrument Approach Procedures
(SIAPs) at the airport.

DATES: Comments must be received on or before July 13, 2015.

ADDRESSES: Send comments on this proposal to the U.S. Department of
Transportation, Docket Operations, M-30, West Building Ground Floor,
Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 20590;
telephone<PHONE_NUMBER>. You must identify FAA Docket No. FAA-2015-
1134; Airspace Docket No. 15-ANM-7, at the beginning of your comments.
You may also submit comments through the Internet at http://www.regulations.gov. You may review the public docket containing the
proposal, any comments received, and any final disposition in person in
the Dockets Office between 9:00 a.m. and 5:00 p.m., Monday through
Friday, except Federal holidays. The Docket Office (telephone 1-800-
647-5527), is on the ground floor of the building at the above address.
    FAA Order 7400.9Y, Airspace Designations and Reporting Points, and
subsequent amendments can be viewed online at http://www.faa.gov/air_traffic/publications/. The Order is also available for inspection
at the National Archives and Records Administration (NARA). For
information on the availability of this proposed incorporation by
reference material at NARA, call<PHONE_NUMBER>, or go to http://www.archives.gov/federal_register/code_of_federal-regulations/ibr_locations.html.
    FAA Order 7400.9, Airspace Designations and Reporting Points, is
published yearly and effective on September 15. For further
information, you can contact the Airspace Policy and Regulations Group,
Federal Aviation Administration, 800 Independence Avenue SW.,
Washington, DC 20591; telephone:<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Steve Haga, Federal Aviation
Administration, Operations Support Group, Western Service Center, 1601
Lind Avenue SW., Renton, WA 98057; telephone<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Comments Invited

    Interested parties are invited to participate in this proposed
rulemaking by submitting such written data, views, or arguments, as
they may desire. Comments that provide the factual basis supporting the
views and suggestions presented are particularly helpful in developing
reasoned regulatory decisions on the proposal. Comments are
specifically invited on the overall regulatory, aeronautical, economic,
environmental, and energy-related aspects of the proposal.
Communications should identify both docket numbers and be submitted in
triplicate to the address listed above. Commenters wishing the FAA to
acknowledge receipt of their comments on this notice must submit with
those comments a self-addressed, stamped postcard on which the
following statement is made: ``Comments to Docket No. FAA-2015-1134;
Airspace Docket No. 15-ANM-7.'' The postcard will be date/time stamped
and returned to the commenter.

Availability of NPRMs

    An electronic copy of this document may be downloaded through the
Internet at http://www.regulations.gov. Recently published rulemaking
documents can also be accessed through the FAA's Web page at http://www.faa.gov/airports_airtraffic/air_traffic/publications/airspace_amendments/.
    You may review the public docket containing the proposal, any
comments received, and any final disposition in person in the Dockets
Office (see the ADDRESSES section for the address and phone number)
between 9:00 a.m. and 5:00 p.m., Monday through Friday, except federal
holidays. An informal docket may also be examined during normal
business hours at the Northwest Mountain Regional Office of the Federal
Aviation Administration, Air Traffic Organization, Western Service
Center, Operations Support Group, 1601 Lind Avenue SW., Renton, WA
98057.
    Persons interested in being placed on a mailing list for future
NPRMs should contact the FAA's Office of Rulemaking,<PHONE_NUMBER>,
for a copy of Advisory Circular No. 11-2A, Notice of Proposed
Rulemaking Distribution System, which describes the application
procedure.

Availability and Summary of Documents Proposed for Incorporation by
Reference

    This document proposes to amend FAA Order 7400.9Y, Airspace
Designations and Reporting Points, dated August 6, 2014, and effective
September 15, 2014. FAA Order 7400.9Y is publicly available as listed
in the ADDRESSES section of this proposed rule. FAA Order 7400.9Y lists
Class A, B, C, D, and E airspace areas, air traffic service routes, and
reporting points.

The Proposal

    The FAA is proposing an amendment to Title 14 Code of Federal
Regulations (14 CFR) Part 71 by modifying Class E airspace extending
upward from 700 feet above the surface at Chehalis-Centralia Airport,
Chehalis, WA. After a review of the airspace, the FAA found
modification of the airspace necessary for the safety and management of
IFR operations for SIAPs at the airport. Class E airspace extending
upward from 700 feet above the surface would be modified to within a 4-
mile radius of Chehalis-Centralia Airport, with a segment extending
from the 4-mile radius to 8.1 miles north of the airport.
    Class E airspace designations are published in paragraph 6005 of
FAA Order 7400.9Y, dated August 6, 2014 and effective September 15,
2014, which is incorporated by reference in 14 CFR 71.1. The Class E
airspace designations

listed in this document will be published subsequently in the Order.
    The FAA has determined this proposed regulation only involves an
established body of technical regulations for which frequent and
routine amendments are necessary to keep them operationally current.
Therefore, this proposed regulation: (1) Is not a ``significant
regulatory action'' under Executive Order 12866; (2) is not a
``significant rule'' under DOT Regulatory Policies and Procedures (44
FR 11034; February 26, 1979); and (3) does not warrant preparation of a
regulatory evaluation as the anticipated impact is so minimal. Since
this is a routine matter that will only affect air traffic procedures
and air navigation, it is certified this proposed rule, when
promulgated, would not have a significant economic impact on a
substantial number of small entities under the criteria of the
Regulatory Flexibility Act.
    The FAA's authority to issue rules regarding aviation safety is
found in Title 49 of the U.S. Code. Subtitle 1, Section 106, describes
the authority for the FAA Administrator. Subtitle VII, Aviation
Programs, describes in more detail the scope of the agency's authority.
This rulemaking is promulgated under the authority described in
Subtitle VII, Part A, Subpart I, Section 40103. Under that section, the
FAA is charged with prescribing regulations to assign the use of the
airspace necessary to ensure the safety of aircraft and the efficient
use of airspace. This regulation is within the scope of that authority
as it would amend controlled airspace at Chehalis-Centralia Airport,
Chehalis, WA.

Environmental Review

    This proposal will be subject to an environmental analysis in
accordance with FAA Order 1050.1E, ``Environmental Impacts: Policies
and Procedures'' prior to any FAA final regulatory action.

List of Subjects in 14 CFR Part 71

    Airspace, Incorporation by reference, Navigation (air).

The Proposed Amendment

    Accordingly, pursuant to the authority delegated to me, the Federal
Aviation Administration proposes to amend 14 CFR part 71 as follows:

PART 71--DESIGNATION OF CLASS A, B, C, D, AND E AIRSPACE AREAS; AIR
TRAFFIC SERVICE ROUTES; AND REPORTING POINTS

0
1. The authority citation for 14 CFR part 71 continues to read as
follows:

    Authority:  49 U.S.C. 106(f), 106(g), 40103, 40113, 40120; E.O.
10854, 24 FR 9565, 3 CFR, 1959-1963 Comp., p. 389.

Sec.  71.1  [Amended]

0
2. The incorporation by reference in 14 CFR 71.1 of FAA Order 7400.9Y,
Airspace Designations and Reporting Points, dated August 6, 2014, and
effective September 15, 2014, is amended as follows:

Paragraph 6005 Class E Airspace areas extending upward from 700
feet or more above the surface of the earth.

* * * * *

ANM WA E5 Chehalis, WA [Modified]

Chehalis, Chehalis-Centralia Airport, WA
    (Lat. 46[deg]40'37'' N., long. 122[deg]58'58'' W.)

    That airspace extending upward from 700 feet above the surface
within a 4-mile radius of Chehalis-Centralia Airport, and within 1
mile each side of the 358[deg] bearing of the airport extending from
the 4-mile radius to 8.1 miles north of the airport.

    Issued in Seattle, Washington, on May 12, 2015.
Christopher Ramirez,
Acting Manager, Operations Support Group, Western Service Center.
[FR Doc. 2015-12570 Filed 5-26-15; 8:45 am]
 BILLING CODE 4910-13-P


[Federal Register Volume 84, Number 105 (Friday, May 31, 2019)]
[Notices]
[Pages 25256-25257]
[FR Doc No: 2019-11350]

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ENVIRONMENTAL PROTECTION AGENCY

[EPA-HQ-SFUND-2012-0104; FRL-9994-61-OMS]

Information Collection Request Submitted to OMB for Review and
Approval; Comment Request; Brownfields Program--Accomplishment
Reporting (Renewal)

AGENCY: Environmental Protection Agency (EPA).

ACTION: Notice.

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

SUMMARY: The Environmental Protection Agency (EPA) has submitted an
information collection request (ICR), Brownfields Program--
Accomplishment Reporting (EPA ICR Number 2104.07, OMB Control Number
2050-0192), to the Office of Management and Budget (OMB) for review and
approval in accordance with the Paperwork Reduction Act. This is a
proposed extension of the ICR, which is currently approved through July
31, 2019. Public comments were previously requested via the Federal
Register on February 8, 2019 during a 60-day comment period. This
notice allows for an additional 30 days for public comments. A fuller
description of the ICR is given below, including its estimated burden
and cost to the public. An agency may not conduct or sponsor and a
person is not required to respond to a collection of information unless
it displays a currently valid OMB control number.

DATES: Additional comments may be submitted on or before July 1, 2019.

ADDRESSES: Submit your comments, referencing Docket ID Number EPA-HQ-
SFUND-2012-0104, to (1) EPA online using www.regulations.gov (our
preferred method), by email to<EMAIL_ADDRESS>or by mail to:
EPA Docket Center, Environmental Protection Agency, Mail Code 28221T,
1200 Pennsylvania Ave. NW, Washington, DC 20460, and (2) OMB via email
to<EMAIL_ADDRESS>Address comments to OMB Desk Officer
for EPA.
    EPA's policy is that all comments received will be included in the
public docket without change including any personal information
provided, unless the comment includes profanity, threats, information
claimed to be Confidential Business Information (CBI) or other
information whose disclosure is restricted by statute.

FOR FURTHER INFORMATION CONTACT: Kelly Gorini, Office of Brownfields
and Land Revitalization, (5105T), Environmental Protection Agency, 1200
Pennsylvania Ave. NW, Washington, DC 20460; telephone number: (202)
566-1702; fax number:<PHONE_NUMBER>; email address:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Supporting documents, which explain in
detail the information that the EPA will be collecting, are available
in the public docket for this ICR. The docket can be viewed online at
www.regulations.gov or in person at the EPA Docket Center, WJC West,
Room 3334, 1301 Constitution Ave. NW, Washington, DC. The telephone
number for the Docket Center is<PHONE_NUMBER>. For additional
information about EPA's public docket, visit http://www.epa.gov/dockets.
    Abstract: This ICR covers the collection of information from those
organizations that receive cooperative agreements from EPA under the
authority of the Comprehensive Environmental Response, Compensation,
and Liability Act (CERCLA) as amended by the Brownfields Utilization,
Investment, and Local Development (BUILD) Act (Pub. L. 115-141).
CERCLA, as amended, authorizes EPA to award grants or cooperative
agreements to states, tribes, local governments, and other eligible
entities to support the assessment and cleanup of brownfields sites.
Under the Brownfields Amendments, a brownfields site means real
property, the expansion, redevelopment, or reuse of which may be
complicated by the presence or potential presence of a hazardous
substance, pollutant, or contaminant. For funding purposes, EPA uses
the term ``brownfields property(ies)'' synonymously with the term
``brownfields sites.'' The Brownfields Amendments authorize EPA to
award several types of cooperative agreements to eligible entities on a
competitive basis.
    Under subtitle A of the Small Business Liability Relief and
Brownfields Revitalization Act, states, tribes, local governments, and
other eligible entities can receive assessment cooperative agreements
to inventory, characterize, assess, and conduct planning and community
involvement related to brownfields properties; cleanup cooperative
agreements to carry out cleanup activities at brownfields properties;
multipurpose cooperative

agreements to conduct activities allowed under both assessment and
cleanup cooperative agreements; cooperative agreements to capitalize
revolving loan funds and provide subgrants for cleanup activities;
area-wide planning cooperative agreements to develop revitalization
plans for brownfields; and environmental workforce and development job
training and placement programs. Under subtitle C of the Small Business
Liability Relief and Brownfields Revitalization Act, states and tribes
can receive cooperative agreements to establish and enhance their
response programs through the four elements and meet the public record
requirements under the statute. Cooperative agreement recipients
(``recipients'') have general reporting and record keeping requirements
as a condition of their cooperative agreement that result in burden. A
portion of this reporting and record keeping burden is authorized under
2 CFR part 1500 and identified in the EPA's general grants ICR (OMB
Control Number 2030-0020). EPA requires Brownfields program recipients
to maintain and report additional information to EPA on the uses and
accomplishments associated with funded brownfields activities. EPA uses
several forms to assist recipients in reporting the information and to
ensure consistency of the information collected. EPA uses this
information to meet Federal stewardship responsibilities to manage and
track how program funds are being spent, to evaluate the performance of
the Brownfields Cleanup and Land Revitalization Program, to meet the
Agency's reporting requirements under the Government Performance
Results Act, and to report to Congress and other program stakeholders
on the status and accomplishments of the program.
    Form Numbers: 6200-03, 6200-04, 6200-14, 6200-17.
    Respondents/affected entities: State/local/tribal governments; Non-
Profits.
    Respondent's obligation to respond: Required to obtain or Retain
Benefits (2 CFR part 1500).
    Estimated number of respondents: 5,438 (total).
    Frequency of response: Bi-annual for subtitle C recipients;
quarterly for subtitle A recipients.
    Total estimated burden: 5,765 hours (per year). Burden is defined
at 5 CFR 1320.03(b).
    Total estimated cost: $667,181 (per year), includes $0 annualized
capital or operation & maintenance costs.
    Changes in the Estimates: There is an increase of 1,888 hours in
the total estimated respondent burden compared with the ICR currently
approved by OMB. This increase is partially the result of adding the
new Program Activity Levels Form for 128(a) recipients to fill out
annually. The remainder of the burden increase is the result of an
overall increase in wages and the large increase in the number of
responses submitted to ACRES annually due to more grants being awarded.
Even with this increase, respondents indicated that improvements in the
ACRES reporting system and increased familiarity with the program lead
to a lower burden per individual entry.

Courtney Kerwin,
Director, Regulatory Support Division.
[FR Doc. 2019-11350 Filed 5-30-19; 8:45 am]
BILLING CODE 6560-50-P